Proved oil and gas reserves are elusive to define, and proved undeveloped ones even more so. Not all are created equal; not all have equal value. Some are more easily counted and sooner produced than others. Yet as they form the backbone of any E&P company, they invite increased scrutiny on the part of investors and regulators. Following Royal Dutch/Shell's write-down of 20% of its reserves in January, six other companies have followed. Their reasons vary. Forest Oil, Vintage Petroleum, Nexen, Husky Energy, El Paso and Western Gas Resources wrote down proved reserves because some of their wells' performances have not lived up to previous estimates of ultimate recovery. Underneath the headlines, the doubts and the call by some to change the way reserves are calculated, some truths emerge. The failure of single oil and gas fields or some projects to live up to early reserve estimates is inevitable. Delay or cancellation of a critical oil or gas sales contract can push new reserve bookings to the back burner until a project becomes commercially viable and income is visible. Low amounts of proved undeveloped reserves could mean an E&P company hasn't been finding much lately and has no new ideas. Or, it could mean that a massive capital spending program for production facilities has finally converted those PUDs into the proved producing category, so cash flow is about to improve. Investment-banking and research firms have been eager to weigh in on this topic for the benefit of clients, who have many questions. Petrie Parkman & Co., Simmins & Co. International and JP Morgan Chase hosted conference calls to address the ins and outs of reserve reporting and the role of the Securities and Exchange Commission. "While we certainly do not see an epidemic breaking out, we also do not believe that all the shoes have fallen," says Petrie Parkman & Co. analyst Steve Enger in a recent report. "A company's culture and bias around the reserves booking and auditing process are critical to avoiding broad reserve write-downs, A culture that supports the technical staff...and a bias to be conservative rather than aggressive are key ingredients." "We do believe more specific SEC guidelines and more uniform booking practices across the industry are likely minimum outcomes," say Mark Meyer and Ryan Zorn of Simmons & Co. International. They point out that generally, the shares of companies that wrote down reserves continue to suffer the ill effects. Calls for action JJ Traynor, managing director and global head of oil and gas research in London for Deutsche Bank, sent an open letter to the SEC in March asking the agency to clarify its rules and explain why it has not updated them to reflect new industry practices and technologies. Probably the most specific and far-reaching call for reform comes from Ron Harrell, chief executive officer of respected engineering firm Ryder Scott. He is calling for voluntary dialogue on enhancing and codifying industry standards. He proposes certification of all engineers charged with reserve analysis or audit, with study, examinations, recurring education and certification by some new or existing agency, for engineers and petroleum geologists. "We now have an environment that demands higher standards throughout the energy industry and particularly in the oil and gas industry. We should act before the U.S. Congress or another authority orders us to do so," Harrell says. He has contacted the Society of Petroleum Evaluation Engineers and the American Association of Petroleum Geologists, as well as the Society of Petroleum Engineers, which already offers an approved document that outlines standards pertaining to estimating and auditing oil and gas reserves. Enger at Petrie Parkman says, "We encourage companies to provide greater detail on their reserve bases, particularly the proved undeveloped (PUD) portion. The vintage of those PUDs, geographic/project-level detail on the major components, and the capital cost required to develop the PUDs would all increase transparency in what has traditionally been a murky set of issues." Anadarko Petroleum Corp. has won kudos for delivering such detail to investors just a few weeks ago. Jim Hackett, its new president and chief executive, wants to be seen as a leader in this respect, so as keynote speaker at the annual Howard Weil investment conference in New Orleans last month, he spoke not about the company's activities, but about reserves issues. "This discussion [on reserves] is long overdue. But we need to look beyond the fevered pitch and focus on our internal processes," Hackett told about 400 investors, buyside analysts and upstream executives. "Management integrity is key-outside engineers don't sign the reserve report, management does, and they risk losing their reputation, their jobs, even their freedom." Management cannot abdicate its responsibility, he added. No consultant should know a company's properties better than internal