by Arthur E. Berman
Shale gas plays in the United States are commercial failures andshareholders in public exploration and production (E&P) companiesare the losers. This conclusion falls out of a detailed evaluation ofshale-dominated company financial statements and individual well declinecurve analyses. Operators have maintained the illusion of successthrough production and reserve growth subsidized by debt with acorresponding destruction of shareholder equity. Many believe that thehigh initial rates and cumulative production of shale plays provetheir success. What they miss is that production decline rates are sohigh that, without continuous drilling, overall production wouldplummet. There is no doubt that the shale gas resource is very large.The concern is that much of it is non-commercial even at price levelsthat are considerably higher than they are today.
Recent revisions to SEC rules have allowed producers to bookundeveloped reserves that questionably justify development costs basedon their own projections in public filings. New reserves are beingbooked at the same time that billions of dollars in existing shale gasdevelopment costs are being written down because the projects are notcommercial. Concerns about the logic of ongoing gas-directed drillingwhile prices collapse have been partly diffused by a shift toliquids-rich plays like the Eagle Ford Shale in Texas. These newventures, however, produce significant volumes of gas which is partlywhy gas prices continue to fall.
Shale Company Cost, Debt and Undeveloped Reserves
Shale gas operators have consistently told investors that theirprojects are profitable at sub-$5/Mcf (thousand cubic feet) natural gasprices. Yet company 10-K SEC filings show that this is untrue. Theyhave invented a new calculus of partial-cycle economics that excludesmajor capital draws for land costs, interest expense and overhead. Theyjustify these disclosure practices because excluded costs are eithersunk or fixed and, therefore, supposedly should not affect theirdecisions to drill. Their point-forward plans are made at shareholderexpense since the dollars spent were very real at the time, and theircosts cannot be charged to a profit center other than the wells thatthey drill and produce.
A multi-year evaluation of production costs for ten shale operatorsindicates a $7.00/Mcf average break-even cost for shale gas plays in theU.S. taking hedging into account (Figure 1). In other words, shale gasplays are not low-cost but comparable to conventional and othernon-conventional projects. Despite claims to the contrary, thegas-price environment has been favorable over this period, in partbecause of hedging, and poor performance cannot be blamed on price.Over-production has changed this dynamic and hedging will not benefitoperators in the second half of 2010 or in 2011, and possibly not forseveral years forward. This emerging trend will test the shale gasbusiness model and show that it is unsustainable. The same tencompanies that we evaluated have cumulative debt of more than $30billion of which three have combined debt of more than $20 billion.
Some shale gas operators tripled their proved undeveloped (PUD)reserve bookings in 2009 because SEC revisions allowed them to do so(Figure 2).
The stated value of these PUDs actually decreased over the samemulti-year period (Figure 3) because of increased cost and debt. Whenthe overall financial picture is considered, the pursuit of low-valueshale gas assets has destroyed shareholder value (Figures 4a and 4b).
One Hundred Years of Natural Gas?
Many people now believe that the United States has an abundantnatural gas supply that will last for 100 years. While it is true thatthe resource base is large and that approximately one-third is fromshale gas, it is not 100 years of supply at current consumption levels.The Potential Gas Committee’s (PGC) June 2009 report estimated that theU.S. has 1,836 Tcf of technically recoverable gas resources.Technically recoverable resources are different than commercially viablereserves. Nonetheless, a more careful reading of the PGC reportreveals that the probable estimate is 441 Tcf and the shale gascomponent is about 150 Tcf (Figure 5). That resource represents a lotof gas but, at 23 Tcf of annual consumption, it is about seven years ofsupply, assuming that this was the only gas available. Based onproduction to date, it is likely that the commercial component of thisresource is between 50 and 75 Tcf assuming a $7.00/Mcf gas price.
The Failure of the Manufacturing Model
The marketing of the shale plays has relied on assumptions that theplays are both low cost, and that a manufacturing model ensuresuniversally positive results that are repeatable and risk-free throughengineering technology. We have shown that the commercial assumptionsare questionable, and that the total resource is likely smaller thanassumed. We will now address the technical issues about themanufacturing model and the reality of commercial reserves.
All shale plays contract to a core area or “sweet spot”. In the caseof the Haynesville Shale, the emerging core area represents about110,000 acres or 5 townships (Figure 6). This is a map of estimatedultimate recovery. The hotter red and yellow colors represent theemerging core area. This area is less than 10% of the total play areain Louisiana that was promoted several years ago as the largest gasfield in North America and the fourth largest gas field in the world.
