Most of the largest publicly traded oil and gas companies in the world are either U.S.-based or maintain large-scale operations in the U.S. and are widely traded in U.S. public equity markets. Most of these companies have grown their U.S. operations into both the epicenter of and their catalyst for growth. Therefore, there is a great deal of analyst and investor interest in how these companies' U.S. operations are performing. Yet, all these companies have assembled unique portfolios and managed their U.S. businesses quite differently. Some keep 100% of their operations in the U.S. while others' domestic operations are as little as 10% of their worldwide upstream activity. Some have chosen to diversify through international exploration and production; others continue to invest in the U.S., perhaps diversifying through midstream and/or downstream operations. Some have continued to successfully grow their U.S. positions, while others have, through conscious decision or lack of opportunity, continued to shrink their U.S. positions. This article examines the results of upstream operations in the U.S. during the last few years for two peer groups-the majors and the large U.S. independents-with a review of their publicly reported financial and operating data. (See chart.) At the time this article was written, 1999 data was not available. With data through 1998, company trends can be analyzed and review is possible of performance during the high oil-price environment of 1996 as well as the unprecedented low price environment of 1998. 1998 data also allows us to examine individual company performance prior to the megamergers. The reader can see the strengths and weaknesses of the acquirers and the acquirees and gain a fuller understanding of why some of these transactions occurred. Oil price volatility, environmental issues and the pressures of megamergers all affect how these large companies view their U.S. operations. Total shareholder return for the industry has not kept pace with the broader markets. (See tables 1-A and 1-B.) Of the companies shown, only BP Amoco's return exceeds the five-year S&P 500 average return of 26% per year. Only BP Amoco, Exxon Mobil, Repsol, Royal Dutch/Shell, Coastal Corp. and Vastar Resources top 20% per year. Many of the majors have delivered single-digit returns and many of the independents, negative returns. The historical return levels in these graphs lead us to ask why investors choose to invest in this business, especially in light of the huge returns on equity in the technology and Internet sectors. While the tech-heavy Nasdaq composite generally kept pace with the Dow and S&P 500 from 1995-98, it was up a whopping 86% in 1999! Reserves Metrics that demonstrate size (i.e. total reserves, production, earnings, cash flow and capital) and efficiency (i.e. reserve growth, production growth, earnings and cash flow per barrel, and finding and development costs per barrel) will be discussed. We have examined the time period of 1996-98, prior to the recent merger frenzy. With the exception of BP Amoco, all the data shown is premerger, as no other large deals closed in 1998. (BP and Amoco combined and restated all their reporting in 1998.) From this data, certain performance issues are apparent and show why companies may have found one another attractive or why companies were compelled to sell. Note that most companies do not fully report detailed affiliate data (exceptions are Exxon, Chevron and Texaco) so data from large U.S. joint ventures such as Aera (Shell/Mobil) and Altura (BP Amoco/Shell), which Occidental is buying, is not included in the numbers. Since we are analyzing, for the most part, only a portion of a company's operating and financial performance (its U.S. business), which indicators should be examined? The best place to begin is with reserves. This is what an oil and gas company has "in the bank" to draw from and monetize through production. Let's begin by examining reserves for the majors. (See Table 2.) The table shows year-end reserves (on a barrel-of-oil-equivalent-BOE-basis, with gas converted to oil at a 6:1 ratio), a five-year average per-year growth rate, and the year-end 1998 percentage of company reserves in the U.S. The last indicator is a proxy to demonstrate the relative size of each company's U.S. business to its worldwide business. In a relative sense, what effect does the U.S. business unit have on total corporate performance? This is quite variable, ranging from 67% for Marathon and Arco down to 9% for Royal Dutch/Shell. In terms of reserves, the sizes of companies within the peer group varies a great deal, from BP Amoco with 6 billion BOE and Exxon with 4 billion to Mobil, Marathon, Phillips, Occidental and Conoco, each with less than 1 billion. The relative size distribution does make a difference in ability to make large percentage changes in indicators such as reserves and production. The larger the size, the more likely yearly changes on a percentage basis will be smaller (but on an absolute basis can be very large). The only companies that increased reserves in the U.S. in each year shown were Exxon and Texaco. Texaco's reserve additions were driven to a large degree by the 1997 purchase of Monterey Resources, a company originally spun off from Santa Fe Resources. This deal and Oxy's Elk Hills purchase were by far the largest acquisitions in the peer group during the five-year period. With a tiny (yet absolute) increases in reserves, it appears as if Exxon established a goal to replace (and