technical staff. "This is all about technical estimates, but only God knows how much is really there." Anadarko's 150 staff engineers estimate reserves for every well, every year. Division vice presidents review and approve the data and question all assumptions before the numbers are submitted to an internal reserve review team consisting of four experts separate from the divisions. A fifth member is a senior vice president of engineering and consulting firm Netherland, Sewell & Associates. Anadarko hired the latter in 2003 to review its reserve processes. It reviewed 70% of the company's 2003 reserve additions, as well as about half of its existing reserve base. Hackett said Anadarko has changed its compensation system so that the five-man team will remain unbiased and not receive bonuses based on upward reserve revisions. "Our board member who heads the audit committee suggested this. I thought it was brilliant-I made the change the very next day," Hackett said. Anadarko's board is scheduled this month to formally ask the company's audit committee to hire the independent external reserve engineering firm, just as it hires external financial auditors each year. No longer will management be the employer-the board will. Company specifics Anadarko, Unocal and Kerr-McGee use procedural audits or reviews. EnCana Corp. in Calgary has 100% of its large reserve base externally determined. Most other public companies use varying degrees of external input. But the question is, do the external experts use maps and data provided by the E&P client, or do they do their own geological interpretations? Currently there is no standard. At every presentation it makes to investors, Ultra Petroleum seems to show increased per-well reserves and company totals from its Pinedale Anticline Field in Wyoming. Its year-end 2003 reserves reached 1 trillion cubic feet, up 53% from 2002. "We believe the risk profile of our reserve base has been reduced [based on 2003 drilling results]. In accordance with Ultra's three-year planning and budgeting cycle, proved undeveloped reserves include only economic locations that are direct 40-acre offsets to producing wells and are forecast to be drilled and on production during the next three years," the company explained in a press release announcing 2003 results. The company and others in this play are drilling on 20-acre spacing and have test wells under way on five- and 10-acre spacing, says chief executive Michael Watford. If these new wells succeed and indicate a new amount of reserves is recoverable, then a whole new set of proved reserves will be counted. Anadarko has a lot of proved reserves to count-2.5 billion barrels of oil equivalent (BOE) to be exact. During the past decade, its revisions not related to commodity-price changes have averaged a positive 0.2% of estimated total reserves. Its asset base is also diversified, a measure of risk reduction, with only 7% of total proved reserves concentrated in its largest field. In its recent disclosures, Anadarko made a point of "vintaging" its reserves. It said the bulk of its 2003 reserve additions can be converted to proved developed reserves in 18 to 24 months because they were made in North America, where existing infrastructure speeds up the time to production. Arctic Alaska satellite well tie-ins, deepwater development and some international programs will take longer, and likely will require larger capital outlays. High levels of PUDs can be a warning flag if an E&P company lacks the capital to drill and produce them, or there is a timing delay. This is what stymied Callon Petroleum in the past two years. It had a meaningful working interest in some deepwater finds that were to catapult the company's production upward, but it had to wait longer than expected for the operator to bring the wells onto production, a situation over which it had no control-but which required capital outlays. Anadarko and Marathon deserve credit, says Enger, for telling investors the vintage of their PUDs and their plans for moving them into the proved producing column. Some companies have a large percentage of PUDs for a good reason. Enger points to Unocal. It has been waiting on the Thai government to certify the commerciality of a gas field offshore Thailand, in which case it will be up for consideration for the next gas-sales contract the Thai will grant. Enger cautions that no two companies are the same. "We were surprised to see that over the past decade, since year-end 1992, there has been a wide range of revisions," from 60%-plus for Occidental Petroleum and Murphy Oil, to negative 14% for Marathon. Marathon reported negative revisions for four consecutive years as new senior management transitioned in the 1998-2001 period by reevaluating and selling oil and gas reserves. "We're clean as a whistle now," says a spokesman. New kinds of reserves Companies must report their reserves under SEC guidelines established in 1978 and