The tremendous price spikes in electricity and gas spikes of the last two years demonstrated both the desirability of flexibility in the national energy system and, unfortunately, the lack of it. Spot oil, gas and power prices rose high above long-dated futures and forward prices. The near-month natural gas contract on the Nymex approached $10 million Btu in December 2000. In certain places, such as California, the price spike was even more pronounced and politically contentious. The energy industry has two reasons for regrets. First, the price spikes damaged the industry politically and alienated some customers. Second, despite being blamed for the price run-ups, few companies managed to exploit high spot prices to the extent they could, and should, have. Energy companies drilled many wells, and began construction on new power plants. Lead times in the industry are usually extensive, however. A rise in the spot price often leads to significant increases in energy volumes that come to market just as prices begin declining again. Indeed, oil and gas futures have declined significantly in the last six months and many power-industry observers forecast a power glut in two to three years, as the surge in new capacity comes online. Valuing flexibility Good businessmen have always understood there was value in flexibility. Certainly, the electric-power industry had always distinguished between base-load generating capacity-employed nearly continuously to meet permanent demand-and peaking capacity-used temporarily only to meet fluctuating demand. Under regulation, the electric industry usually had both ample base-load capacity and sufficient peaking capacity for the worst-case scenarios. Rates of return on assets were generally guaranteed. As rules governing power generators changed during the 1990s, managers were forced to begin valuing peaking capacity accurately. Traditional discounted cash flow techniques were inadequate to the task. The value in peaking capacity comes from the ability of companies to provide electricity when it suits them-i.e. when the margin between fuel and power is wide-not all the time. Peaking capacity has the desirable characteristic of call options. One has the right, but not the obligation, to do something on predetermined terms in the future. Several of the companies active in the unregulated merchant-power business began to employ real-option (RO) analysis. As the name suggests, these techniques borrow much from financial-option analysis but are used to value and manage physical assets. Owners of peaking capacity such as Enron, Dynegy, El Paso, Calpine, Reliant, Mirant and others have used real-option models to decide whether to build more peaking capacity and when to exploit opportunities. Peaking units tend to have lower capital costs but higher operating costs (especially fuel) than base-load generators. Owners would not want to run them all the time but only when margins were wide. Although operating costs of peaking units are high, they are more profitable than base-load units when margins are very volatile. The oil and gas industry has also invested heavily in North American gas reserves in the last two years but almost all the investment has been in the equivalent of base-load, rather than peaking, capacity. The gas-reserve equivalent of peaking capacity would be PUDs (proved undeveloped reserves) that can be brought into production very quickly, even though production is short-lived and comes at a high cost per thousand cubic feet (Mcf). Overlooked option PUD reserves are real options. Companies have the right, but not the obligation, to exploit marginal reserves. This marginal capacity has real economic value, particularly when in basins with existing gathering systems, pipelines and drilling contractors. Some new wells can be completed in as little as a month. This value is not apparent from discounted cash flow (DCF) calculations that only capture the value of a well if it is drilled now rather than the possible value in the future. Oilmen have always understood this intuitively. A PUD may have a net present value (NPV) of zero currently. Because of that, it could not even be booked officially as a PUD because standard petroleum engineering requires development to be NPV-positive under current conditions. Nevertheless, good managers would never give away a lease for free if it has years to run because, in the future, gas prices might be higher or costs lower. RO calculations often provide much higher values for PUDs than DCF calculations. Even contingent reserves that would be NPV-negative to develop today have real economic value as options. This value isn't just theoretical. Most E&P companies have market values that significantly exceed the simple NPV of their proven, developed, and proven-undeveloped reserves. The difference comes from the implied values of exploratory and development options. Companies with a history of comprehending, identifying and managing real-option values have provided superior returns. The North American oil industry needs to think about its marginal reserves as valuable, real options. PUD gas reserves are vitally important as peaking capacity with respect to electrical power as well as gas. The point is not to develop these marginal PUDs now (most of the time, development would not make sense) but to identify the opportunities before contingencies arise. Value is created more through proving reserves than through developing them. This critical fact is often overlooked while management is focused on current production volumes, cash flow and earnings. Additionally, many drilling opportunities have not been cataloged because proven-reserve figures are based only on volumes that are economic to produce at current prices and with current technology. Real option models also provide the best information about when to exploit reserves. Everyone agrees that negative-NPV development wells should not be drilled. But although finance textbooks advise "accept all positive-NPV projects" there is no one who would drill a well for just $1 of NPV. Real-option theory explains why managerial intuition is correct on this point and properly calibrated models will tell what level of NPV is optimal for converting PUDs into proven developed reserves. Using markets North American gas PUDs and contingent reserves are potential sources of value to the oil industry. By recognizing and managing these marginal reserves properly, oil companies could provide important protection to gas consumers-and create a lot of value for their shareholders at the same time. Peak power generators and utilities with obligations to provide gas to homes at capped prices would place a very high value on such protection. Call options on gas and power swaps are bought and sold every day. Few oil companies participate in this market, however. This is unfortunate for them because, as the owners of marginal reserves, they are the natural providers of such calls. With sufficiently reliable information about the cost and timing of undeveloped reserves, E&P companies could sell call options, perhaps on an annual or seasonal basis, to power generators to backstop peaking capacity. Most of the time, these calls would expire unexercised. This would be a way for E&P companies to get an economic yield on marginal reserves. Some times, when gas prices jump, consumers would exercise those calls and the producers would have to develop those reserves to meet their obligations. Even then, if the transaction had been configured properly, the producer would have been exercised into a positive NPV investment. Such arrangements would be the first step in a build-to-order national energy system that integrates E&P companies, pipelines, power generators and end-users. PUDs that can be developed quickly have high option value. Being able to develop them quickly, however, depends upon having prearranged exploitation plans. The contracting issues would also be complex. In particular, such a system would require better contracting between E&P companies and contract-drilling and service companies. Some sort of benefit and risk-sharing would be necessary. What to do Two of the oldest adages in business are "What gets measured, gets managed" and "You get what you pay for." Once companies begin rewarding people for managing real-option values, the size of their marginal reserves will grow dramatically as will their ability to extract value from them-even if they are not developed. They should be reviewing their existing-resource bases to identify such values. They should also be looking for contingent PUDs-those that would be booked if prices were just a bit higher than today.