Energy consumers, politicians and investors are becoming increasingly concerned about the resources available to supply energy for our transport, industry and homes over the coming years. Across the globe, there are alarming inconsistencies and a lack of clarity and transparency in the way oil and gas reserve numbers are estimated and reported. These somewhat arbitrary figures are used and compared by widely different audiences, with varying perceptions of their real meaning, to draw conclusions about the capacity of  future production to meet growing demand or about company earnings and value. The results may be deceptive.

After two years of dramatic reserve downgrades by oil and gas companies, investors and market regulators would like more reliable and accurate information to assess the value, prospects and future cash flows of energy companies. With depleting domestic reserves, tight supplies, high and volatile prices and perhaps some risk of shortages, governments and others charged with developing and keeping up the smooth flow of oil and gas are reassessing what measures they can take to ensure a reliable, cost-effective supply of energy to keep their economies stable and growing. Proved reserves, as currently stated by many countries and companies, provide a very incomplete picture of either likely production profiles or value.

We need more reliable, consistent and useful information about available supplies of these key energy resources as the world becomes more interconnected and society more complex. What oil and gas resources really exist, and how attractive are they to invest in and bring to market?

To address these questions and to ensure that the main reserve holders and key regulators move toward using the same consistent method, a single, strong, workable, global standard for making reserve estimates is urgently needed.

Energy consumers are aware of the growing debate over whether sufficient oil and gas reserves will be available quickly enough to keep raising production to supply demand. The world already uses over 30 billion barrels of oil each year. If demand continues to grow at around 2 percent a year, how long is this sustainable?

Since 2000, explorers have been finding fewer and fewer new reserves. The world may have reached the point where new discoveries, even with expected subsequent reserves growth from field development, hold less than is used each year. The amount recognized will depend on technology and how we assess what’s there.

National oil companies (NOCs) control around three-quarters of the globe’s known conventional reserves. Highlighting the pressing need for better information are recent suggestions by energy investor Matthew Simmons, Petroleum Intelligence Weekly and others that the reserves of such "closed" holders of large resources, such as Saudi Arabia, Kuwait and others, are significantly overstated. This was the also the case with Mexico’s known reserves before outside auditors were invited in.

The basis for most of the 300 billion barrels of increased reserves declared by the Organization of the Petroleum Exporting Countries (OPEC) during the mid- and late 1980s is still not clear – and that was when OPEC was agreeing its quotas. Nor have the larger Middle East producers subtracted what they have produced since – around 110 billion barrels!

Stated global proved reserves have continued to increase over the last 10 years, mainly from deepwater and areas like Qatar and the Caspian, but reserve-to-production ratios, although apparently long, are now beginning to fall.

The market is driven by perceptions. Clearly the major producers have their own agendas to maximize their income by balancing price and sales volumes, and to avoid triggering a premature switch from oil to other sources of energy. Most of the world’s larger oil fields have been producing for around 40 years, and infill drilling yields less and less additional production.

How long can producers keep adding (or signaling) enough new field development to meet global oil demand if it continues to rise at 1.5 to 1.8 million barrels per day (mmb/d), or an extra 600 million barrels each year? Higher prices may yet choke back demand, as they did between 1980 and 1985, when demand for OPEC oil fell from 30 to 15 mmb/d. Still, many expect demand for Middle East oil to grow by 20 to 30 mmb/d by 2030, and more from OPEC as a whole. If this happens, could production capacity be increased in time, and for how long?

The intense debates about how close we really are to peak oil production – the halfway point, after which supply tends to fall inexorably – would be better informed with more transparent and reliable reserves information. This point may have been reached by some countries, such as the United States, Indonesia, Oman and the United Kingdom. But we have been here before and several times since 1914, when the U.S. Bureau of Mines said there was at most a 10-year supply remaining. Technology, as it has before, may well usher in new plays, deeper imaging, cheaper drilling or better recovery.

With higher oil prices and improved technology, some oil sands projects are moving forward despite their high environmental impact and a cost of about $25 per barrel, and so now clearly hold recoverable reserves. Taking these into account, Venezuela and Canada might move to first and third in global reserves rankings, pushing Saudi Arabia to second place. Canada’s estimated 170 billion barrels in oil sands could supply the world for five years.

The ongoing peak debate led by geologists and reservoir engineers should perhaps focus on how soon conventional production may start to decline from all the existing major non-OPEC and non-Russian basins. The global issue can better be addressed once more consistent and accurate reserves data become available from these other sources. The conventional peak from stable sources may occur sooner than expected.

Global production capacity has been tight since 2004. Ongoing political threats to oil supplies from Iran, Iraq, Nigeria and Venezuela, along with gas shortfalls from Russia, have raised prices this winter. Storage accidents and regional shortages of diesel, jet fuel and other key products have highlighted the problems facing consumers.