interpreted by the Financial Accounting Standards Board (FASB) in 1982, and by SEC reports issued in 2002. Meanwhile, companies' understanding of those reserves has changed greatly due to new drilling and completion technologies, seismic data and reservoir modeling software. "Technology has not stood still in the meantime," Kenneth Chew, vice president, upstream information-services firm IHS Energy, said in a March interview with the European Association of Geoscientists and Engineers' journal, First Break. "Advances in seismic such as 3-D, 4-C and direct hydrocarbon detection, the use of huge computing power to make reservoir simulations, and probabilistic calculation methods all allow far greater precision in establishing in-place and recoverable hydrocarbon volumes than was possible a quarter century ago." Netherland Sewell points out that in some regions where new technologies are brought to bear, or unconventional formations are being developed successfully for the first time, reserves are difficult to evaluate. Examples include South Texas, where new frac techniques have changed the landscape. This in part contributed to El Paso's recent reserve write-down of 41% of the total. Meyer and Zorn at Simmons & Co. reviewed South Texas gas wells and found that initial daily production rates nearly doubled for wells drilled in 2000, versus wells drilled in 1995. First-year decline rates rose from 30% for wells drilled in 1995 to 75% for 2000-vintage wells. These factors will influence ultimate reserve recovery estimates. "We've said before that not all reserves are created equal," says an analyst with Merrill Lynch. "The PUDs being booked by industry are of lower quality-i.e., higher development cost-than the proved developed reserves. "This was confirmed by Royal Dutch's announcement: the 20% reserve decline (totaling 3.9 billion BOE) resulted in only a 10% PV-10 decline, as the removed PUDs were lower-margin reserves. Estimated future costs [a part of the reserve calculation] had remained relatively constant for a long time until rising recently and have probably been underestimated, in our view." Booking a PUD prematurely is like counting on a stock to go up before it actually does-you can't book that and take it to the bank. Sources say that in general, any PUD that remains booked but not converted to proved developed producing (PDP) status in three years should be reexamined by the company-if not by investors. In the Barnett Shale and Powder River Basin coalbed-methane plays, reserve booking has had to occur slower than one would expect elsewhere, if one follows the strict interpretation of SEC rules that say only reserves one well location away from a producing well can be booked. But spacing concerns vary from field to field. Western Gas Resources "unbooked" some 30% of its year-end 2002 Power River Basin coalbed reserves because close-in well spacing was apparently not recovering what was expected. The mere physical attributes of reserves-being miles below the surface-make precision an impossible standard to achieve, note Meyer and Zorn. Likewise, a barrel of oil produced in a waterflood in the Permian Basin is not going to be measured the same as a rapidly declining gas well in South Texas. "And, increased frontier activity on the part of many companies can introduce additional ambiguities beyond basic technical uncertainty...." VOLUMETRIC ESTIMATES Volumetric reserve estimates can be very imprecise, based on the tools used and the frame of mind of the engineer making the estimate. The pool of oil is assumed to be roughly the boundaries of a lease. Say it is 160 acres, or one-half mile per side. An optimist would assume all the oil under the lease can be recovered from a square pattern. A more cautious engineer might assume the drainage of oil would be less, and would occur in a circular pattern-meaning only about three-fourths of the drainable area. Similar differences can be found in log measurements. A density log run on the test well could reveal a pay zone 18 feet thick, while an electric log used to gauge water saturation shows only 12 feet-two-thirds as much pay as in the first instance. Uncertainty continues when porosity is gauged. A neutron log shows 16% porosity of the rock, while a density log shows only 10%. This measures the amount of oil, gas and water that is stored in the pores of the rock. Two other different types of methods to test how much hydrocarbon is in the rock make the results equally unclear. Log analysis using water samples points to a saturation of 0.50 while a different log shows saturation of 0.80. Finally, an engineer must guess how much water pressure there is and what amount of oil can thus be recovered as the water moves and drives the oil to the well bore. He could assume 25%. But if there is no water and he has to rely on gas pressure to drive out the oil, he might estimate only 10% of the oil in place can be recovered. There is no easy answer.