The status quo approach to valuing companies in the E&P sector now needs to be seriously questioned. Many investors are focusing on better performing industries, and die-hard E&P investors are demanding that companies demonstrate an ability to generate a return on capital rather than a return of capital. One measure of a company's performance that has proved useful is an E&P value-added index. This index reflects the annual change in future net cash flows from oil and gas reserves relative to capital invested. The value-added index can provide a consistent yardstick to measure a broad universe of companies; unfortunately, the data only comes out once a year and is backward looking. True, past performance is no guarantee of future results, although a good track record is certainly preferable to a poor one. A related concept-that of free cash flow-may be more telling. Free cash flow (FCF) is discretionary cash flow (DCF) available for reinvestment after providing for the capital required to replace annual production. The amount needed for production replacement can be derived by multiplying a given company's output by its full-cycle all-sources cost of reserves added (CORA). Simply put, FCF is the amount of internally generated funds available to grow a company. Indeed, the ability to grow internally will be a critical issue for independents during the next several years. Investor sentiment toward the energy sector has changed-the traditional reliance on equity financing to fuel uneconomic growth cannot continue. As investor interest wanes, oil and gas companies face lower valuations and larger requisite market capitalizations. Given escalating production decline rates, companies that cannot grow internally will be forced to liquidate. They may dissolve slowly and inadvertently over time, or quickly and deliberately through a sale or merger. Consequently, mergers and acquisitions in the E&P sector will likely accelerate in the near term. Traditional valuation methods Analysts generally agree that the most appropriate way to value an oil and gas company is via a risked discounted cash flow analysis of proved and probable reserves, plus future prospects. However, the reality is that this information is not publicly available. Practicality dictates that valuations are instead based on derivations of a net asset value (NAV). Analysts calculate NAV based on a company's current proved reserves and other assets and liabilities, then acknowledge that its equity should trade at a premium to NAV in recognition of "going concern" value, such as a company's ability to create incremental value through the reinvestment of cash flows. Other popular valuation tools are discretionary cash flow (DCF) multiples and the ratio of adjusted market value (AMV)/EBITDX (unleveraged cash flow). DCF and unleveraged cash flow multiples have been widely adopted because they are easy to calculate, because management has control over the use of these funds, and because both measures are invariably positive. Further, they fit the industry because E&P companies typically have little or no earnings. However, these multiples have become increasingly subjective, as competition in the industry accelerates and additional performance measures are identified. Both leveraged and unleveraged cash flow multiples fail to reflect reserve depletion. Further, not all cash flow is truly discretionary, and not all cash flow can be reinvested to enhance growth. If a company chooses to spend nothing on exploration and development, it will eventually liquidate-shrinking each year by the quantity of reserves that are produced. Financial theorists created P/E multiples as a valuation shortcut from the dividend discount model. Using this analysis, a multiple is applied to future economic earnings that are retained and reinvested in order to generate growth in future dividends. Companies that consistently generate both superior rates of return and growth are awarded premium multiples. In theory, P/E multiples can be applied to E&P valuations because depletion is a proxy for the maintenance capital required to replace reserves produced during a given period. However, in practice depletion is skewed by such factors as asset write-downs, accounting methods, mergers and acquisitions, and asset sales. Also, expenses are included that do not reflect the true cost to replace production. An alternative measure Free cash flow accounts for what producers must spend merely to replace production. Hence, it captures all aspects of the E&P business-CORA, operating revenues, and operating costs. In a nutshell, free cash flow measures the economic earnings of a producer and is thus consistent with financial theory. Admittedly, free cash flow is not a perfect tool. It presents several new hurdles for analysts: • It can be negative; • It requires a value judgement on future CORA; • E&P companies typically pay nominal or no dividends, which complicates the multiple approach. However, these hurdles can be overcome. If free cash flow is negative, there can only be three causes: revenues that are too low, operating costs that are too high, and/or reserve addition costs that are too high. Since management has no real control over unit revenues (commodity prices) in the oil and gas business, its goal should be to minimize operating and reserve addition costs in order to achieve high free cash flows and rates of return. Negative free cash flow can be expected in a low commodity price environment; analysts in these cases should pay particular attention to management's ability to produce and add reserves in an efficient manner. Like accounting earnings, they can look beyond periods of negative FCFs to those in which economic profitability returns, then discount this cash stream back to the present. In addition, CORA