Wall Street analysts and portfolio managers, in their quest to find the best E&P stock, are perpetually trying to measure the value of the enterprise as well as the direction of that value in the future. One of the questions investors frequently ask: "Is this a better time to drill for proved oil and gas reserves or a better time to buy them?" While this might seem like a simple question for Wall Street, it is a much more complicated one for successful E&P managers. Among the more obvious factors affecting the buy-versus-drill decision for managers is the outlook for oil and gas prices as well as the current and future costs of finding and producing reserves. Other important, but more subtle factors, include the quality of a company's existing drilling inventory, the availability of drilling rigs and experienced personnel to man them, as well as opportunities to make "reasonably priced" acquisitions. Wall Street, on the other hand, tends to view the decision as pretty much black or white. Either it is a good time to make acquisitions because they are plentiful and relatively cheap, or it's a bad time because they are scarce and too expensive. In today's environment, historically high oil and gas prices have made acquisitions both plentiful and expensive. Unfortunately, some investors put too much emphasis on finding costs as the primary benchmark for determining whether companies should buy or drill, when the principal objective for companies is generally to maximize rate of return. If it costs $2 to $2.50 per thousand cubic feet of gas equivalent to find it with the drillbit, some say, why not just buy it for $1.75 or $2 instead? Of course, there are many other factors to consider, including production rates, reserve life and extraction costs. New wells typically generate higher rates of production, lower per-unit operating expenses, faster payouts and higher rates of return than older wells. A mature property, on the other hand, which is more typical for acquisition candidates, generally has higher per-unit operating expenses, a longer payout and a lower rate of return than a new well. So, although the cost for an acquisition may be less than a new drilling project, after-tax returns are generally lower. This is especially true in today's overheated acquisitions market. In terms of relative valuation, Wall Street has always had a clear preference for companies that can successfully grow through the drillbit. The current bias is for so-called "resource plays" or low-risk, repeatable drilling plays such as tight gas sands, gas shales and coalbed methane. Companies with large inventories of these "unconventional" reservoirs typically command a premium for their shares. Examples are EnCana Corp., Ultra Petroleum and Quicksilver Resources. The buy-and-exploit companies, on the other hand, generally have lower valuations, primarily because the market perceives them as dependent upon acquisitions for growth. Apache Corp., St. Mary Land & Exploration and Whiting Petroleum are good examples. Good inventory, then drill The current business environment indicates that there has rarely been a more compelling time to drill than today. This conclusion is based mostly on detailed comparisons of today's unit economics with other periods of relative industry strength, as well as numerous interviews with company managers that have weathered several cycles. For example, a bread-and-butter Cherokee-age development play in western Oklahoma is currently generating an estimated pre-tax internal rate of return between 30% and 40%, including the cost of dry holes. By comparison, returns from this play during the mid-1990s, an acknowledged period of industry prosperity, were only 10% to 15%. A big part of this difference is higher natural gas prices, to be sure, but that is offset to some extent by an approximate 50% increase in drilling-rig dayrates. But faster drilling times, mainly the result of improved drillbit technology, have mitigated roughly half of the impact of higher dayrates between these periods. Companies currently drilling in this play include Cimarex Energy and St. Mary Land & Exploration. Another good example is the Red River oil play in northeastern Montana, where advanced 3-D seismic interpretation has enabled some operators to match structure with porosity development in the reservoir. This technique has dramatically improved drilling success rates in this play, increasing from around 15% in the mid-1990s to almost 90% for some operators in the past few years. Even with oil in the $30-range, pre-tax internal rates of return from this play have exceeded 100%. By comparison, the Red River was viewed as a marginal play by most operators during the mid-1990s. St. Mary Land & Exploration and Whiting Petroleum are active drillers in this region. Acquisitions have become increasingly expensive, even though some niche players continue to successfully make accretive purchases. More often than not, however, acquisitions are necessary to replenish drilling inventory, especially for companies that don't have enough quality acreage to consistently grow through the drillbit. Indeed, very few E&P companies are capable of sustaining a reasonable rate of multi-year growth (5% to 10%) without acquisitions. So even though most industry professionals would agree that now is a great time to drill, most companies are constrained by their existing inventories-and may have to make acquisitions anyway. Previous cycles Understanding the relative strength of today's drilling climate gets easier when it's compared with other so-called booms in the industry. Prior to 2000, the last real boom in the oil patch was about 25 years earlier: the five-year period from 1976 through 1981. Driven by rapidly changing events in the Middle East, the average U.S. wellhead price of crude oil during that time increased four-fold, from about $8 per barrel to almost $32. Average domestic natural gas prices, which were regulated at the time, increased from only $0.53 per thousand cubic feet (Mcf) in 1976 to about $2 by 1981. The U.S. rig count increased from a relatively robust 1,658 rigs in 1976, when about 41,000 wells were drilled, to almost 4,500 rigs by 1981, when almost 92,000 wells were drilled. Prices and costs were escalating so fast during this period that it was almost impossible to measure investment returns. By 1980, almost any drilling prospect was a good one and Wall Street was pouring money into the industry at a record pace. Some industry participants believed oil would reach $50 per barrel by 1985 and $100 by the