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On May 11, 2012, The New York Times published an editorial about making natural gas extraction technology “safer” for neighbors and landowners where new wells are being drilled. “There is little doubt that the (new shale) gas is plentiful and cleaner than coal (and) could help with the country’s energy and climate problems,” the newspaper said.

But, the Times went on to deny this economic gain, “…unless the public can be sure that it will not pollute water supplies or the air.”

This approach to new technology is in the tradition of cost-benefit analysis (CBA) as required for all federal regulation that certifies beneficial gains to the economy. When justifying any new energy technology, then in most cases, the findings are that benefits are substantially in excess of the cost, indeed by as much as is required to compensate those on whom the costs are imposed.

The New York Times, however, dispenses with assessment of benefits. There is no mention of gains to U.S. industry from lower-cost fuel and raw material supplies, of gains to homeowners from lower monthly heating, air conditioning and power costs as new shale gas expands supplies (lowering prices delivered through the national large-scale pipeline network).

Instead, the Times focuses on contamination of groundwater, failures in the disposal of contaminated water used in the drilling process, failures to deal with the chemicals used in drilling, and last but not least, on air pollution from escaping methane (i.e., the natural gas itself).

The orders of magnitude of these costs to the economy are not estimated, nor are they compared to benefits. There are methods proposed for reducing costs, such as preventing any drilling where it is anticipated that costs could be imposed, or adding production taxes to pay for regulation that might prevent social costs.

Our approach here is to go beyond the complaints, however profuse and loud, and whether those new gas wells have caused spills, made excessive noise, or produced disagreeable odors. We attempt here to assess the scale of benefits as well. These include substantial front-end royalties paid to the complainants and increased supplies of lower-cost energy resources for manufacturing, trade and household consumption, as well as increased tax revenues for state and local governments generated from the sale of more (shale) gas. We have not been able to specify most of these gains, but we can find numbers for the order of magnitude of total quantities going to market.

Revenues and costs in shales

It is appropriate to ask whether there is more than local land, water and air-quality decay to be derived from drilling shale-gas wells. In the most general sense, there must be gas-based products from which consumers derive benefits. The question then becomes whether the production and environmental costs exceed the benefits from the purchase and sale—and ultimate consumption—of this new supply of natural gas.

The process of production, from recent rapid spread of decades-old shale fracturing technology, is not different in kind from natural gas production methods developed over the last century for extracting gas from non-shale formations. Wells are drilled some distance underground and the vertical hole is encased by pipe and sealed with cement. The technology requires wells drilled horizontally and fracturing with high-pressure liquids (water plus prop-pants and surfactants specific to the well) to fracture the shale formation. Production costs incurred are very likely to be in the range of $1 per thousand cubic feet (Mcf) of gas produced, plus or minus 50 cents, depending upon specific drilling and pressure conditions. Table 1 shows these costs for five shale-gas production companies for which there is information publicly available. In some instances production cost outlays are less than amortization expenses or interest expenses on capital outlays. Our estimate of marginal costs of $1 per Mcf is similar to those from company to company, based on the operations of thousands of wells in various shale basins.

In 2010 the natural gas average sales price per company, including all gains/losses on financial gas derivatives ($ per Mcf) at the wellhead, regional pipeline market and delivery point, was between $4.64 and $5.57 per Mcf. Because of substantial differences in the locations of basins across the country, and new wellhead production points, gas prices differed because of varied delivery costs into pipeline hubs. Prices also varied because of differences between short- and long-term contracts and spot sales.

Even so, one can make a judgment that in 2010, all natural gas together (conventional vertical-well gas and shale gas) sold at a hypothetical central market for $5 per Mcf (the U.S. Energy Information Administration calculated the average wellhead price as $4.48 per Mcf for 2010). This is because natural gas from various sources sold in a competitive market both at the wellhead and in commodity exchanges after incurring marginal costs of production of $1 per Mcf.

The operating income margin of $4 ($5 operating revenues minus $1 marginal costs) would appear to be economic gain, but it is not what we mean by benefits. As indicated in Table 1, general expenses, depreciation and amortization of assets, and interest expense comprise parts of total expenses in addition to marginal costs. If the (representative) company were to sustain its operations at current production rates, expenses making up average total cost of $2.58 to $5.01 per Mcf would have to be included . The operating income margin (price minus average total cost) in the long run would have to exceed $2.48 per Mcf for Chesapeake Energy Corp. and $0.53 per Mcf for Cabot Oil & Gas Corp.

In the last year that prices were “normal,” i.e., relatively unaffected by the surge of new supplies from shale formations and reduced demand from mild winter weather, producer positive net returns ranged from $2.293 billion at Chesapeake to $66.515 million at Cabot (as estimated by multiplying the operating margin by annual gas production).

Benefits for users and consumers

Net income from production accumulated by producers is hardly the benefit of greatest interest. It is the gain to consumers of the gas that determines benefits, since the consumers incur the environmental costs. Manufacturers of chemicals and materials, household users of heating, air conditioning and electricity purchased more gas for less payment to realize these benefits.