Indeed, as the U.S. Energy Information Administration said on its Web site in early March 2006: "Continued steady world oil demand growth, combined with only modest increases in world spare oil production capacity, and the continuing risks of geopolitical instability, are expected to keep crude oil prices high through 2006." After a period of cautious investment, perhaps fearing the price will fall back significantly, oil companies and most consumer countries are now pushing hard to secure their upstream supplies.

In Western capital markets, one key indicator of future growth is the rate at which companies replace or add new "SEC proven" reserves – those allowed under current Securities and Exchange Commission rules – to make up for the barrels they produce. Most companies are finding such replacement increasingly tough, and their slow or nonexistent production  growth reflects this.

Overall reserve replacement from new exploration and development (rather than from acquisitions or signing long-term contracts for liquefied natural gas) is falling for many oil companies, leading to a greater focus on mergers and buying assets. Organic replacement is probably worse for the national oil companies.

How reliable are reserves as a guide to future value for investors? Not all barrels are equal; different areas and resources, from sweet light to tar sands and coal-bed methane (CBM), have very different costs and timing to market. In many fields, the reported or "booked" proven figure is well below (and not necessarily a good guide to) the internally expected ultimately recoverable reserves in the early stages of development and even production, and the major economic decision to develop the field is not based on the booked figure. Economic decisions are driven by internal best estimates – usually probabalistic ranges, with stage gates of further investment in seismic and drilling to reduce the uncertainty in the range.

What investors and analysts really want to know is how well a given company is doing and how its portfolio of future opportunities looks. We should note that many other industries – from timber or food to pharmaceuticals – are not required to provide full details of their opportunity or raw-material inventory, or indeed of their research-and-development portfolio or other assets, which may be commercially sensitive. In oil and gas, more IOC/NOC (international/national oil company) contracts are likely that do not offer any kind of reserves ownership, but instead, in differing forms, valuable margins and cash flows from the investments made.

To get a fuller picture, investors might want progressively better breakdowns of not just booked reserves, but also the expected recoverable resources, expected production profiles and costs, risks, net cash-flow margins and the value created for the investment made. At analyst meetings, senior management may indicate the number of prospects they plan to drill in highprofile basins or perhaps some gross estimates of the undrilled potential available in these areas. Clearly, proved reserves alone are a poor indicator of company or shareholder value.

The key need seems to be a single, agreed method of evaluating reserves, enabling more clarity and a better understanding and comparison of resource information. This would provide a more open and transparent investment framework for energy users and providers to ensure a stable flow of reliable and affordable energy.

Problems and solutions alike were discussed at an interesting and useful meeting hosted by the Energy Institute and American Association of Petroleum Geologists (AAPG) in February. SEC reserves are based on a set of U.S.-focused definitions made from 1978 to 1982. They rely on deterministic methods to assess "proven reserves" recoverable "with reasonable certainty," but the SEC refuses to specify at what confidence level. This vague phrase can be interpreted as anything from over 50 percent to 95 percent, while most professional bodies and companies focus on 90 percent. The SEC definitions do not reflect what modern imaging technology and subsurface modeling can now show.

How reserves are assessed and then depreciated can have a big impact on taxable income and tax due. In the United States, the SEC rules, which apply to all companies wanting a listing on a U.S. exchange, now appear outdated and parochial. Little has been changed since 1978 when the rules were set, except the SEC now allows reserves defined by 3-D seismic. Still, even this provision features a disturbing inconsistency: Such reserves are allowed only in the U.S. deepwater Gulf of Mexico, and not offshore elsewhere.

Inconsistencies in definitions can lead to invalid comparisons. The SEC’s exclusive focus on a single deterministic "proven" reserves estimate ignores the real range of underlying resource potential and promotes incomplete consideration of the geological, engineering, commercial and price risks. These risks have a major impact on possible outcomes of reserves, production, capital and operating costs, project feasibility, timing, margins and value for oil and gas projects.

Probabilistic estimated ranges recognize inherent uncertainties in recovering these hidden reserves better than a simple, single deterministic figure. The lack of rig availability is also now causing near-term difficulties in testing and appraising many offshore prospects and discoveries. The United Kingdom’s Financial Services Authority (FSA) rules, updated in July 2005, have a different, more transactional focus and appear somewhat more pragmatic and flexible, based on a fuller set of inputs and more modern estimation techniques.

Changing prices can also dramatically change an investor’s volume of proven reserves under production-sharing contracts with host countries. With higher prices, less oil is needed to cover costs, so less of the production is assigned as an investor’s "cost oil," and the host government takes a higher share. SEC rules require reserves to be technically recoverable and economic at the prices and costs prevailing when estimates are finalized, so the estimates are based on a single day’s price, not an average of the previous year. This is usually the last day of the accounting year, and low prices on that day can remove or add reserves arbitrarily – as recently happened when some Canadian companies had to reduce their heavy oil bookings significantly. Perhaps the average of the last four to twelve months or an agreed outside price forecast would be a better indicator.

