A Primer on Economics of Shale

8/20/2019 A Primer on Economics of Shale

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VOLUME 25 | NUMBER 4 | FALL 2013

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 Uni-versity 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 CorporateRisk Management on Capital Structure Decisions

97 Julita M. Bock, Otto von Guericke University

APPLIED CORPORATE FINANCEJournal of


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Journal of Applied Corporate Finance • Volume 25 Number 4 Fall 2013 87

A Primer on the Economics of Shale Gas Production

Just How Cheap is Shale Gas?

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. Respon-sibility for any remaining errors, however, is ours.

2. The American Energy Outlook (published by the U.S. Energy Information Adminis-tration or EIA) estimated total US recoverable US shale gas resources in 2009 to be269.3 trillion cubic feet, increased its estimate to 317 trillion cubic feet in 2010 andthen doubled that again for 2011 ( http://www.eia.doe.gov/forecasts/aeo /). The EIA alsoincreased its estimates of worldwide recoverable shale gas volumes from 6,622 TCF in2011 to 7,299 in 2013. Over the same time frame the worldwide recoverable tight oilreserves increased from 32 million barrels to 345 million. (http://www.eia.gov/analysis/ 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 Ber-man, staff member of The Oil Drum ( http://www.theoildrum.com ), questions whethershale 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 muchmore attractive.

6. Although fracking has been around since the 1940’s its use has increased signi -cantly since 2000 and become a focus of intense media scrutiny. Fracking uid is 99.5%sand and water and most of the injected water is later extracted during production. Thereis always some risk, however, of ground water contamination, and objections to moretraf c and noise r elated to drilling. See John Walton and Arturo Woocay, “EnvironmentalIssues 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. Al-though not as large geographically as the Marcellus shale which covers 95,000 squaremiles, it has almost as much gas: an estimated 251 trillion cubic feet (Tcf) compared tojust 262 Tcf for the much larger Marcellus shale.

B

by Larry W. Lake, University of Texas; John Martin, Baylor University; J. DouglasRamsey, EXCO Resources, Inc.; and Sheridan Titman, University of Texas 1

The U.S. government doubled its estimate of thecountry’s economically recoverable natural gasreserves between 2009 and 2011.2 Tis increaseis directly related to unconventional gas, specif-

ically gas held in shale formations that are now recoverableusing horizontal drilling and hydraulic fracturing (i.e.,“fracking”) techniques developed in the last decade. More-over, the promise of unconventional gas and oil resourceshas led some to predict that “the U.S. will be the top globaloil and gas producer, surpassing Russia and Saudi Arabia.”3 Others caution that overly optimistic estimates of shale gasreserves combined with low gas prices may keep shale gasfrom becoming the game changer many believe it will be.4 Specically, there are three big issues that arise with respectto the production of natural gas from shale:5

• First, traditional methods used to estimate gasreserves may overstate recoverable shale gas reserves. Sincethe horizontal drilling and fracturing methods used to extract

gas from shale formations is relatively new (often less than5 years old), analysts have limited experience to draw upon when trying to estimate the volume of technically recoverablereserves. Moreover, production experience suggests that theproduction rate from shale wells declines much more rapidlythan production from vertical gas wells.

• Second, the economic viability of producing shalegas has been questioned . Extracting natural gas from shaleformations is both difficult and expensive. It requires horizon-tal drilling and fracturing of formations using large quantitiesof water. It is difficult to forecast the long-term productionof shale gas wells. Te productive life of shale gas may be

very short with roughly 70% of available reserves extracted

in the rst year of production. Tis means that a depend-able supply of natural gas from shale formations requires asustained program of drilling, completion, and exploration.

• Finally, there are serious environmental concernsabout the production of shale gas . Te drilling techniquesused to extract shale gas require large volumes of water andsome chemicals that could result in ground water contamina-tion. Potential environmental costs could seriously erode theeconomic viability of producing gas from shale formations. 6

Ultimately all of these concerns impact the economicsof shale gas production. If shale gas reserves have been over-estimated then this will result in reduced production andpossibly higher gas prices. Environmental concerns will likelylead to regulatory changes that result in increased costs ofextracting shale gas.

In this paper we rst develop a base case model to evalu-ate the economic viability of producing natural gas from shaleformations. o construct our base model we use data from a

shale gas well in the Haynesville shale region of North Louisi-ana.7 Our analysis explores the valuation of the predicted gasvolumes from that well using estimated production costs forthe region in conjunction with estimated natural gas prices.o generalize the model we use both sensitivity analyses of the

key value drivers, as well as simulation analysis. We nd mostshale gas wells are protable under the assumed conditions ofour model data. However, the key driver of NPV is the priceof natural gas, which at the time of this writing is very nearlyequal to breakeven levels (assuming the current method usedto estimate production volume is correct).

Te conventional view of a hydrocarbon accumulation

is that three things are required: a source rock, a reservoir,


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88 Journal of Applied Corporate Finance • Volume 25 Number 4 Fall 2013

8. This is a bit of an oversimpli cation for even with conventional wells the operatormight choose to frack the well after drilling should the well not ow. Thus, conventionalwells offer the operator the option to complete the well which may include fracking. Incontrast, 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

such as natural gas which in the State of Louisiana is $0.0331 per Mcf. The ad valoremtax is a tax levied on the difference between the price of natural gas and the cost ofproduction. In Louisiana this tax is levied for each well as follows: In the rst year the taxis $955 per month. In years two through twenty the tax declines by 4% per year and forall years thereafter it is equal to the year 20 total.

much higher than in conventional wells that seek out smallerreservoirs. Tis means that the opportunity to make add-oninvestments is greater for shale gas wells than conventional wells.