The Barnett Shale play has contracted similarly to two core areas(Figure 7). The Barnett was advertised as a 9 million-acre play thatall held equal potential based on the manufacturing model. A year ago,Chesapeake CEO Aubrey McClendon told Bloomberg News (October, 2009),“There was a time you all were told that any of the 17 counties in theBarnett Shale play would be just as good as any other county. We foundout there are about two or two and a half counties where you really wantto be.”
Because of the relative maturity of the Barnett Shale, we can learnfrom evaluating the northern core area in Wise, Denton and Tarrantcounties, Texas (Figure 8).
This figure is a map of first-year cumulative production so itinvolves no interpretation of decline rates or ultimate recovery. Redor hotter colors describe areas of better production and brown toyellow, or cooler, colors show areas of poorer production. The mapshows extreme heterogeneity within the core area where high Barnettproduction volumes are unevenly distributed and many non-commercialwells have been drilled adjacent to excellent wells. The claim ofrepeatable and uniform results by the shale play promoters cannot besupported by case histories to date. We contend that the factory modelis not appropriate because the geology of these plays is more complexthan operators claim.
Well Life, NPV and EUR
The high shale gas reserve forecasts by operating companies are basedon long individual well lives of as much as 65 years. In the BarnettShale, wells were grouped by the year of completion and evaluated basedon current monthly gas production. The percentage of wells from eachgroup that are currently producing less than 1 million cubic feet of gasper month is shown in Figure 9. This gas volume only covers the costof well compression assuming $5/Mcf without royalty payments or othercosts. In other words, 25-35% of wells drilled over the past six orseven years are not paying for the cost of compression so what is thejustification for 40-65 years of advertised commercial production?
When we examined Chesapeake Energy’s type curve for the Barnett Shaleand assumed that all parameters were correct--initial production rate,decline rate, well life, etc.--we found that most of the discounted netpresent value (NPV10) occured in the first five years and that there isnegligible value after Year 20 (Figure 10). The type curve, however,forecasts about half of the reserves in years 20 through 65. Sincethese volumes have no discounted value, reserves are over-estimated byas much as 100 percent. There is clearly more risk in the shale playsthan we are told.
Consider also the Chesapeake type curve for the Haynesville Shale(Figure 11) which predicts that an average well will produce 6.5 Bcf ofgas reserves.
The match with wells that have 12 months or more of production isgood. The problem lies in how future decline trends are projected andwhat hyperbolic exponents (curvature or b-factor) are assumed. At thistime, we do not know how these wells will decline--only time will tell.It, therefore, seems reasonable to present a probabilistic range ofpossible reserves rather than a fixed value. Depending on a range ofpossible hyperbolic exponents, we can project reserves that range from2.5-6.5 Bcf per well. We do not know which outcome to choose but itseems clear that small changes in the curvature of the hyperbolicexponent result in radically different reserve outcomes (Figure 12).
This implies greater uncertainty and, therefore, greater risk thanoperators represent. It seems more reasonable for companies to use anintermediate hyperbolic exponent (as recommended by Society of PetroleumEngineers peer-reviewed papers) to project their reserves and, later,revise them upward or downward when production has stabilized. Using ahyperbolic exponent of 0.5, Chesapeake’s average well will produce 3.0Bcf based on their type curve, which is not commercial at $7.00/Mcf.For reputable companies to say that the least likely case (b = 1.1) isthe most likely case does not prudently represent uncertainty.
The Traveling Circus
Shale play promoters constantly try to divert attention and analysisfrom current plays to newer plays. Newer plays have less data toanalyze and, therefore, reserve claims are more difficult to question.Because the Barnett and Fayetteville shale plays have under-performedexpectations, we were invited a few years later to consider the futurepotential of the Haynesville Shale play. Now that the Haynesville looksdisappointing, we are asked to consider the Marcellus Shale play.Since the State of Pennsylvania does not publish monthly production datafor analysts to evaluate, no one can dispute or confirm the claims madeby operators. With the shift to liquids-rich plays like the Eagle FordShale, we are again asked to trust the same promoters that sold usunder-performing plays in the past that this time it will be different.
We should call a time out at this point and ask for a reality check.This will never happen because the capital keeps flowing and thepromoters continue drilling and leasing. There appear to be a host offoreign investment companies that may provide capital for the shaleplays now that operator debt has reached extreme levels, and mostavailable assets have been sold at considerable damage to shareholders.