slightly grow) reserves in the U.S. every year. Mobil and Shell reported the largest per-year average decreases in size. Much of this was due to their formation of joint ventures (Aera and Altura), some to asset sales, and some to natural decline. Shell's reserve decreases are partially offset by reserve additions in deepwater Gulf of Mexico. In general, this peer group acquired and sold relatively few reserves. The percentage of reserves sold ranges on the high end from Conoco with 5.4% per year for the five-year period to Arco's 0.3%. As for the acquisition of reserves, the rate is negligible except for Oxy's 19.6% per year, which is mainly due to its Elk Hills acquisition, Texaco's 4% (Monterey Resources), and Conoco's 3.2% (South Texas gas). Looking at the reserve data for the independents yields much different results. All except Amerada Hess and Unocal showed positive reserve growth for the five-year period. Interestingly, both Unocal and Amerada Hess were once considered majors, hence still may have acted like and operated like majors. Unocal sold its downstream businesses (but still has a small portfolio of diversified businesses) to become a self-proclaimed superindependent. Amerada Hess is included with this peer group due to its size in the U.S. Seven of the 16 companies (Anadarko, Coastal, CNG, EOG Resources, Louis Dreyfus, Ocean Energy and Vastar Resources) increased reserves every year. The size of their U.S. reserves versus worldwide vary from 100% U.S. to 29% (Amerada Hess). Mainly through acquisitions, the independents attained huge reserve growth. On average, this group acquired more than 10% per year of their reserves; the majors averaged 3% per year and only 1% if not for the gigantic Elk Hills purchase. The most acquisitive were Nuevo (31% more reserves acquired per year), Pioneer, Coastal, Apache and Ocean Energy. Not surprisingly, the least acquisitive were Unocal and Amerada Hess, the two former majors, at less than 1% each. In terms of divestments, the group averaged 3% per year, with Sonat, Apache, Unocal, Pioneer and UPR being the most active. Anadarko, CNG and Vastar all sold less than 1% of their reserves. In terms of portfolio turnover, Apache and Pioneer had the most active programs, buying and selling the most properties. How much of an effect do U.S. operations have? The majors' reserves are 45% U.S., on average; the independents, 75%. Therefore, U.S. performance is meaningful, but not the whole story. Production Among the majors, only Marathon and Texaco were able to increase production each year in 1996-98 and only Marathon, Oxy and Exxon had a positive five-year average production growth. (See Table 3.) Texaco's increase was driven by the Monterey Resources acquisition and Oxy's was driven largely by its Elk Hills acquisition. Mobil showed the largest decrease in yearly production, largely due to the exclusion of Aera joint-venture production in its public reports. Much of Shell's U.S. production became part of the Aera and Altura joint ventures, yet the company still averaged only a 1.5% annual production decrease, due to new deepwater Gulf of Mexico volumes. To tie reserves and production together in this discussion, the year-end 1994 and 1998 R/P ratios are also shown. This is a ratio of reserves (on a BOE basis) to yearly production (also on a BOE basis) and can be used to estimate how quickly a portfolio is being depleted. Changes from 1994-98 can also be examined. Oxy, Texaco and Exxon show significant increases. Oxy and Texaco made large acquisitions. The Exxon increase is interesting as it cannot be tied to a single large event, and its size is quite significant, 1.3 years on an already large reserve and production base. Meanwhile, Marathon and Shell showed the largest R/P decreases, with Shell's due to the exclusion of Aera and Altura reserves and production. Most other R/P ratios changed by less than one year. Once again, the independents had quite different results in the U.S. than the majors. Ten companies increased their production every year and every company in this group had a yearly five-year average production increase, except Amerada Hess and Unocal. Most of the independents with double-digit production growth also acquired the most reserves in the five-year period. The group also spent more, as a percentage of available cash flow, at the drill bit than the majors spent. (See Table 7.) Most of the independents have changed their R/P ratios by more than one year. EOG Resources has shown the largest increase, followed by Anadarko, Coastal and Nuevo. Notable decreases in R/P have occurred at Burlington Resources, Louis Dreyfus, Noble Affiliates, Ocean Energy, Sonat, UPR and Unocal. The R/P ratios clearly demonstrate how differently the two groups manage their businesses. The much larger businesses of the majors are less volatile, as indicated by more stable R/P ratios and smaller yearly changes in production. The independents have much smaller portfolios but much higher growth rates. Some of the independents have comfortably large R/P ratios while others seem to run with just-in-time inventory replacement programs. Let's now examine how reserves and production performance have translated into financial indicators. Earnings The bottom line from production is earnings, which are Revenue minus Lease Operating Expenses (LOE, including production taxes) minus Depreciation, Depletion and Amortization (DD&A) minus Exploration Expenses minus Taxes and Other Expenses or Charges. Revenue per barrel is a great way to