VII. Exploration costs . he vastness of shale forma-tions means that there is little discovery risk and few wells areabsolutely unproductive. Tese differences indicate that theeconomics of extracting shale gas can be quite different thanthat of extracting conventional gas deposits. Te rst ve differ-ences tend to decrease the value of shale gas in comparison withconventional formations but the last two favor shale very much.

We built a model for a specic shale gas well found inthe Haynesville shale region of North Central Louisiana(Haynesville #1). Te key elements are the production declinecurve forecast for the well, the cost of drilling and completingthe 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 produc-tion to replicate a wide range of conditions encountered acrossdifferent regions of the country. We rst calibrated our basemodel to the actual Haynesville shale conditions and thenvary the key value drivers.

Panel A of able 1 contains the original data estimatesfor the Haynesville #1 well. Tis data is from a single welland not the entire resource play. In year 0 the well calls for aninvestment of $1,912,500 which equals the owner’s 15.75% working interest in the well multiplied by the total drillingand completion costs.

Beginning in year 1 the annual cash ows from the

example gas well are calculated as follows:

(1)

Net GasProduction

(mcf)

Price of Natural Gas

per mcf – – –

Total NetOperatingExpenses

Severance & Ad Valorem

Expenses

Depletion Allowance

1- CorporateIncome Tax Rate

+ Depletion Allowance

Net gas production is equal to the owner’s proportionate

working interest in the well revenues (15.75%) multiplied bythe estimated gross annual gas production. otal net operat-ing expenses include the owner’s share of the cash expensesrequired to extract, transport and sell the gas production

from the well. Severance and Ad Valorem expenses are taxesimposed on gas producers and the depletion allowance is anon-cash expense available to gas producers to reect thedepletion of the asset represented by the well.9

Energy rms have sometimes computed return on invest-ments in gas wells on a before corporate tax basis. Tis practicearose, in part, because their investments were often unprof-itable. Tis has been much less true recently. For example,Chesapeake Energy paid average tax rates of 38% and 39%

and a seal. Hydrocarbons are generated in the source rock,usually organic-rich shale, by slow cooking over hundredsof thousands of years. Once converted, hydrocarbons areexpelled from the source and migrate upwards until encoun-tering and being trapped by the seal. Te goal of conventionalexploration was to nd the seal. Te actual location of thesource rock was unimportant; sometimes it was hundreds ofkilometers away from the reservoir, and for many conven-tional 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. Andthe hydrocarbons were not hydrocarbons in the usual sense;they were only precursors to hydrocarbons.

Tat was the conventional view. We now know thatsource rocks contain a good deal of hydrocarbon itself,especially natural gas, not just its precursor. Source rocks areessentially impermeable however, but we can deal with this bybrutalizing the rock through horizontal drilling and fractur-ing (often referred to as fracking). Interestingly it remainstrue that source rocks are abundant.

Te economics of conventional natural gas productiondiffers from unconventional shale gas in several ways:

I. Total production volumes —a conventional gas wellmight 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 conven-

tional wells, especially in the initial production period.III. Production methods —shale gas is trapped in rockformations that must be fractured before the gas can ow.Fracturing, which involves injecting water and sand at highpressure into the formation, is expensive and may entailenvironmental risks.

IV. Horizontal wells —shale gas production typically useshorizontal drilling whereas conventional gas wells are drilledusing vertical wells.

V. Completion after drilling —these wells must befractured before the viability of producing the well can bedetermined. Tis means that the decision to drill the well is

tantamount to a commitment to complete the well. Tis isdifferent than a conventional gas well in which a drilling log andpressure measurements can be used to estimate the volume ofrecoverable reserves before the well is completed.8 If the well isdeemed uneconomic it can be plugged and abandoned therebyavoiding completion expenses.

VI. Follow on investments —since shale formations aretypically very large, the probability of success of follow on wells (in what is commonly referred to as the resource play) is


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89Journal of Applied Corporate Finance • Volume 25 Number 4 Fall 2013

Table 1 Base Case Model for Haynesville #1

Panel A Cash ow estimates

Date Period EstimatedGross Gas

(Mcf)

Estimated NetGas

(15.75% ofGross Gas)

(Mcf)

Price ofNatural Gas/

Mcf

EstimatedTotal NetRevenue

EstimatedTotal NetOperatingExpense

EstimatedSeverance &Ad Valorem

Expense

EstimatedDepletionAllowance

EstimatedEquity

Investment

EstimatedAfter-tax NetCash Flow

Dec-09 0 $(1,912,500) $(1,912,500)

Dec-10 1 2,405,443.0 378,857.3 $4.50 $1,704,858 $(13,568) $(1,908) $(483,695) 1,327,676

