New strategies on horizon for exploration companies

Sept. 3, 2012
The last decade saw total new global O&G resource additions exceed consumption while yet-to-find estimates were revised significantly upwards.

Ivan Sandrea
Oxford Institute for Energy Studies
Oxford, UK

Monica Enfield
Energy Intelligence

The last decade saw total new global O&G resource additions exceed consumption while yet-to-find estimates were revised significantly upwards.

New resources totaling 800 billion bbl of oil equivalent were added (1.5 times cumulative consumption), while global yet-to-find resources are now estimated to be close to 4 trillion boe, three times more than 10 years ago), underpinned by the addition of unconventional resources but also resources in the Arctic and deep offshore. New ideas, technological developments, and rising prices strongly supported the expansion of the global opportunity set, the combination of which has just started to shape the long term future of the industry.

Deepwater exploration is arguably the most important high-risk high-cost strategy in terms of capital and technology the international industry has developed in recent decades, with a total of 85-90 billion boe discovered in 2000-11 following several country openings and new basin tests.

However as predicted 10 years ago, Brazil, the US Gulf of Mexico, and West Africa remain the big themes with only East Africa added as a new deepwater gas play that could rival the East Mediterranean.1 Many basins have failed to provide either sufficient materiality or even a positive result.

Meanwhile, access to deepwater Brazil by foreign international oil companies has been constrained, the US gulf is still recovering post-Macondo, Mexico is struggling to find a formula to attract investment, Nigeria is no longer an attractive proposition, and domestic Indian players are holding tight to the vast yet marginal deepwater domestic acreage. On the positive side, Angola has just offered its most prospective deepwater acreage.

The 4 decades-long deepwater E&P adventure has created huge value, 7.2 million boe/d of current production, and a large reserve base that is yet to be developed, but in an industrial and geological-strategic sense deepwater exploration has in our view entered its own "end game."

In general, despite oil price decks of $100, all the major types of reserves have become harder to commercialize while the industry seems to be going back to onshore plays. Excluding the Middle East and deepwater opportunities, the most thought-after remaining material options are unconventional, extra heavy oil, and Arctic resources. These may be accessible under equity ownership but are high cost, environmentally sensitive, involve a large technological risk, and have very long lead times. Beyond these, new exploration themes exist but will require players to redirect their exploration strategies, become familiar with the many and new types of risks and geographies, and ultimately modify how they execute projects.

Post-2000: A big decade

During 2000-11, global exploration resulted in the addition of 380 billion boe of proved and probable conventional reserves.

Some 80-100 billion boe were discovered in post-2000 accessed licenses, the bulk of which are in deep water. The big exploration themes of the last decade include: Former Soviet Union (Caspian), China onshore, Australian offshore, Brazil presalt, Angola deepwater, US gulf deepwater, Middle East onshore, and East Africa/Mozambique deep water. Other new, much discussed discoveries in Ghana, Uganda, India, Israel, Guyana, and now Kenya have been small in both absolute and relative terms and so far appear to offer limited upside.

Looking at the unconventionals or "difficult hydrocarbons" (exploration risk is virtually zero), there was significant testing and proving of resources in Australia (coalbed methane), Canada (bitumen, shale gas), US (shale gas and tight oil), and Venezuela (extra heavy oil).

Although there are no reliable official estimates, consultations with government agencies, industry, published literature, and independent assessments suggest that some 400 billion boe have been delineated, tested, or proved. US shale gas has been among the biggest, estimated at some 100-150 billion boe.

There is no doubt that the increase in industry's access to prospective acreage and discovered reserves was significant, if not a record. And in the last 12 months, new groundbreaking access has taken place in Angola presalt, China shale gas, and more recently in Russia's Arctic, totaling prospective yet-to-find reserves of 380 billion boe (Fig. 1). Yet except for Africa rift basins no new access in less-known, studied onshore basins with large potential conventional oil and gas has taken place.

In terms of competition, the number of E&P players has increased sharply while many evolved beyond the traditional operator role. In 2000, there were around 500 active E&P players while in 2011 the number was close to 1,000.

Today, the E&P competitive environment includes companies ranging from IOCs, NOCs, large and small E&P independents, private equity, trust funds, sovereign wealth funds, investment banks, local players, utilities, industrial conglomerates, traders, and miners, among others.

In deep water, a highly complex and high-risk operation, more than 90 companies are active compared with 20 just 15 years ago.