The Marcellus Shale Play Will Disappoint Expectations
What projections seem reasonable for the Marcellus Shale based onexperience with other plays? We should expect that the play willcontract to a much smaller core area, or perhaps a few areas, instead ofthe currently advertised expectations for the region as a whole. It isalso likely that identification of core areas will be more difficultbecause of the large geographic extent of the play. This should resultin a higher level of capital destruction in drilling and leasing than inother shale plays.
While the play may have built-in advantages because of naturalfracturing and proximity to important natural gas markets, it also hasdisadvantages. The region currently lacks sufficient pipeline capacityto deliver gas to markets or storage, especially in northeasternPennsylvania. While infrastructure is forthcoming, wells are beingdrilled to hold leases now and delays in sales connections will have anegative impact on net present value.
Much of the Marcellus gas contains natural gas liquids (NGL),apparently necessary to justify the economics of the play. These NGLsmust be removed before delivering the gas to a pipeline, butfractionation plant capacity is limited. Even after plants are built,demand for ethane (about 60% of NGL volume) is limited, so wells mayhave to be shut in, further destroying present value and slowingdevelopment of the play.
Water needed for hydraulic fracturing and disposal of produced loadwater are becoming serious obstacles for Marcellus development. Theproblem with water sourcing is not availability but getting watermanagement plans approved for the high volume withdrawals (drillingrequires about 100,000 gallons and completions use another 3-4 milliongallons). There are few waste treatment plants and the cost oftransporting disposal water from the well may add $250,000 to the cost(Tudor, Pickering and Holt, 2009). Also, there is widespread belief thathydraulic fracturing will contaminate aquifers and that this is a riskthat cannot be tolerated.
The population density is high in many areas of the play, and thiswill heighten sensitivity to perceived drilling and producing hazards.Any spills or blowouts have the potential to shut down or curtailoperations in a larger area than the problem well. Drilling in suburbanareas will complicate putting acreage blocks together. It will alsomean more potential objections to drilling the thousands of locationsnecessary to hold leases and prove reserves. These factors do not meanthat development won’t proceed, but it is likely to move forward moreslowly and at greater cost than in other shale plays.
The Drilling Continues Despite Low Gas Prices
Returning to the broader subject of shale plays in general, why dooperators keep drilling while their own over-production has depressedthe price of natural gas by half of its value since January 2010? Itseems fairly clear at this time that the land is the play, and not thegas. The extremely high prices for land in all of these plays hasproduced a commodity market more attractive than the natural gasproduced.
Foreign companies invest in U.S. shale plays for different reasonsbut the most often-stated reason is to learn about the technology thatthey may be able use to their advantage in future shale plays around theworld. It is possible that some companies enter into joint ventureswith U.S. shale operators for strategic reasons based on fears of futureresource scarcity particularly as China expands its efforts to controleverything from petroleum and minerals to rare earth metals around theworld. Diversification of their global portfolios also enters intoconsideration because their view of the economics of U.S. shale gas isgenerally different than the domestic developers. Their implicit cost ofcapital is usually much lower, as well.
Closing Thoughts
The so-called shale gas revolution promises E&P opportunitiesthat are geographically immense with no barriers to entry. Theseventures supposedly have no risk. Because of shale plays, we are toldthat there will be an abundant supply of inexpensive gas for 100 years.And the E&P companies involved will all earn big profits. Is thereprecedent for this improbable combination of make-believe businessassumptions that did not end in disappointment?
U.S. shale plays have been over-sold and are unlikely to deliver theresults that investors now expect. In fact, shareholders have alreadylost most of their investment. The shale gas resource is huge but thecommercial portion is likely to be much smaller than what has beenclaimed or hoped for. At higher gas prices, more of the resource makeseconomic sense but that depends for the near term on productiondiscipline that seems to be absent in the U.S. E&P companies. Italso assumes that attendant service costs do not escalate at similarmultiples to gas prices.
For many companies, there is no turning back--the entire company hasbeen bet on the success of shale plays. This seems to violate what hasbeen learned in the E&P business about the importance of having abalanced portfolio. In some cases, companies do not have sufficientshareholder value to justify being bought and, therefore, saved.
Our evaluation suggests that there is limited commercial value fromthese plays despite public enthusiasm and operator claims. E&Pcompany shareholders have subsidized low natural gas prices and havelittle hope of recovering their investment in the near term. Theunderlying problem is a failure to grasp the concept of discounting.Reserves that are produced in small volumes over decades have littlefuture value and are, therefore, not reserves. The shale plays arecalled resource plays for a reason: they are all about resources butnot profit or the shareholder.