Dec-11 2 773,147.5 121,770.7 4.50 547,968 (11,833) (36,625) $(155,467) 396,298

Dec-12 3 474,995.6 74,811.8 4.50 336,653 (9,747) (25,794) $(95,514) 239,432

Dec-13 4 343,838.1 54,154.5 4.50 243,695 (9,747) (19,644) $(69,140) 170,755

Dec-14 5 269,659.5 42,471.4 4.50 191,121 (9,747) (15,791) $(54,224) 132,176

Dec-15 6 221,876.7 34,945.6 4.50 157,255 (9,747) (13,165) $(44,616) 107,425

Dec-16 7 188,506.2 29,689.7 4.50 133,604 (9,747) (11,265) $(37,906) 90,186

Dec-17 8 163,873.9 25,810.1 4.50 116,146 (9,747) (9,827) $(32,952) 77,486

Dec-18 9 144,941.4 22,828.3 4.50 102,727 (9,747) (8,701) $(29,145) 67,739

Dec-19 10 129,934.0 20,464.6 4.50 92,091 (9,747) (7,797) $(26,128) 60,021

Dec-20 11 117,744.9 18,544.8 4.50 83,452 (9,747) (7,054) $(23,677) 53,759

Dec-21 12 107,647.8 16,954.5 4.50 76,295 (9,747) (6,433) $(21,646) 48,575

Dec-22 13 99,146.5 15,615.6 4.50 70,270 (9,747) (5,906) $(19,937) 44,213

Dec-23 14 91,890.3 14,472.7 4.50 65,127 (9,747) (5,454) $(18,478) 40,492

Dec-24 15 85,870.8 13,524.7 4.50 60,861 (9,747) (5,076) $(17,267) 37,406

Dec-25 16 80,858.5 12,735.2 4.50 57,308 (9,747) (4,761) $(16,259) 34,838

Dec-26 17 76,149.7 11,993.6 4.50 53,971 (9,747) (4,463) $(15,312) 32,426

Dec-27 18 71,715.1 11,295.1 4.50 50,828 (9,747) (4,182) $(14,421) 30,155

Dec-28 19 67,538.7 10,637.3 4.50 47,868 (9,747) (3,916) $(13,581) 28,017

Dec-29 20 63,605.6 10,017.9 4.50 45,080 (9,747) (3,665) $(12,790) 26,005

Dec-30 21 59,901.5 9,434.5 4.50 42,455 (9,747) (3,428) $(12,045) 24,109

Dec-31 22 56,413.1 8,885.1 4.50 39,983 (9,747) (3,204) $(11,344) 22,325

Dec-32 23 53,127.8 8,367.6 4.50 37,654 (9,747) (2,993) $(10,683) 20,645

Dec-33 24 50,033.9 7,880.3 4.50 35,462 (9,747) (2,793) $(10,061) 19,063

Dec-34 25 47,120.2 7,421.4 4.50 33,396 (9,747) (2,605) $(9,475) 17,574

Dec-35 26 44,376.1 6,989.2 4.50 31,452 (9,747) (2,427) $(8,923) 16,171

Dec-36 27 41,791.8 6,582.2 4.50 29,620 (9,747) (2,259) $(8,404) 14,851

Dec-37 28 39,358.1 6,198.9 4.50 27,895 (9,747) (2,101) $(7,914) 13,607

Dec-38 29 37,066.0 5,837.9 4.50 26,271 (9,747) (1,952) $(7,453) 12,436

Dec-39 30 34,907.5 5,497.9 4.50 24,741 (9,747) (1,811) $(7,019) 11,334

Dec-40 31 32,874.6 5,177.8 4.50 23,300 (9,747) (1,678) $(6,611) 10,296

Dec-41 32 30,960.1 4,876.2 4.50 21,943 (9,747) (1,553) $(6,226) 9,318

Dec-42 33 29,157.2 4,592.3 4.50 20,665 (9,747) (1,434) $(5,863) 8,398

Dec-43 34 27,459.2 4,324.8 4.50 19,462 (9,747) (1,323) $(5,522) 7,531

Dec-44 35 25,860.1 4,073.0 4.50 18,328 (9,747) (1,218) $(5,200) 6,714

Dec-45 36 24,354.1 3,835.8 4.50 17,261 (9,747) (1,119) $(4,897) 5,946

Dec-46 37 22,935.8 3,612.4 4.50 16,256 (9,747) (1,025) $(4,612) 5,222

Dec-47 38 21,600.2 3,402.0 4.50 15,309 (9,747) (937) $(4,343) 4,540

Panel B Project Valuation (Cost of capital = 10%)

Corporate Tax Rate, % 30 0

NPV, $ 309,201 893,995

IRR, % 16.47 30.86


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10. Based on a study published in April 2009 and prepared for the U.S. Departmentof Energy Of ce of Fossil Energy and National Energy Technology Laboratory titled “Mod -ern Shale Gas Development in the United States: A Primer”, p. 17.

11 Larry Benedetto, “Unconventional Gas and its Impact on Domestic Supply,” a re-port issued by Howard Weil ( http://www.ocsbbs.com/hottopics/2008/PLANO_Larry_May2008.pdf )

12. This is the cost estimate of our example well. However, the average cost of shalewells in the Haynesville shale has been reported to be somewhat higher. In 2010 bothPetrohawk (HK) (Enercom Oil & Gas Conference: August 24, 2010) and EXCO (XCO)(Fourth Quarter and Full Year 2009 Review: February 2010) reported an average cost oftheir 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 andthat J.J. Arps later expounded upon. See R. E. Allen, “Control of California Oil Curtail-

ment,” Trans. A.I.M.E., 92, 47, 1931 and J. J. Arps, “Estimation of Primary Oil Re-serves” in Petroleum Transactions , AIME, Vol. 207, 1956.