examine the effect of different portfolio mixes (oil to gas and light oil to heavy oil). There is a $2- to $3-per-BOE difference in revenue realization depending on the company's production mix. Operating expenses have probably captured the most attention within companies, because they are an absolutely controllable cost. These vary with the production mix, as well as with how well they are controlled. A great deal of time and effort had been spent in the 1990s on pushing operating costs lower in the mature U.S. Meanwhile, the DD&A rate is a great indicator of the historical success of capital decision-making. The more reserves added per dollar, the lower the DD&A rate. This also varies among the two groups, with a $3- to $5-per-BOE DD&A rate for the majors and a range of $4 to more than $8 for the independents! Showing earnings per barrel is a good way to demonstrate which companies had the most efficient production and to also show how the earnings yield changes over time in the different pricing environments. 1996 is a good year to examine U.S. performance in a high price environment and 1998 is a good year to examine performance in a low price environment. (See Table 4.) Earnings for the majors were most attractive during higher oil-price environments. The oilier companies benefited from the oil-price premium to gas during this time period as well. For many of the majors, the U.S. cash cow was also the earnings champion for the corporation during this period. Earnings of $4 per BOE and higher, with production of 200- to 400 million BOE a year, contributed more than $1 billion to the bottom line in these years! As prices fell in 1998, earnings margins shrunk but most majors were able to maintain positive results. Mobil and Phillips were exceptions. Return on fixed assets Another way to examine earnings efficiency is through return on fixed assets (ROFA), a measure of earnings versus capital invested. (See Table 5.) Once again, the numbers were volatile, and were affected by the commodity-price environment. The five-year average dampens out this volatility and indicates which companies are performing best. The goal is ROFA of 12% to 15%, but the current E&P life cycle in the U.S. makes this a challenge, due to production maturity, low market prices for product and higher costs. The public markets have rewarded independents for cash flow growth rather than earnings growth, so the earnings of independents are generally lower than those of the majors. Also, independents have been able to make acquisitions even though they might have a near-term dilutive effect upon earnings per share. More than half of the group reported negative earnings in 1998, in part due to large acquisitions made by most of those companies prior to 1998. Less acquisitive and more-gassy companies-Anadarko, Burlington Resources, CNG, EOG Resources and Vastar-had decent 1998 earnings. The best performance may have been by Coastal, which was quite acquisitive (it averaged 21% per year of reserves purchased) but also very gassy-a winning combination in its earnings performance. Coastal also enjoys the best shareholder return of the group, something El Paso Energy shareholders expect to benefit from when Coastal becomes part of El Paso later this year. There have been some interesting changes in portfolios, in gas-to-oil in 1994 versus that of 1998. Many of the independents are gassy; only Pioneer and Nuevo had more oil production than gas. Nuevo has made a huge shift from gas, while Ocean Energy has made a huge shift to gas, and each company has done this via acquisition. The independents as a group are decidedly more gassy than the majors; the average independent produces 30% oil, the average major, 50%. Cash flow Cash flow is a key driver of why the majors continue to have significant U.S. operations; it is historically a cash cow for the rest of their business. The U.S. offers low political risk and great leverage in a high price environment, and it is home court for many in the group. For this article, cash flow is Earnings plus DD&A. Once again, cash flow efficiency is demonstrated on a per-BOE basis. The differences on a per-BOE basis among the companies are significant. (See Table 6.) With the average major producing approximately 250 million BOE per year, a $2-per-BOE difference in operating cash flow yields an additional $500 million in cash flow for the company with the higher margin. The average major spends about $1.2 billion per year in capital, so an additional $500 million in cash flow provides more than 40% of the company's annual capital! This is a huge advantage for the better performing companies as they can choose to use this for more capital projects, reduce debt, or any other purpose. Five-year absolute cash flow growth per year demonstrates companies' U.S. growth. With de-emphasis on U.S. operations and the increasing maturity of traditional production areas, it is not surprising that the majority of the majors show decreased cash flow over time. If the U.S. is indeed the cash cow for an oil company, this is putting increasing pressures on companies for alternative sources of cash. For the independents, the story continues to be the same as it has been throughout this analysis. They did very well in 1996-97, but really felt the pressure in 1998, and not as much as the majors. Perhaps because they have been driven by cash flow and cash-flow-per-share growth, their 1998 cash flow did not, on average, decline as much as the that of the majors. Once again because of the