Stronger state/corporate alliances to galvanize giant offshore

Basic development schematic for Iran's Sirri A and E Fields, due onstream in 1998 at a cost of $600 million. 1995 Japanese equity oil and gas reserves compared with those held by international companies. BHP has been producing gas from the Bass Strait since 1965, and still sees this province as one of its core offshore areas.

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World's leading oil companies forecast
next decade's developments

Jeremy Beckman
European Editor
BHP has been producing gas from the Bass Strait since 1965, and still sees this province as one of its core offshore areas.


Major, minor, and state oil company executives were invited to London recently to share their visions of the future. However, the Third Millennium Petroleum Conference did not quite live up to its billing, with most speakers preferring to reveal the shape of things so far.

In between outlining their recent rationalization programs, some orators did list their preferred playgrounds for future hydrocarbon E&P. Venezuela topped most wish-lists, with no out-and-out offshore province subject to special hype or neglect. But real detail was lacking in the predictions, suggesting either that a) three and a half years is a long time in the petroleum industry or b) CEOs are not yet fully attuned to the industry's new mood of information sharing.

However, the conference - organized by Global Pacific & Partners and Petroconsultants - did reiterate certain themes. Most speakers felt that the focus of exploration and production would shift swiftly to newer provinces, but the technical and political risks in these regions would also have to be tackled collectively. And the competition for new plays will likely intensify.

Howard Paver of BHP Petroleum pointed out that although more than 30 countries still hold substantial resources of oil and gas, there is a major imbalance in the distribution of these reserves. While the state petroleum companies are estimated to be sitting on 940 billion boe of oil and 4,500 tcf of gas, 250-plus petroleum companies capitalized at a trillion-dollar share reserves totaling just 140 billion boe - roughly 6% of the state groups' quota.

Replacing production from maturing, low-risk areas is proving difficult even for the Seven Sisters, Paver added: their collective reserves base fell 11% between 1992 and 1994. But with so many companies following similar strategic paths in their new zones of choice, he said, "they are forced to compete with high bonus payments, stiff work programs and increasingly difficult terms from the host governments". Some bonus payments in this year's Venezuela licensing round exceeded $100 million, he stated.

The Majors

When it comes to signature deals in emerging provinces, the industry still looks to the majors to lead - except Mobil, for some reason. The 130-year old company has a regressive image, which puzzled Steve Comstock, VP for planning and upstream technology at the E&P division. He pointed out that Mobil had just acquired stakes in Ampolex, Tengiz, Natuna, and Canada's Sable Island regions. "They had been waiting 20 years for someone to develop them," he said.

Mobil's base oil price estimate is "$17 pegged flat forever", Comstock stated. "We see the privatization of national oil companies continuing, and more competition through strategic alliances which will include pipeline companies." As for mega-projects in undeveloped regions, such as Tengiz, working with host oil companies was the way forward, he added. "Sharing the economical and technical risks is too large for one company".

Comstock said that Mobil was now viewing traditional competitors as potential partners. "Banks and lending institutions are more active in bringing governments and potential lenders together." These groupings are becoming helpful in funding upstream as well as downstream investments such as power plants, he said, which in turn is driving the LNG expansion projects in Southeast Asia.

Just over 10 years ago, Comstock claimed, two-thirds of the capital spending of the 10 leading majors was spent in the US. "In 1995, the percentages reversed and that trend will continue." A contributory factor, he said, is the "not in my backyard" line of the "People's Republics of California, Florida, and South Carolina".

Texaco is one of the chief architects of downsizing. Its US exploration and production division, TEPI, divested half its non-core assets in 1994. This had minimal impact on the business, claimed Ken Smith, assistant to the president of the division, as these properties accounted for 7% of cash flow and 10% of production. However, the cuts did allow human resources to be re-focused on Texaco's core assets, he said, leading to higher reserves replacement last year and finding and development costs down 18c/bbl to $3.75/bbl. The production loss was also being recovered.

Internationally, Texaco has pulled out of exploration in 18 countries since 1991, Smith said, shunning high-risk regions in favor of provinces with known hydrocarbon systems. But its capex had also risen 100% in that period. He cited the West of Shetlands, Australia's NW Shelf, Myanmar, Bohai Bay, and offshore Sakhalin Island as offering the reduced risk and higher reward potential sought by Texaco.