14. The method we use to estimate production volumes follows industry practice;however, new methods have been proposed that claim to improve the accuracy of vol-ume projections. These include the one mentioned in the M.S. thesis of A.J. Clark. SeeA. J. Clark, “Decline Curve Analysis in Unconventional Resource Plays using LogisticGrowth 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,” SPE144790, presented at the 2011 Annual Technical Conference and Exhibition of the So-ciety of Petroleum Engineers, Denver, Colorado; and Peter Valko and W. John Lee, “ABetter Way to Forecast Production from Unconventional Gas Wells,” SPE134231, pre-sented at the 2010 E Annual Technical Conference and Exhibition of the Society of Pe-troleum Engineers, Florence, Italy.

completing the well is not as valuable for a shale gas well asit is for a conventional gas well.

In a typical shale gas well in the US, the investor willhave a complete working interest. A working interest less than100% can represent an attempt to diversify risk exposureor 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 royaltyowners do not share the expenses.

Gas well revenues are a function of two key variables:Te price per thousand cubic feet (Mcf) of natural gas sold,and the volume of gas produced. We will assume that theprice of natural gas is xed at $4.50/Mcf over the life of theinvestment just as was done by the investor in the example well described in able 1. Although gas prices can uctuate widely, it is common practice to use rolling, forward contractsdated out to ve years to hedge price risk. Te ve-year gasprice assumption should reect forward market prices at thetime of evaluation since that is what can be hedged.

he second key variable is the volume of gas it willproduce. Te common methods used to estimate oil and gasreserves rely on an empirical extrapolation based on physicalcharacteristics of the reservoir. Over sixty years ago, J.J. Arpsdened a set of empirical production decline curves based onthe following hyperbolic function:13

qt= qi(1+nD it)–– 1n (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 twoconstants (the former is the initial rate of decline in produc-tion and n is the rate of change inD i over time); and t is thetime period for which production is being estimated. Te Appendix discusses the particulars of applying the hyperbolicdecline curve to production estimates found in Panel A of

able 1.14 Te production estimates for Haynesville #1 are based

on a combination of two types of production decline curves:Initially production declines based on a hyperbolic declinecurve 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 therst year;

in 2010 and 2011 respectively. We believe our assumption ofa 30% corporate tax rate is a conservative one.

Panel B of able 1 contains the estimated net present value(NPV) and internal rate of return (IRR) for the well. Te NPVis $309,201 and the IRR 16.47%, which exceeds the 10% costof capital used in the analysis. If one were to assume a zerotax rate, the NPV would be $893,995 and the IRR 30.86%.Obviously, the tax assumption will have a very large impacton the reported results.

able 2 presents the results of the model’s forecast of thecash ow found in the Haynesville #1 well described in able1. Tere are three basic components that must be modeledto evaluate an investment in a shale gas well: Drilling andcompletion costs, gas revenues, and operating costs. Let’sconsider each in turn.

Drilling costs are directly related to the depth of the shaleformation and the number of fractures or “fracks” used toprovide a permeable path for the gas to ow through thetight shale formation. Te number of fracks in the pay zonetends to be 8-10 for most wells. However, the depth of theshale formation varies from one shale area to another. Forexample, the depth of the shale formation in the Haynesvilleregion is 10,000-13,500 feet whereas in the Fayetteville shalethe formations are 1,000-7,000 feet and in the New Albanyshale, the wells can be as shallow as 500 feet.10 o illustratethe range of drilling costs, the cost of drilling and completinga well in the Woodford shale (Oklahoma), where the shaleis 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 theHaynesville shale is estimated to be $9.5 million.12 Te cost ofHaynesville #1, however, was slightly lower than the averageat $8.5 million. Note that drilling costs change from monthto month and also vary by location. Te cost of drilling the well is approximately 60% of this total and completion costsmake up the remaining 40%. For conventional gas wells theoperator has a valuable option to shut-in the well if measure-ments taken during drilling indicate it will be uneconomic.Consequently, the division between drilling and complet-ing costs is very important. With shale wells, however, theproductivity of a shale gas deposit cannot be known until

after the well has been fractured and this entails incurringthe bulk of the costs of completing the well. Consequently,the option to shut-in the well prior to incurring the costs of


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15. The slope term, n, being equal to one indicates that the hyperbolic decline func-tion reduces to the special case of a harmonic decline function, which is discussed in theappendix.

16. Given the relatively brief time that horizontal, hydraulically fractured gas wellshave been producing, the productive life of these wells is still unknown. Although con-ventional wells have produced for 30 years and longer, the initial evidence from theBarnett Shale is that the average productive life of a well is 7.5 years and the early evi-dence from the Marcellus suggests its wells also might have similar (short) lifespans (seewww.marcellus-shale.us/Marcellus-production.htm ). A short life span does not meanthese wells are not economic, but to be pro table the volumes of initial production haveto carry the investment.

17. This switch to the exponential decline function is important because a hyperboliccurve with value of n greater than one implies an in nite recovery amount, (i.e., com -monly referred to as the well’s estimated ultimate recovery or EUR).