The traditional measure of such benefit, consumer surplus, is the “B” of CBA in our view, and it equals the difference between the market price and what a consumer is willing to pay.

In the traditional supply-demand diagram, declining demand is illustrated by a line stretching from a price at which zero units would be demanded down to the price at current consumption rates. The area above the current price, as illustrated in Diagram 1, consists of a measure of such benefits. That is, the difference between an all-or-nothing offer to pay for the entire quantity and the amount actually paid at current price is the “benefit” from having the production available.

With both linear supply and demand curves, the supply curve with a positive slope and the demand curve A to B with a negative slope, and equilibrium price where supply equals demand, then consumer surplus is illustrated by the triangle (A – P)Q/2 for the volume Q taken at price P. This is the sum of the (vertical) amounts that consumers would pay—their total benefit minus actual market price paid. (See Price Theory, 3rd edition, Jack Hirshliefer, pp 218–219.)

Then what are the gains for consumers from the production distributed from gas wells owned by Chesapeake, say, in 2010? To answer this question, we would have to know the slope of the demand curve facing Chesapeake at various locations. There is no such demand curve. In current markets, that slope is zero because, with large numbers of other sources of both shale-gas and conventional gas in the same basins, any gas price specific to Chesapeake, net of transportation and other costs unique to Chesapeake, will be approximately the same as for any other producer.

But consider that each producer faces the same demand condition, then the hypothetical demand is a pro rata share of the basin demand and is downward sloping. The hypothetical demand curve at the well has the same slope at any price. Then assuming that the market-wide elasticity of demand were negative 0.20, consumer surplus on Chesapeake’s gas sales approximates $4.217 billion (924.9 million Mcf x ($5.57 - $1.01) per Mcf). In at least this one example, involving consumer gains in one year, for one company’s production, the surplus of consumers is expected to exceed the producer’s costs and gains by a factor of two.

Shale-Gas Production Costs

In the last year that prices were “normal,” i.e., relatively unaffected by the surge of new supplies from shale formations and reduced demand from mild winter weather, producer positive net returns ranged from $2.293 billion at Chesapeake Energy Corp. to $66.515 million at Cabot Oil & Gas Corp.

Benefits for the economy

There is some indication of very large gains for the economy from shale gas from comparing year-to-year total consumption. Within the triangle of consumer surplus there is a rectangle of the difference in prices in successive years times the quantity of earlier years’ sales. This is a conservative estimate of consumer surplus since it takes no account of the increased consumption that occurs in response to a lower gas price. But since the elasticity of demand is quite low, that increase is small.

The nominal price (that is, the Henry Hub spot price) in 2008 was $7.97 per Mcf and in 2011 was $3.95 per Mcf (according to the EIA) so that the difference in price over three successive years was $4.02 per Mcf. Gas production in 2008 was 25.6 trillion cubic feet (Tcf), so the surplus to consumers from the price reduction from shale gas equaled $102.9 billion.

This very large amount of consumer gain—over $100 billion—from the new-technology-induced price reduction in gas is the elephant in the room. It comprised a substantial majority of total expenditures on this fuel nationwide.

In past years, those expenditures were limited by the higher costs of production of gas produced from vertical wells. These were in part producer surplus, but most were the costs of sustaining well operations in the old technology. Even so, it is startling to acknowledge that consumer benefits from new shale-gas production can be expected to exceed $100 billion per year, year in and year out, as long as current production rates are maintained.

Economy-Wide Benefits Shale-Gas-Induced Gas Price Reductions

The difference between an all-or-nothing offer to pay for the entire quantity and the amount actually paid at current price is the “benefit” from having the production available.

Economy-wide costs of shale drilling

But as we have indicated, there are adverse effects—costs against these benefits—on water, ground conditions and air quality from shale fracing. To complete even the rough approximate CBA requires these costs to be estimated and subtracted from the $100 billion of the year-to-year consumer gains.

To assess costs, we reviewed current studies and reports on accidents, misuse of technology and poor well design and installation. A 2011 report for the Secretary of Energy (the “Deutch Report”) counted 19 instances of problems with fracwater over the previous few years, amid thousands of wells drilled. The Secretary of Energy Advisory Board was chaired by John Deutch, former CIA director and now at MIT, and included Stephen Holditch, Texas A&M; Fred Krupp, Environmental Defense Fund; Kathleen McGinty, Weston Solutions; Susan Tierney, Analysis Group; and Mark Zoback, Stanford University.

The Deutch Report could not confirm any instances of groundwater contamination from fracing, but it found incidences of some remediated surface spills. The Oklahoma Corporation Commission, the regulatory authority for oil and gas drilling in that state, with more than 100,000 oil and gas wells hydraulically fractured, documented no incidents of groundwater contamination.

The EPA has reported an instance of hydraulic-fracturing contamination at two deep (more than 7,000 feet) water wells (in Wyoming) as a matter of concern. (It is useful to note that many underground aquifers in Wyoming, as well as across the nation, are saltwater aquifers with heavily mineralized waters that are unsuitable for agriculture, livestock or human consumption without significant gains from purification.)