expectations of the market, their cash flow margins each year were also generally higher than those of the majors. The cash flow growth treadmill for the independents is a very aggressive one. Most companies grew their cash flow in double-digit yearly percentages and only Amerada Hess, EOG Resources, and Unocal had decreases. This is where their acquisitive nature is also a strength. The real winners know how to both acquire-for the absolute growth-and to improve performance of the total asset base-for the efficiency growth. While the majors averaged $6.50- to $7.50-per-BOE yearly cash flow, the independents averaged $8 to $10 per BOE-quite a difference. There may be some anomalies in these numbers. It's not realistic for Sonat and Ocean Energy to have the 1998 cash flow margins shown on $11 or $12 oil. The margins shown may be due to adjustments for the large acquisitions during this time period or asset write-downs. Capital Spending (Cash Flow Reinvestment Rate) Finally, how much of this cash flow is reinvested in the business? Table 7 shows absolute capital spending and reinvestment rates by the majors and the independents. The numbers include spending for exploration, development and acquisitions. For the majors, the U.S. cash cow is clear in 1996; a huge amount of U.S.-generated cash went overseas, into diversified businesses, to pay debt, to buy back stock, or into corporate treasuries. Most companies in this group made concerted pushes overseas, into areas such as West Africa, South America and the former Soviet Union. In 1996, the majors took $750 million to $1.25 billion from U.S. cash flows for other purposes. 1997 was a little less extreme, as companies began spending more in the U.S.-driven by deepwater exploration and development spending, some acquisitions, and a general increase in U.S. spending with the improved industry conditions due to a very healthy prior year. The results for 1998 are also not very surprising. Greatly decreased cash flow led many companies to reinvest more in the U.S. than they had generated. Texaco's effort to increase volumes led them to greatly increase spending above their operating cash flow capacity, even beginning in 1997. Texaco's goals were for worldwide production growth of 8% to 9% per year, exceeding all of the other majors' proclamations of 4% to 7% production growth. Conoco's spending also greatly increased in 1997 due to its South Texas acquisition. The increased spending of the peer group in 1998 also resulted from greatly increased spending in the deepwater Gulf of Mexico. Some of the companies spending more than 100% of cash flow were Shell, Texaco, Conoco, BP Amoco and Chevron, all among the most active in the deepwater. An interesting exception is Exxon, which spent less than 100% and is also very active in the deepwater Gulf. Meanwhile, Oxy's spending profile was due to its Elk Hills acquisition. The final column in the table is five-year average finding and development costs per BOE. This is the ratio of capital spending to proven reserves added and is an indication of capital efficiency. Those companies that add reserves very profitably do so at a lower F&D rate than those that do not. With the mature fields in the U.S. and taking into account higher-than-normal current capital expenditures in the capital-intense deepwater Gulf, F&D of approximately $6.00 per BOE or less is good performance. Recent acquisitions will generally raise F&D rates, especially if a portion of the acquisition was for unproved reserves. This is certainly what is impacting the Oxy F&D rate. Meanwhile, Exxon has been able to replace reserves every year and grow production while reinvesting much less than 100% of its cash flow in the U.S. with F&D costs of less than $3 per BOE. This is an extremely powerful combination. The independents show extremely high reinvestment rates. They are under pressure to continue to grow cash flow and have invested huge amounts of money on a percentage of cash flow basis into their U.S. businesses. They average 120% to 140% reinvestment rates, hence many of them carry much more debt than the majors since debt is one of the key sources of cash. They also have a wider range of and generally slightly higher numbers for their F&D costs. This leads to higher DD&A rates, hence lower earnings, and is one explanation for the independents' lower earnings margin as compared with the majors. Summary What does all this mean? The historical data can be used to predict future performance. Companies have established definitive management, technical and financial resources, systems, processes, and asset portfolios that have yielded the results shown. One logical presumption is that, without wholesale changes or anomalous events, these will continue to yield similar competitive results; companies with good performances are likely to continue to produce good performances. This is not an absolute. Every one of these companies is continuously trying to improve its performance and are examining all options. In summary, who's the best? The worst? It depends on the perspective. Start with the historical shareholder returns. That is the current scoreboard of who is winning and losing. Who has had repetitively good or poor results in each indicator? 1999 results have been released by now. It will be quite interesting to look at how companies have performed through the price whiplash of 1998 and 1999. M William A. (Bill) Marko, formerly of Navigant Consulting Inc., Houston, is now working with Madison Energy Advisors Inc.