18. Although we report actual production volumes on the vertical axis, engineerstypically report log production. This practice probably arose out of the convenience wherean exponential production decline function was used and the log transformation resultedin 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 ofrevenue method. The cost method, which we use, bases the allowance on the originalcost 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 revenuesmethod is not tied to the original cost of the well such that the total depletion for a wellis not limited to the original investment in the well using this method. The percent ofrevenue method can be used by an independent producer or royalty owner. However,certain re ners and certain retailers and transferees of proven oil and gas proper ties can -not claim percentage depletion. We use cost depletion to be conservative.

model total net operating expenses as a percent of revenuesfor the rst three years followed by a xed dollar amount foryears four and beyond that is equal to the year three expense.Te percentages of revenues used in the analysis are consis-tent with actual estimates for the example well whose dataprovides the basis for our model.

We combine severance and ad valorem taxes and modelthem as a quadratic function of net gas revenues as shown

in Figure 2. Te t of the relationship to the data providedfor Haynesville #1 was nearly perfect. Tis is unsurprisingas these taxes are a function of revenues that are estimatedusing the production data provided to us for Haynesville #1.Te production estimates were made using the productiontechnique described in the Appendix. In 2010 the sum ofthese taxes is much smaller than in subsequent years becausein Louisiana, where Haynesville #1 is located, there is noseverance tax for the rst year’s production.

Te depletion allowance is like depreciation expense inthat it represents the allocation of the cost of drilling andcompleting the gas well against revenues over the life of the

well. For modeling purposes we use cost depletion expenseper unit of production for the year multiplied by the totalamount of gas produced.19

and n (the rate of change inD i ) = 1.0.¹Te production decline curve switches to an exponential

decline when the annual rate of decline in production falls to7% at which time the decline function switches to the follow-ing exponential function with a rate of decline of 6%, i.e.,16

qt=qt-1e–.06

Te switch from the hyperbolic to the exponential decline

function occurs between years 13 and 14 for Haynesville #1.17Figure 1 contains the estimated production volumes for2010 through 2047.18 Note the initial steep production ratedecline as noted above. Using estimates based on this hyper-bolic decline curve in the model we can later consider theeffects of deviations from the estimated parameters on thevalue of the shale gas well.

Multiplying the annual production volumes by the $4.50/Mcf price for natural gas provides an estimate of the grossgas revenues from the well. Adjusting these estimates for the working interest of the investor produces the net gas revenue.

Tere are three categories of annual operating expenses

(see Equation 1). Tese are otal Net Operating Expense;Severance and Ad Valorem Expense; and Depletion Allow-ance. Based on the estimates provided for Haynesville #1 we

Figure 1 Estimated Gross Gas Production (Mcf/year) for Haynesville #1.

y = 2,015,779.16x -1.19

R = 0.99

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

0 5 10 15 20 25 30 35 40

Annual Production Estimates

G r o s s

G a s

P r o

d u c t

i o n

( M c f

/ Y e a r )

Production function switches fromhyperbolic to exponential betweenyears 13 and 14


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20. Recall that the production decline function used to model Haynesville #1 is ahybrid model containing a mixture of a hyperbolic and exponential function. In the sen-sitivity 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 exponen-tial 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 declinecurve equation. This variable determines the rate of change in the annual decline rate inproduction and was designated by n. When we evaluated the sensitivity of NPV to thisvariable 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 othervariables constant so that estimates of this variable are important even though in thisexample 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 con-verts 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 petroleumengineering profession in 2010 regarding the amount of natural gas that will ultimatelybe recovered from shale formations and at what cost. See “Debate over Shale Gas De-cline Fires Up,” FT.com (October 10, 2010).

Table 3 Sensitivity Analysis of the Production Estimate Parameter Original

ParameterEstimate

Break-evenParameter

Value

PercentChange inParameter

Value

PercentChange inEstimatedUltimateRecovery

(EUR)

InitialProductionRate ( qi)

19,500 Mcf/ day

16,551 Mcf/ day

-15.12% -15.12%

Initial Decline

in Productionin Year 1 ( Di)

85% 87.7% 3.15% -13.2%

Clearly, the NPV of the project is very sensitive to produc-tion volumes. An increase in the initial rate of decline inproduction for year one from 85% to 87.7% (an increase of just 3.15%) leads to a zero NPV estimate. Furthermore, adrop of 15.12% in the initial rate of production from 19,500Mcf/day to 16,551 Mcf/day can also result in a zero NPV.21

Although we have used the same hyperbolic declinefunction (as in equation 2) widely used with conventionalgas wells,22 to estimate the output of our shale gas well, we

do not yet know whether this or some other function is moreappropriate for unconventional shale gas wells. Some geosci-entists suggest that a more rapid exponential function wouldbe more appropriate. Only time will tell as we gain moreproduction experience.23

able 2 shows the NPV and IRR generated by the model.Te model estimates are very close to the calculated values forNPV and IRR found when using the original data suppliedfor the project. As we estimate drilling plus completion coststotal $1,912,500, our share of the 16.17% increase in thesecosts would reduce the NPV to zero.

Table 2 Summary Measures for the Original Data andModel of Haynesville #1

Original Data Estimates Model Estimates

NPV, $308,222

309,201

IRR, %16.45

16.47

Te well’s NPV is sensitive to two key parameters of thehyperbolic production decline curve found in equation (2).Tese are the initial production rate and the initial declinein production for year 1.20 able 3 shows how much eachof the two parameters would have to change to reduce theNPV to zero.

Figure 2 Actual and Estimated Severance and Ad Valorem Expenses.