At this stage, then, consider the known contamination that hypothetically could occur on a micro scale, that of one well and one property owner. Would fracing impair the property owners’ domestic water resources? What is the cleanup cost if a tanker truck turns over and spills the tank’s contents in the rancher’s pasture? In this instance, there is not likely to be impairment of a ranch’s well water due to spa- tial and geologic separation of water resources. Nor would there be a case of intrusion of fracing liquids in the well water. Well-water supplies are drawn from aquifers, usually no more than 500 feet below the surface and generally well separated by many stratifications of geologic formations from oil and gas resources at depths in excess of 4,000-plus feet. This makes contamination extremely unlikely.

In addition current state-by-state regulations require steel and cement-sealed casing for oil and gas wells passing through the shallow aquifers. Also, as a matter of course, in the contracting process for drilling rights, private landowners can and do require even more safeguards. A study now under way at Yale University in the Marcellus Basin on the East Coast will drill through the 500 feet of surface aquifers to set up monitoring wells to detect any hydrologic changes in the surface aquifers due to hydraulic fracturing at depths of 7,000 feet.

However, there is always a potential for even the greatest of redundancies in safeguards to fail. Assuming that there is a failure during fracing or production, the well crew would be able to detect the failure by a loss of pressure and fluid return. Engineering calculations can be done to determine the fluid loss and the extent of the damage. Cleanup efforts would begin on the well, and the gas company would compensate the rancher by trucking in quantities of potable water for ongoing ranch operations. The cost of trucking in potable water can range from $0.50 per barrel to $2 per barrel. The damage costs would be determined by the number of barrels until either the aquifer self-cleans by its natural flow of water through the pores of the subsurface rock, or the gas company drills a new water well—ordinarily a task accomplished within weeks at a cost of less than $5,000.

But a 5,000-gallon tanker truck turning over in a rancher’s pasture could mean a release of the whole 5,000-gallon load. Most of this would be water and sand, which could be eliminated with absorbents and shovels. In the Wyoming basins, the cost of removing contaminated water for either deepwell disposal or remediation has been up to $3 per barrel (a barrel containing 42 gallons). In Texas, the costs would be less.

Depending on how porous the soil is in the yard, the wastes seep down into the earth. Once there, the concentrations in the soil determine the level of cleanup. Again, most of these are likely to be hydrocarbons, which may stay on the surface in thick masses, or slowly leach into the soil, if they do not first evaporate and disperse into the air. Heavy metals, unless moved by the liquid portion of the waste or rainfall, are not likely to move deep into the soil.

These contaminated soils can be scraped up and trucked offsite. A key factor is the distance of the remediation site to the landfill. A rough estimate is that 5,000 cubic yards of material disposed of at an offsite landfill at $500 per cubic yard, including on-site sampling, crew protection, transportation, and disposal, comes to a total outlay of $2.5 million. This example, of course, may vary greatly due to site-specific conditions. However, based on our direct experience with environmental remediation efforts in oil and gas operations, it is clear that the cost of a discrete spill event would not impair the economic value of a drilling operation, especially if there is more than one oil and gas well on the rancher’s land.

An economy-wide estimate

How then do we extrapolate individual disaster scenarios across an entire industry to determine the social cost of possible contamination from fracing in order to deduct it from the consumer surplus of $100 billion for each year?

We consider that the reported instances of contamination from fracing relate, at most, to an extremely limited minority over hundreds of thousands of wells. Let’s assume the worst—that the accidents occur in one year; that the cleanup requires a new water well at $5,000; and that 100 spills occur (at $2.5 million per spill) given then that the industry drills 10,000 new wells per year. The cost of fracwater contamination is therefore $250 million. Economic benefits, as estimated in as limited methodology as is reasonable, thus exceed costs to the community by 400-to-1.

Consumer surplus

In keeping with the national debate on the future of natural gas as a replacement for crude oil, we consider the consumer surplus of replacing one barrel of oil with its BTU equivalent of 6 Mcf of shale gas. We assume that the current price of oil is $100 per bbl. If we use the gas wellhead price of $5 per Mcf and multiple it by 6 to get a per barrel of oil equivalent (BOE) of $30 of cost, the savings is $100 per barrel, or $30 per BOE.

Therefore, the gain to consumers of replacing one barrel of oil with a natural gas fuel equivalent is approximately $70 per barrel. Current U.S. consumption of crude oil is approximately 15 million barrels per day. Replacing 1 million barrels per day of crude oil with the 6 billion cubic feet equivalent of natural gas, would generate approximately $25.6 billion ($70 per barrel x 1 million barrels x365 days) of consumer surplus for the U.S. economy over one year.

The Yale Graduates in Energy Study Group includes Robert Ames, vice president of Solazyme and an advisor to the U.S. DOE on renewable fuels; Anthony Corridore, Lafarge North America; Joel Ephross, who practices law in the energy industry; Ed Hirs, a managing director of Hillhouse Resources and who teaches undergraduate and graduate energy economics classes at the University of Houston; Paul W. MacAvoy, Yale Professor Emeritus; and Richard Tavelli, a director of Winchester Capital.