is a backward-looking yardstick of operational performance. While relying solely on historical CORA to predict future FCF would still be an improvement over accounting earnings or DCF, this would not be significantly different than relying on a value-added index to project future increases in NAV. The challenge is to estimate how a company will perform going forward. Analysts make predictions of DCF (the cash inflow side of the equation), so it follows that forecasts of forward-looking CORA (the investment required to generate cash flows) be made as well. The timing of exploration and development expenditures relative to the corresponding booking of reserves is the most critical element in this analysis. Finally, if an entity were to never pay dividends, its shares would be worthless. Since E&P stocks are not completely worthless, investors must believe that there will be a dividend in the future, even if it is effectively a liquidation dividend upon the sale of the company. Benefits of the FCF method Free cash flow can be an extremely important tool in evaluating E&P companies. Firms can be compared on both a FCF/DCF ratio and FCF multiple basis. Presumably, the higher FCF is as a percentage of DCF, the larger the FCF multiple. An extension of the FCF concept is the relationship between AMV and debt-adjusted FCF. Whereas FCF measures economic earnings generated to common shareholders, the AMV/debt-adjusted FCF ratio measures the economic earnings generated by the company's asset base, before the financing decisions undertaken by management. In this sense, the AMV/debt-adjusted FCF ratio can be viewed as a proxy for the market's perception of asset quality. (See table.) Another important concept related to FCF is the recycle ratio (RR), which is DCF/CORA. In fact, FCF (DCF-CORA) is the dollar incarnation of the RR. Rates of return in the oil and gas industry can be derived from the RR by assuming some duration to the exploration and development cycle. Experience suggests that the time from concept to production is approximately two to three years for domestic ventures and four or more years for international and frontier-type projects. A three-year cycle for domestic producers and a four-year cycle for those with a combination of domestic, international and frontier-type projects are reasonable assumptions. Additionally, the required after-tax return on equity in the E&P industry should be approximately 11% domestically and 14% globally. That premise is based on an industry-specific risk premium of 5% to 7% and a risk-free rate (represented by 10-year Treasuries) of approximately 6% to 7%. This translates into an estimated after-tax cost of capital approximating 12.5% for large-cap, globally diversified independents. To return their cost of capital, domestic E&P companies need to maintain an average RR of 1.3X (i.e., $1 invested today needs to return roughly $1.30 midway through year three to generate a compound annual return in excess of 11%). This equates to a minimum FCF/DCF ratio of approximately 25%. Likewise, the large-cap, globally diversified producers need to maintain a RR of 1.5X over time, with FCF representing 35% of DCF in order to meet the 12.5% threshold. Since DCF is measured after interest costs and preferred share dividends, these returns can be attributed to a company's common equity. The value-added index and FCF concept are similar to the Economic Value Added/Market Value Added (EVA/MVA) approach used in other industries. The annual change in these standardized measures represents the economic value added by management. Likewise, future FCF represents potential economic value added before considering reinvestment risk. To the extent that the value-added index indices a company's relative success, FCF analysis attempts to identify the capital which management will have available to reinvest in enhancing growth. Over time, this approach will help differentiate between companies, in theory leading to superior stock selection. A look to the future Based on an analysis of 1995-98 data (the last year for which complete information is available), industry-wide FCF averaged 16% of DCF in the U.S. and 27% of DCF worldwide. (Results for 1999 are unlikely to be significantly different from these figures.) This implies respective returns of only 7.9% and 9.6%-well below the industry's imputed cost of capital. In the past, investors have tended to overlook this economic reality and finance the group regardless. Commodity price shocks, exploration success, accretive acquisitions, and takeover speculations blinded them to the underlying fundamentals of the business. However, investors now realize that equity market returns in the group have not justified the risks involved. "New economy" sectors such as the Internet and high technology have displaced E&P as the high risk/reward sectors of choice. In the absence of a reversal of investor sentiment toward the stocks, the E&P sector may be headed for a major consolidation. Companies that can grow internally are typically efficient finders and operators of oil and gas assets in their selected core areas. And, FCF measures can separate the firms with the ability to internally grow from those that cannot. Consolidating the assets of struggling firms with the profitable entities should lead to both direct and indirect cost savings. M&A activity can increase both rates of return (through reducing costs) and future growth (by improving a given company's ability to capture profitable new opportunities). Higher rates of return and better growth stories are essential for the industry as a whole if it hopes attract investors again. Andrew T. Lees is an E&P research analyst at Petrie Parkman & Co., Denver. Paul R. Leibman is a principal and director of research at Petrie Parkman.