Equation in the gure is for the t ted line.

y = 0.00x 2 - 0.13x - 1,654.88

R = 0.99

100,000 200,000 300,000 400,000 500,000 600,000

S e v e r a n c e

& A d V a

l o r e m

T a x e s

Net Gas Revenues

(40,000)

(35,000)

(30,000)

(25,000)

(20,000)

(15,000)

(10,000)

(5,000)

0

2


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24. See the appendix for a description of the method used to calculate q i25. 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 ofchange 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,” CommoditiesNow, (March 2001), 74-80.

26. The simulated value of the mean NPV and the original estimate diverged becauseof skewness in the probability distributions used in the simulation.

27. For an excellent overview of the use of option pricing analysis to evaluating oil andgas investments, see J. McCormack, Raoul LeBlanc, and Craig Heiser, “Turning Risk intoShareholder 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, pages437-439 of “ Valuation: The Art and Science of Corporate Investment Decisions 2 nd edition,” (Upper Saddle River, NJ: Prentice Hall, 2011).

Producers often use a gas price assumption that matchesthe forward prices at which the rms could actually hedgefuture price risk (i.e., enter into forward contracts to sell gas).However, production for Haynesville #1 is estimated out 38years, which is far beyond any rm’s ability to lock in gasprices such that the rm is subjected to price risk.

o model natural gas prices, we use a geometric Brown-ian motion model25 that has two parameters: the mean rateof change and standard deviation in the rate of change in gasprices (volatility). We assume that the mean rate of changein future gas prices is zero and the annual volatility in future

gas price changes is modeled using a triangular distributionusing an assumed minimum value of .05, most likely valueequal to .10, and maximum value of .30.

Figure 3 shows frequency distributions for the NPV of theshale gas well. Te expected NPV is $267,776 but the proba-bility of a NPV of zero or greater is 60.13%, meaning thereis a 39.87% probability that the well will produce a negativeNPV. Tis estimate of project NPV is about $40,000 lowerthan the earlier deterministic estimate. Te earlier estimate,however, corresponds to the results from one particular gas well in the Haynesville shale, whereas we have, through theengineer’s experience, modeled the experience of several wells

throughout the entire area.26

It has long been recognized that oil and gas productiontypically offers valuable real options to the developer.27 Teseoptions can be thought of in terms of options that exist beforea shale gas drilling project has been launched and options thatarise after the investment launch.28

We assumed a constant natural gas price for all futureperiods equal to $4.50 per Mcf. Should gas prices drop15.66% to an average of $3.80, the NPV of the well fallsbelow zero. Historically, gas prices have been volatile. Teaverage annual per Mcf well-head price of natural gas was$4.00 in 2001 but rose to more than $10.00 in 2008 andthen collapsed to $3.60 in October 2013.

Although the sensitivity analysis provides some indicationof the range of outcomes, it says little about the probabilitiesof extreme outcomes. o gain insight into possible extremeoutcomes we used Monte Carlo simulation. We chose thetriangular distribution to model uncertainty in the threekey production function variables (the initial productionrate (q i ), the initial decline in production experienced in therst year of production (D i ), and the slope coefficient thatdetermines the change in the rate of decline in production(n)). Te triangular distribution offers exibility in model-ing a wide variety of outcomes. Knowledgeable engineersand management personnel easily understand its parameters(minimum, most-likely, and maximum) and they can readilyprovide estimates. able 4 contains the values used to denethe distributions for each of these parameters.

Table 4 Parameter Estimates for the ProductionFunction Variables

Parameter Minimum Value Most-Likely Value Maximum Value

Initial ProductionRate (Mcf/day) ( qi)

4,053 19,500 31,616

Initial Decline inProduction in Year 1(Di), %

76.5 85 93.5

Slope Coef cient ( n) 0.50 1.0 1.5

Te parameter estimates for the initial production rate(q i ) are based upon a conversation with the chief reservoirengineer for the Haynesville gas well. He indicated that theinitial year of production for wells such as ours could be assmall as 500,000 Mcf (0.5 Bcf) or as large as 3,900,000Mcf (3.9 Bcf) although the most likely level of productionis roughly 2,500,000 Mcf (2.5 Bcf). Tese annual produc-

tion estimates correspond to the three daily productionestimates found in able 4 for the minimum, most likely, andmaximum values.24 For the distribution around the initialdecline in production in year one, we assumed maximumsand minimums that were 10% larger and smaller than themost likely value.

Figure 3 Frequency Distribution of NPV


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29. See J. McCormack and Gordon Sick, “Valuing PUD Reserves: A Practical Applica-tion of Real Option Techniques,” Journal of Applied Corporate Finance , 13, 4 (Winter2001), 110-115.

30. Some shale plays, such as the Haynesville shale, produce only dry gas, whereasthe northern most region of the Eagle Ford Shale in South Texas produces oil, the middleregion produces wet gas (some liquids) and the southernmost region is dry gas only.

of the timing option. However, researchers have not foundevidence of a strong association between drilling costs andthe price of oil and gas.29

Finally, exercising a timing option in a shale gas playis made difficult by virtue of the fact that it involves thecoordination of multiple outside contractors including drill-ing contractors and companies that provide fracking services.Since it can be very difficult to move drilling and frackingrigs around the country in a timely way, this friction (and itsassociated cost) diminishes the value of the timing option.

Operating options refer to the potential to design a drill-ing and production program in such a way as to provide therm with the exibility to respond to changing economiccircumstances. For example, the development of drill-ing pads for drilling multiple shale gas wells from a singlelocation can dramatically reduce the cost of drilling out alease when compared to conventional drilling methods.