Undoubtedly, the most strategically relevant set of new international E&P players that emerged during the last decade via mergers and acquisitions include the Asian NOCs and Statoil, in exploration Petrobras and the independents, and in unconventionals the independents—in fact, as a whole the NOCs and independents dominated the new access game during much of the last decade.

IOCs lagged behind in major discoveries-exploration in new trends (Brazil presalt, Turkmenistan, US shale, East Africa deep water, etc., as well as in smaller plays such as rift basins onshore Africa) even though they have long been the dominant players in bitumen and extra-heavy oil.

The Chinese NOCs have transformed themselves from pure state entities with domestic focus and limited international capacity to globally active E&P players (present in over 30 countries including the US, Canada, and Australia) with assets in all the new major plays (still risk adverse to exploration but with an evolving apetite) backed by their solid balance sheets. In general, NOCs grew faster than many IOCs in term of reserves, production, and balance sheet, and most have remained unchallenged in the top ranks in virtually every metric.

M&A/capex shift

Between 2000 and 2011 there were over 13,000 M&A deals worth $1.5 trillion in which more than 100 billion boe of proved reserves, about 50% gas, and 30 million boe/d of production were transacted.

M&A spending became increasingly led by NOCs, characterized by large assets, JVs, and complex corporate deals. Relatively speaking, most deals were in North America, Russia, and Europe, while deals in unconventional resources in North America and Australia became the new theme. In deep water most of the activity took place in Brazil and the US gulf as asset deal flow outside these regions was limited.

Reflecting the capital intensity of the industry and the significant capital available in NOCs and SWFs, organic E&P Capex (excluding M&A), global Capex (in real terms) increased from just over $100 billion in 2000 to $600 billion in 2012. Cumulative E&P Capex spending totaled $3.5 trillion, exceeding all expectations and forecasts (in 2006 the International Energy Agency projected cumulative upstream investment at $2.3 trillion from 2001 to 2010).

Regionally, Capex in Mexico, Brazil, Russia, and Canada expanded greatly as a total share, while the share of IOC Capex decreased to less than 25%. Offshore Capex, including deep water, rose steadily to represent 40% of the total industry E&P Capex (Fig. 2).

Deepwater status

Global offshore exploration (including deep water) contributed to 170 billion boe or nearly 45% of the total new conventional reserves.

Of this, deep water accounted for 85-90 billion boe of new reserves. As of 2011, estimated global deepwater discovered reserves totaled 160-170 billion boe proved and probable. This compares with 30-40 billion boe in 2000.

Global oil and gas deepwater production stands today at 7.2 million boe/d (circa 5% of global oil and gas), up from virtually nothing in 1990, and remains dominated by the incumbent IOCs, Petrobras, and independents, however with reevaluation of the risks in the wake of the Macondo blowout, this picture is expected to change.

In terms of water depth, less than 1 million boe/d comes from 1,000 m or less, the rest comes from deeper water; the latest production record is 2,700 m of water. The growth in deep water was strongly underpinned by technological breakthroughs (seismic, drilling, riser, well), new reserves additions, rising prices, and more players involved.

Deepwater oil production is now close to 6.2 million b/d, mostly from Brazil, the US gulf, Angola, and Nigeria. As for deepwater gas, current production is now 1 million boe/d, and the most significant contributors are the US gulf, India, Egypt, Brazil, and Nigeria.

Taking recent official published studies and assessments, deepwater yet-to-find resources could be as high as 500 billion boe. Of this, the Big 4—Brazil, US gulf, Angola, and Nigeria—account for 320 billion boe, while accounting for the rest are 35 other countries, many of which represent small-scale or one-off opportunities; however, it is worth noting that the yet-to-find estimates in the mid-1990s for the Big 4 totaled around 60-100 billion bbl of oil.

A new end game

For several decades, industry access to equity reserves and prospective areas has been limited to less than 10% of the global resource base, and a further roughly 10% has been available through NOC and-or direct government access under different contractual terms.

Industry operations evolved from their onshore origins to shallow water operations (1950s), to deep water (1970s onwards), and to increasingly harsh environments such as deserts, rough seas, jungles, and ice-infested waters; offshore Arctic and many exotic Arctic projects have been talked about for decades with limited success.

Few would argue that material opportunities have diminished in conventional onshore and shallow water basins in the 100 countries with such resources. The international industry mainly operates and derives most of its profits from 20 or so countries and profit hubs.