More investment and production of less-conventional oil and gas resources is expected. We have much less experience in estimating how much of these resources we may recover. SEC rules currently prevent companies from including some Canadian oil sands in their reported reserves. How should we set the rules for various types of unconventional resources?

There is a pressing need for consistent criteria to address these uncertainties, with enough flexibility to adapt sensibly as technology continues to advance in improved recovery, imaging or reducing costs. Different rules exist in the United States, the United Kingdom, Norway, Australia, Canada, China and Russia, some with very different philosophies, sets of definitions and reserve-reporting requirements. Much of the Middle Eastern reserve question may come down to differences in definitions of production capacities and stated reserves.

Different audiences have differing needs in terms of standards. Some have less understanding of reservoir geology and how reserves are recovered, and therefore less understanding of how to interpret reported reserve figures. It is important for those who seek to communicate forward-looking information on expected reserves – from a field, a basin or a country – to do so in a way that clearly sets out the inherent uncertainties.

A good standard might be close to that put forward by the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC) and AAPG, with a universal system evolving under the United Nations Framework Classification for Petroleum (UNFCP). This provides a lot more useful information, but it may need some simplification to be pragmatic. And it would still cover only estimated oil and gas volumes remaining – good for energy-use planning, at least in part, but not for investors who may control the timing of planned projects and who would be better served by more information on the expected value and returns of these opportunities.

Independents are keen to see a common, global standard, with the flexibility to respond to future technology advances, adopted by the SEC and others. With a shorter track record on performance and earnings, their share price depends more on quickly recognizing success in exploration and reserve addition. The big majors have their own global systems and are less motivated to let others see how they do this, perhaps preferring to keep competitive information to themselves for potential asset-trade deals and the flexibility to pull rabbits (or reserves) out of their hats when needed.

Sovereign states and NOCs want to control information about their own resources and have little incentive to be subject to outside rules. Each regulator is used to and prefers its own established system. For governments, political needs and other agendas may dictate how much potentially hand-tying information they want to reveal.

In any case, many regulating bodies lack the expertise or staff to make the updates and changes needed to adhere to a desirable standard system, let alone really audit all individual producers. For example, the SEC apparently has only around two qualified reservoir staff and does not even attend the discussions. So how best should regulators check or enforce standards? By annual audits of some percentage of reserves held? Will auditors become beholden to their clients, as appeared to occur at Enron?

Progress to date has been slow. Consistent definitions have been developed over the last seven years, and there is clearly a move toward a global standard in reserve estimates as in many other global activities and technical disciplines. If a strong, workable, global standard were applied by most key resource holders and regulators, access to better information and more energy resource transparency would be available for all concerned.

Why is the SEC so unwilling to move forward or even engage in assessing the options? It may take strong lobbying from industry leaders – perhaps the reason for the strange Gulf of Mexico deepwater exception – or a crisis to trigger a real change. So a major supply interruption, severe energy shortfall or corporate scandal might push the SEC to revise its rules and adopt a globally acceptable standard. Perhaps it won’t happen before other wider political changes on global  issues in the United States – in other words, not quickly enough to start better energy planning for the long-term projects needed between 2010 and 2020.

Clearly, existing reporting of oil and gas reserves does not fully meet the needs of either energy users or investors. Despite analysts’ ongoing preoccupation with SEC-proved reserve volumes, these have very different values depending on location, costs, tax levels and markets, and future contracts with NOCs may focus more on cash-flow margins rather than volumes held.

Key regulators, including the SEC, could cooperate in converging on a global standard close to the current SPE, WPC, AAPG and UNFCP recommendations. Most believe this should include compulsory reporting, by qualified reservoir engineers, of probable reserves as well as proved, based on consistent definitions and estimation methods. As reserves are a forward-looking indicator, they probably should be estimated based on current and agreed expected future economic conditions, rather than an arbitrary past year-end price point.

Indeed, Adam Smith’s "invisible hand" will need much more visible information, and market traders and investors a much clearer understanding of the value impact of developing different kinds of reserves, to be able to allocate capital resources in an efficient manner for both the near and, more importantly, the longer term.

Consumers urgently need a better understanding of what resources actually exist, how long they may last and what it will take to get them to users. Costs, timing and risks will depend on where and what the resources are. Inherent uncertainties will remain in the complex projects of today and tomorrow, such as coal and less-conventional hydrocarbon resources like CBM, other tight gas, hydrates, tar sands and oil shales, as these figure more strongly in the energy mix.

A recognized international reserves standard will enable better communication and cooperation between energy users, suppliers and those in between. Until such a standard is adopted, the industry will not be well enough informed to make the realistic, long-term energy plans, including the massive investments to recover these reserves, that are needed to provide our societies with a crucial resource: a reliable and cost-effective energy supply. 

John Brooks, CBE, is president of the European region of the American Association of Petroleum Geologists and director of Brookwood Petroleum Advisors. He is a former senior U.K. civil servant in the Department of Trade and Industry and the Department of Energy.

© 2006 John Brooks and Hugh Ebbutt
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