Once a gas well has been drilled there are a host of differ-ent sources of operating exibility or options available tothe operator of the well. Some of the more important typesof options include growth options, shutdown options, andabandonment options.

Because the areas covered by shale formations are solarge, shale gas investments offer a potentially valuable optionto extend production once a viable well has been developed.Tis is due to the high probability of successful wells in theimmediate vicinity of a successful well. Tis 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 anoption to select the site that is most advantageous at thetime of the drilling. For the most part, the selection is deter-mined by the mix of hydrocarbons at the potential sites andthe price of those hydrocarbon resources at the time of thedrilling.

Shale formations not only yield dry gas but often producehydrocarbon liquids, so called rich gas or gas condensates, as well as oil. Depending on where you drill, you will produce amix that may be almost exclusively dry gas, or may be almostexclusively liquids. Hence, once the play has been explored

and liquid rich areas identied, the developer has the optionto choose specic sites depending on the relative prices of thevarious hydrocarbon liquids and gas that will be produced.30

Te source of value to this option arises from the volatil-ity of the market price difference between hydrocarbonliquids and gas. In recent history this difference has beenquite volatile, and currently, the market price of the liquidsis quite high relative to the gas. For example, the energyequivalent of 1 barrel of hydrocarbon liquids is about 7 Mcfgas. Using this gure and $5.3/Mcf, the price of 1 barrel of

Prior to drilling, both conventional and shale gas wellspossess three fundamental types of options: staged investmentoptions, timing options, and operating options. However,there are differences in value between the options attachedto conventional and shale gas wells.

Oil and gas drilling programs provide classic examplesof staged investment options. Initial exploratory wells deter-mine the potential of an investment play before full drill outand production commences. Te sheer size of shale forma-tions make the likelihood of successful follow-on wells quitevaluable. For example, the Marcellus shale formation coversan area of more than 90,000 square miles. Once a productivesite has been identied, multiple horizontal wells are oftendrilled from the same site going out in different directionsinto the shale formation.

iming options arise out of the legal right to postpone aninvestment in order to maximize value. Both conventionaland shale gas well investment options involve nite term drill-ing leases that typically extend for three years. If the energyrm fails to drill within this three-year window, its lease with the land-owner lapses. So there is substantial pressureon the lessee to do at least minimal exploration in order to“hold” the lease to enjoy the opportunity to fully develop aproperty at some date. But the full production potential ofthe property does not have to be exploited in the initial leaseperiod. Once some minimal level of success has been estab-lished then the option to defer or delay investing in drillingout the property is fully available to both the conventional

and shale gas producer.Because shale gas wells produce high volumes in the rstyear and because they usually also present extensive follow-on drilling opportunities, they may possess an importanttiming option not possessed by conventional wells. Tat is,shale gas producers may have the ability to time the drillingof shale gas wells in response to short-term price movementsfor natural gas. Te key determinants of the timing optionare the cost of drilling and completing the shale gas well,the likelihood of success, and the volatility of gas prices. Ina world of highly volatile natural gas prices the option todevelop 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.Tis analogy is very similar to the use of electric generation“peaker” plants that can be switched on and off in responseto price spikes for power.

Note, however, that the value of the timing option isdiminished if dril ling costs are positively correlated withthe price of natural gas. If a high gas price results in a highdemand to drill gas wells, and this leads to an increase in therates charged for drilling rigs, this would reduce the value


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31. We are grateful to John McCormack for pointing out this second type of shut-inoption to us. See J. McCormack and Gordon Sick, “Valuing PUD Reserves: A PracticalApplication of Real Option Techniques,” Journal of Applied Corporate Finance , 13, 4(Winter 2001), 110-115.

its relative infancy, and it remains to be seen whether theproduction curves of these wells will follow this path. Recog-nizing this, we used different parameter estimates for theproduction decline curve. Finally, the price path of naturalgas is modeled using a simple diffusion process that does notattempt to incorporate the possibility of shifts in price pathsbecause of major changes in either the supply of, or demandfor, natural gas.

ConclusionBreakthroughs in shale gas extraction techniques such ashorizontal drilling and fracturing (“fracking”) have dramat-ically increased estimates of recoverable gas reserves in theUS. Although some observers have concluded from this thatthe US will enjoy great supplies of low-priced gas for a long-time to come, others are not so sure.

Te model of US shale gas drilling economics and NPVsimulations presented here indicate that shale gas exploitationis probably sustainable (with a 60% likelihood) but majorquestions remain. NPVs are highly sensitive to gas priceassumptions and projected production volumes. Te base caseassumes the current gas futures price curve, but a fall in price of just 17% along that curve would reduce the well NPV to zero.

Te model uses standard engineering assumptions aboutconventional wells for the relationship between rst yearproduction declines and subsequent production. Althoughit is clear that production from shale wells declines fasterthan from conventional wells, engineers have too little history

to forecast ultimate production from shale wells with greatcondence.Nevertheless, shale gas drilling opportunities also present

energy companies with valuable “follow-on” real options thatare not captured in NPV analysis. Tis additional sourceof value is inherent in vast shale gas formations where onesuccessful well leads to additional development opportunitieson attractive terms.

. holds the Sharon and Shahid Ullah Chair in PetroleumEngineering at the University of Texas at Austin.

is Collins Professor of Finance at Baylor University.