Today, after 40 years of exploration, deep water has also reached this point. The other remaining material opportunities for equity access are characterized by low exploration risk unconventionals, extra heavy oil, and high exploratory risk Arctic resources (Figs. 3 and 4).

A not yet very well understood but potentially material new exploration "theme" are the rift basins and unexplored intracratonic sedimentary basins; having said this, in recent years we have seen strong activity in rift basins across Africa with increasing success. In North America, recent developments in horizontal drilling and hydraulic fracturing have highlighted the multibillion barrel oil potential for example of the Late Devonian Bakken shale formation of the Williston basin. Outside of North America, these types of basins may be also found in Brazil, Africa, Eastern Europe, the Bazhenov shale of Western Siberia-Russia, China, and Australia.2 Compared with North America, all of these have few wells in very large areas and much less oil and gas discovered, leaving an open question and perhaps a large opportunity.

However, for any of these types of reserves, particularly the most capital intensive ones, to be monetized, operators will need to manage new aboveground challenges. Beyond just macropolitical and economic stability in the country of operation, companies face increasingly surface issues to secure a license to operate. These include nascent, evolving energy policies and fiscal frameworks, social issues, varying levels of regulatory capacity, increasing environmental liabilities, as well as an array of risks that impact operating conditions, such as local community relations. Particularly for Arctic, deepwater, and unconventional resource development, investors' ability to manage these largely nontechnical, socioeconomic risks will be critical.

In many jurisdictions, the potential rewards do not outweigh the aboveground risks, meaning that investment and development in many countries are likely to be delayed or dropped (Fig. 5). Especially in many of the frontier deepwater plays in Latin America and in Sub-Saharan Africa, high levels of political instability, regulatory uncertainty, changing fiscal terms, and significant technical barriers to operations will likely delay in some cases the pace of resource development.

In emerging unconventional plays with sprawling surface footprints, land rights issues and local community opposition are likely to be key aboveground risk challenges, while in the Arctic more stringent safety and environmental regulations will make it difficult for all but the most experienced and patient companies to lead development efforts.

The end game is defined by accessing and producing difficult hydrocarbons from a massive opportunity set but at high capital cost, replete with new technical and socioeconomic challenges and a changing set of players at the table. It is an end game in which only the flexible and patient will be winners.

The long arc of evolving technological, economic, and geopolitical factors that have determined exploitation of oil and gas since the mid-19th century has now clearly entered the hydrocarbon resource pyramid's base—the end game is on.

The resource types are few but enormous; their exploitation massively capital intensive with subsurface technical complexity and unprecedented aboveground socioeconomic challenges. While perverse for an end game, the players are many, and many are newcomers to the game, but they all know that few can bear the risks and costs alone. All in, the next exploration frontier appears to be back to unexplored onshore basins, and this is where we are likely to see the next wave of competition and developments take place.


1. Daly, Mike, "Cratonic basins—the missing data," Geoscientist, Vol. 22, No. 4, May 2012.

2. Sandrea, Ivan, "Deepwater oil discovery rate may have peaked; production peak may follow in ten years," OGJ, July 26, 2004, p. 18.

The authors

Ivan Sandrea ([email protected])is former president of Energy Intelligence Group in London. Previously, he was vice-president of global strategy and business development and vice-president of international E&P strategy for Statoil where he specialized in complex business new development, opportunity screening and identification, international E&P strategy, and business intelligence and competitor analysis. Previously he was head of oil supply for OPEC and represented OPEC in the United Nations in efforts to reclassify petroleum reserves. He has also been associated with Merrill Lynch and BP Exploration. A native of Venezuela, he has a BS in geology from Baylor University, an MS from the University of Edinburgh, and an MBA in finance and strategy from Edinburgh University.

Monica Enfield ([email protected]) is director of industry analysis for Energy Intelligence's Research & Advisory Group, based in Houston. She manages retainer and advisory engagements that assess aboveground risk for regional, country, and project level investments in international oil and gas. An Africa specialist by background, she leads the country risk practice on that region, with specific expertise in African national oil companies, local risk assessment, and strategy development. She was previously director of country risk at PFC Energy, where she managed client offerings on national oil company strategies and country risk. She has an MA in Arab studies from the School of Foreign Service, Georgetown University, and a BA in political science from California State University, Stanislaus.