Deepstar has helped Texaco build strengths in 3D seismic acquisition using vertical cables, lower cost subsalt seismic imaging, and sequence stratigraphy: these techniques will be applied to cut the risk of rank wildcats in the slope fan systems off Nigeria. At home in the Gulf of Mexico, Smith added, the company's goal is to drill five deepwater wildcats over the next four years.

Long-term, he said, the company needs to build up its asset base again through new venture exploration. One stumbling block is that too many drilling engineers were let loose under the company's bloodletting program. "We have probably reduced too far," he admitted. Texaco also lacks sufficient trained workstation-competent geophysicists: "The technology has advanced so much."

Chevron has a similar problem. Its reorganization action has lifted production 46% over the past five years, said Tom Schull, general manager for Exploration and Technology overseas (COPI). This division's goal is to grow annually by 10-15%: recent new discoveries off the Australian NW Shelf will help, likewise increased output from Chevron fields off Angola and Zaire which could raise current production from this region by 25% to over 500,000 b/d.

There are other areas where the production increase could be achieved, but according to Scholl: "The difficult thing is to decide what not to do, to focus on the things that are most important." As a growth provider, COPI does not have a problem getting capital out of Chevron. The difficulty, he says, is "how do we make this happen with this workforce of ours that is a little over-stressed right now?"

ARCO's regional vice-president Steve Suellentrop hinted at no such problems. He said his company's current base-case, five-year plan anticipated capital spending of $14 billion, half of this directed to worldwide upstream oil and gas projects. ARCO's international expenditure would jump 50% compared with the previous five years: further billions might also be made available upstream beyond the base case figure.

The Middle Ranks

BHP ranks 20th in the league of publicly owned oil companies, said Howard Paver, with reserves of 1.3 billion boe. Exploration is still seen as the key to growth, but the company is warier of frontier provinces following its experiences in Vietnam: it has just had to write off its $151 million investment in the Dai Hung development following lower than expected production. Dai Hung had been a risk, Paver admitted: "But you win some, you lose some."

BHP was now sticking to core areas with high reserves potential and where it can apply its technical strengths such as FPSO expertise for deepwater E&P. Exploration is being part-funded by selling non-core assets: in the North Sea, for instance, BHP has divested its interests in the Dutch sector and the ETAP project to concentrate on its key UK development, Liverpool Bay.

At home in Australia, although the NW Shelf and Timor Sea hold best hopes for new discoveries and increased production, while the Bass Strait remain crucial to BHP's production profile. Paver listed initiatives such as capturing step-out oil with new field developments; accelerating production or tapping poorer quality reservoirs; workovers; and high grading exploration prospects near existing platforms, while also evaluating deeper water prospects.

The State

National Iranian Oil Company's exploration director, Seyed Mehdi Hosseini, spelled out equations for meeting rising global oil demand. If the forecast increase of an extra 20 million b/d by 2010 is to be believed, he said - and assuming that Iran's current share in OPEC's total output remains constant at 14% - Iran would have to double its current production capacity to 8.4 million b/d by 2010.

But despite Iran's proven reserve base of 90 billion bbl, and the resistance in some quarters to US sanctions, Hosseini was not confident of meeting that target. He estimated the necessary capital investment at $30-40 billion, with a further $6-8 billion needed just to sustain Iran's existing production. Realistically, he said, his country could only aim currently at 6.5 million b/d by 2010.

Further foreign investment is needed in upstream joint ventures on top of the service contract negotiated by NIOC with Total for the offshore Sirri Fields development. Hosseini claimed that this type of contract, whereby Total gets longterm access to crude from Sirri instead of conventional production sharing, would also prove attractive to other oil companies. Sirri management would be under a steering committee, he added, with a commitment to maximize the workforce from Iran and to use local materials and services.

Last November, NIOC organized a seminar on 11 planned new Iranian upstream and downstream projects where foreign participation could be permitted. It was attended by "tens" of local and international companies, according to Hosseini. Tenders are being pursued and contracts are expected to be finalized shortly. To attract finance from banks as well as engineering contractors, revenue from pre-sale of crude obtained would be used to cover the expenses of participating companies.