. is Director of Strategic Planning and Special Proj-ects at EXCO Resources, Inc.

holds the McAllister Chair in Finance at the Univer-sity of Texas at Austin.

liquid should be about $35/barrel, a gure that is about 1/3of the world oil price. It is no surprise that operators in shalegas plays are moving to liquids production when it is possibleand deemphasizing dry gas production. However, the priceratio of gas and liquids can easily change over time, and ifthe gas prices change, drillers have the option to move theirrigs to areas with dryer gas.

Te option to shut down operations or shut in a gas wellcomes in two basic forms: temporary and permanent. Teability to temporarily shut in a gas well is a timing option.Te owner can produce gas when prices are high and shut in when prices are very low. o a limited degree it has long beenrecognized that conventional gas wells offer some degree ofexibility in timing production. But the timing option forshale gas wells is not yet fully understood because horizon-tal drilling and fracking technology is relatively new. Wedo 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 suchas “choking” may actually increase the long-term productionof the shale gas well.

Both shale and conventional gas wells that also produceliquids through pumping present opportunities to tempo-rarily suspend production. Tese shut in wells can later bebrought back on line should gas prices rise to economic levels. Wells that require pumping are more costly to operate thandry gas wells that do not, and sufficiently high costs maymake shutting the well in economic. It is not clear though,

whether the well will produce at the same level just priorto the shut in after it is re-opened.31 It is clear that optionsattached to both conventional and shale gas wells are poten-tial sources of value but we cannot generalize. Each drillingplay must be evaluated individually.

Our most important nding is that a large number ofdrilling opportunities such as those in Haynesville shaleregion of North Louisiana have positive net present valueseven in a historically low gas price environment. Neverthe-less, we acknowledge that our analysis is limited in someimportant ways.

First, our model used production and cost estimates

from a single well. Tat said, our results are more generallyapplicable because of our thorough sensitivity and simula-tion analysis. Second, we did not consider the possibilityof producing very valuable liquids along with gas. heeconomics of liquids are critical in certain shale regionssuch as the Eagle Ford of south exas. Tird, we based ourproduction decline curve on the combination of a hyper-bolic and exponential curve that extended out over threedecades. However, the Haynesville shale production is in


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32. R.E. Allen described four types of production decline curves in 1931. J.J. Arpslater expounded upon three of these (the exception being the rst, the constant declinecurve).

33. W.W. Cutler, Jr., Estimation of Underground Oil Reserves by Well ProductionCurves,

USBM Bull, 228 (1924).

34. Petrohawk Energy Corporation, Enercom Oil & Gas Conference presentation (April24, 2010).

35. A. J. Clark, Decline Curve Analysis in Unconventional Resource Plays using Lo-gistic Growth Models, M.S. thesis, University of Texas at Austin, 2011.

Equation (1A) is the basis often used for reporting ofdecline curves to the media. For example, the PetrohawkEnergy 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 declinerate of 50%, and a hyperbolic exponent (n) of 0.9.34 Figure 1Acontains the production decline curve for the above inputs:

Te estimated ultimate recovery (EUR) for the Petro-hawk example reported in Figure 1A was 9.9 Bcf.

When the hyperbolic exponentn is greater than one Eq.(1A) extrapolates to an innite estimated ultimate recovery(EUR). Te EUR is the integral of Eq. (1A) over all time. When this occurs—and it appears to for more than one-halfof wells examined35—the production decline curve must beconverted to another type of function at some point so as torestrict the EUR to be nite. Te switching point is arbitrarily

set. For alternates that do not have this arbitrariness see thepapers already mentioned by Clark, Lake, and Patzel and byValko and Lee.

Appendix—Production Decline CurvesTe methods used by reservoir engineers to estimate oil andgas reserves often rely on an empirical extrapolation based onphysical characteristics of the reservoir. Over sixty years ago, J.J. Arps dened a set of empirical production decline curvesbased on the following three-parameter hyperbolic function:32

q t= qi(1+nD it)–– 1n (1A)

whereq 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 andn are two constants (the former is the initial rate of decline inproduction and n is the rate of change inD i over time); andt is the time period for which production is being estimated.Equation (1A) can be reduced in two special cases wheren = 0 and n = 1. When n = 0 equation (1A) becomes an expo-nential decline, i.e.,

q t= qie-D it (2A)

When n = 1 equation (1A) reduces to the harmonicdecline function, i.e.,

q t= qi(1+D it)-1 (3A)

In 1924, W.W. Cutler documented empirical support forthe hyperbolic function with exponent values for n between0 and 0.7 with most wells falling being between 0 and 0.4.33

Using Equation (3A) to estimate production decline ratescan be confusing because of how companies choose to reportthe initial rate of decline,D i . Specically, the initial declinerate reported is typically the effective rate of decline based onthe secant method. Tat is, if the initial rate of productionper year is 10 at year 0 and the production rate is 5 at the endof one year, then the initial decline rate reported would be50%. However, this is not the nominal rate of decline thatshould be used in Equation (3A). We calculate the nominalrate of decline from the reported rate using equation (4A):

D i =

1 -D esi-n -1

n for n 0 (4A) whereD esi is the effective initial decline rate calculated usingthe secant method described above.

Figure 1A Production Decline Curve (Initial Production =8.6 Mmcf/day; Initial Decline rate = 50%;and the Hyperbolic Exponent = .90)

8.60

4.30

2.82

1.13

0.36

.0

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

0 5 10 15 20 25 30 35 40

E s t

i m a t e d

M m c f

/ D a y

Year


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