end of the decade. The cycle reversed itself when oil prices began to roll over in 1982, due largely to a confluence of declining demand and excess capacity. By 1986, due to Saudi Arabia's decision to "increase market share," the average wellhead price of domestic crude cratered to only $12.50 per barrel from about $24 in 1985. Average wellhead gas prices, which were in the early stages of deregulation during the mid-1980s, declined from about $2.50 per Mcf in 1985 to $1.94 in 1986. It wasn't until 1990-91 that the industry had its first taste of recovery, although brief, when "Desert Storm" drove the average U.S. wellhead oil price back up to $20 per barrel. But gas prices, which were largely unregulated by the early 1990s, had pulled back to $1.70 per Mcf. The rig count, which had recovered from the very depressed levels of the late 1980s, peaked at around 1,000 in 1990. Oil prices pulled back sharply during the next few years, declining to about $13 by 1994, while gas moved up only marginally, to about $1.90. Upstream investment returns were generally negative during this period, even though costs remained relatively depressed. Driven by a recovering U.S. economy, the price of oil in 1996 had moved back up to about $18, while gas prices moved up to an average of $2.17. This was the first sustained period of positive investment returns for the industry since the late 1970s, and Wall Street welcomed this "new era" with massive amounts of equity capital. Average industry after-tax rates of return during 1994-97, however, were only about 7%, well below what Wall Street believed the industry was achieving. This new era of prosperity would only last until the end of 1997, when OPEC, believing that world oil demand would continue to rise, made an ill-advised decision to increase output 10%. On the heels of this near-fatal move, an unrelated economic debacle in Asia caused world oil demand to plummet in early 1998 and oil prices cratered again, this time to less than $11 per barrel. Gas prices, which had moved up to average about $2.35 per Mcf in 1997, pulled back to $1.96 in 1998. Not surprisingly, the modest investment returns of the mid-1990s turned sharply negative. Even though the events of 1998-99 were virtually outside the industry's control, Wall Street labeled this period the "Capital Destruction Phase," a nomenclature it continues to use to this day. Based on what we know today, however, this was probably the most opportune time in the history of the industry to make acquisitions. The 2000 boom The year 2000 marked the beginning of the current boom in the oil patch. Wellhead oil prices averaged $26.72 and gas had moved up to $3.69. In late 2000 and early 2001 there were the first tangible signs of an impending North American gas shortage, culminating in an average wellhead price of $6.82 per Mcf during the first quarter. Still nursing its wounds from the capital-destruction phase, Wall Street was reluctant to jump in. Fixed-rate debt was being issued to finance acquisitions, but new equity capital was hard to come by. By the second half of 2001, a mild recession, high prices and rising gas supplies from increased gas drilling began to depress North American demand. Gas pulled back below $3, where it remained through the first half of 2002, and oil prices dropped below $20, due largely to the events of September 11. Was this the beginning of another down cycle, or merely a temporary pullback in a supply-constrained market? By the beginning of 2003, gas prices had moved back up to the $4-to-$6 range and oil prices were north of $30. After-tax returns had risen to double-digit rates for the first time since the late 1970s. How good is this cycle? The accompanying chart sets forth a summarized comparison of unit economics and after-tax returns for a universe of 30 E&P companies during 1994-1997 and 2000-03, respectively. The same data for 2004 is projected based on estimated results through the first nine months of the year. As previously mentioned, estimated after-tax returns during the mid-1990s were only 7%, well below the combined cost of debt and equity capital issued during that period, which was between 10% and 12%. By comparison, estimated after-tax returns more than doubled to 15% during the 2000-03 cycle, an era of declining interest rates and relatively cheap capital. Even though finding and development costs had increased more than 80%, net margins were up more than 100%. Translation: although comparable in terms of percentage change, the top-line impact of higher oil and gas prices dwarfed the bottom-line impact of higher costs. Even more striking is the forecast for 2004. Based on a projected average realized price of $35 for oil and $5.50 for gas, the 30-company universe will generate an after-tax return of approximately 25%. This assumes an approximate 30% increase in unit production costs and a 15% increase in finding and development costs, versus the 2000-03 period. Oil and gas prices in 2004, however, were projected to increase about 40%. Even if oil and gas prices declined to $25 and $3.50, respectively, and finding costs remained the same, I estimate after-tax returns would still approximate 10%, a minimum hurdle rate for many companies. It's a great time to be in the oil and gas business-especially if one has a large inventory of low-risk drilling prospects. Yes, oil-service costs have increased and continue to escalate. But service costs, in percentage terms, have not kept pace with wellhead prices. Unless they escalate at a significantly higher rate than prices, after-tax margins should remain very strong. For example, oil-service costs have increased approximately 20% in the past 12 months. This compares with an approximate 40% year-over-year increase in the spot price of oil and no significant change in the spot price of natural gas (as of mid-December 2004). And finally, dramatic improvements in technology during the past 10 years have made the industry more efficient. Horizontal drilling, advanced processing of 3-D seismic data, multi-zone completions, new fracture-stimulation products and enhanced drillbit technology are just a few of these innovations. These productivity advances, in some cases, have more than offset the impact of rising oil-service costs and are likely to continue in the future. M Greg McMichael retired last fall after 16 years as an award-winning sell-side analyst, most recently as head of energy equity research for A.G. Edwards in the firm's Denver office. Before becoming an analyst, he was the chief executive of a private E&P firm.