NIOC was also willing to offer other upstream projects for foreign investors, including offshore oil and gas fields in the Hormuz Strait and South Pars as well as gas export projects such as a planned pipeline from the Persian Gulf to India and Pakistan. Hosseini saw these countries as the best market in the near term for Iranian gas, but NIOC was also undertaking a joint study on a pipeline and/or LNG supplies to Europe with Gaz de France, Ruhrgas, and Snamprogetti.

In the Caspian, Iran is negotiating exploration of offshore fields with Turkmenistan. Hosseini also claimed that Azerbaijan's recently signed Shah Deniz contract, which includes one private Iranian company, but none from America, "proved once again that the US policy of isolating our country internationally by exerting political and economical pressure over neighbors and international trade partners is short-sighted and doomed to be futile".

Another country which is not outlawed, but famed for outlawing grand-scale foreign oil company involvement in its waters, is Malaysia. Mohd Farid Mohd Amin, presenting a paper on behalf of Petronas Carigali's E&P division, declared that his country "wanted more sustainable exploration of its resources for as long as possible".

Stiff tax terms have dissuaded some international oil troops from joining in, but Amin claimed relief was on the way. "We are introducing a new petroleum formula based on cumulative revenue and cumulative costs." Petronas is reviewing Malaysian PSCs to take into account prevailing oil prices, he added: under a low oil price scenario, PSC partners would therefore be able to recover their investments faster. Details will be announced in the near future.

Amin estimated around $12 billion had been budgeted over the next five years for Malaysian oil exploration, development and production, and $4 billion for gas developments. Currently 18 further Malaysian gasfield developments are planned over the next two decades, he said, boosted by construction of the country's third LNG plant. This should come onstream via two liquefaction trains in 2001, with capacity for further expansion.

Agip has held a virtual monopoly on promising acreage around Italy's shores, but the situation would change, promised Dr Domenico Tantillo, vice-president for planning in Milan. In line with European Union rules, the next licensing bid round in January will be open to all-comers. "We hope other operators will join us to share the difficulties of exploring Italian areas," he said.

Yasuhiko Wada, vice-president of Japan National Oil Corporation, pointed out that Japan's equity crude production last year was 600,000 b/d, with proven reserves of 3.5 billion bbl. Its equity gas output was 350 bcf/d with reserves of 8.5 tcf. Those figures showed that the Japanese E&P industry as a whole could be ranked alongside the companies just below the majors.

Although the core source areas remain the Middle East and Asia-Pacific, accounting for 80% of Japanese production, new areas of supply are being sought. Wada cited the UK tax regime as one readily adapted to meet investors' needs: "Would it be too optimistic to expect that the producing countries will follow a similar path as they pass from infancy to maturity as oil producing countries?"

Wada saw North Sea-developed technologies such as subsea production systems, deepsea platforms, 3D seismic and horizontal drilling as carrying "a trickle down effect to the rest of the world". He also felt development of further new technologies would be needed for the CIS to restore lost production capacity, once political stability and a satisfactory fiscal regime has been established there.

With new openings and fiscal improvements generally not accelerating at a constant rate, this could increase the risk factor for investors, he perceived, particularly in ultra-large developments requiring technical innovation. He foresaw these projects as being feasible only through host governments or state oil companies sharing the risk with oil companies under an "inter-dependent, alliance type of partnership".

JNOC itself eyes gas exploration in India and China, and is keen to be involved in development of the Sakhalin and Turkmenistani gas reserves, including the proposed pipeline transportation scheme for Amu Darya. Wada also hoped that Mexico would open up gas E&P soon to outsiders.

Although Japanese oil companies remain keen on the Middle East, some of the countries there are still grappling with formulating policies for allowing outside investment. If the pace of new activities in Latin America and the CIS is spurred, Wada said, "the Japanese E&P industry, which does not boast unlimited source of investment, would have to allocate her limited risk money in these areas, leaving off the Middle East whose geological prospectivity ranks among the highest".

Wada concluded that continued excessive rationalization in the global E&P industry, prevalent also in Japan, "could hamper the industry's performance, especially evaluation capability and R&D. Consequently, we may see in Japan new business alignment and work sharing associations emerge, which are better equipped with new technology, financial resources, and management resources".

Copyright 1996 Offshore. All Rights Reserved.

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