BP sharpening focus on improved shareholder value, efficiency

BP Oil's 100,000 b/d Castellon refinery in Spain is one of the few refineries in Europe with an undersupplied local market. Rationalization of refining capacity is a key element of BP's strategy for bolstering shareholder value. Photo courtesy BP Oil.

British Petroleum Co. plc has made dramatic strides the last 5 years using shareholder value as a lever to improve company performance. The U.K. major also has made equally dramatic changes in organization the last 5 years, a key to that strategy.

In 1989 BP was a bureaucratic company. Its exploration costs were high, producing assets mainly mature, refining and marketing operations unwieldy, and chemical operations unfocused.

About that time the company appointed a new chairman and chief executive, Robert Horton. He was ousted in 1992 after a boardroom bust-up but before leaving instigated a huge restructuring program (OGJ, Mar. 22, 1993, p. 25).

Shareholder return the key

Addressing shareholders at BP's annual meeting in April, current Chairman Sir David Simon revealed just how central investors have become to the company strategy since the restructuring.

"Shareholder return is our key performance measure," said Simon. "It's very encouraging, as I go round BP in all parts of the world, to find the pleasure which staff at all levels feel as a result of our improved performance and the rising share price.

"That performance, with replacement cost profits before exceptional items up to a record level of £2 billion ($3 billion) in 1995, has meant we are now beginning to achieve our goals in terms of shareholder return.

"We've been able to increase the dividend. A payment of 15.25 pence/ share (23.79¢/share) in 1995 was a 45% increase over 1994. The increase in the last quarter put us back above the level achieved in 1992 on an annualized basis.

"The most important thing though is not the percentage increase nor even the absolute amount. It's the fact that we are now convinced that the payment is sustainable because the improvement in performance is secure and still continuing.

"Dividends are one part of shareholder return. The other is the share price. During the past year, the price of BP's shares rose by 27% to £5.39 ($8.10). In the recovery period of the past 4 years we have returned comfortably to over 20% return annually (see table, p. 24)."

Focus regained

Keeping shareholders happy is hardly a revolutionary strategy. Where BP has been innovative is in the change of culture it has adopted to cut costs and improve efficiency throughout the company.

Key to this change has been the splitting of resources throughout the company into asset groups within the three main divisions: BP Exploration, BP Oil, and BP Chemicals.

This facilitated sale of noncore assets following the major upheavals in 1992, particularly disposal of the BP Nutrition division. It also grouped remaining core assets in a way that enables identification of poor performers.

As a result of this approach, BP has taken the industry by surprise twice this year. In January it disclosed a plan to close or sell two refineries and reduce capacity at a third. Then in February BP and Mobil Corp. announced a merger of European refining and marketing operations.

Kevin Abbott, BP's manager of group investor relations, said that in 1992 BP was in a position where not only was its performance at the bottom of the competitive pack, but also its financing-particularly its debt level-was uncomfortable.

"We embarked on a journey to make BP the sort of company people could feel confident with financially," said Abbott, "because we recognized that this was one criterion for gaining access to future opportunities."

On the performance side, said Abbott, BP had lost some of its focus, and so was not being selected as often as it would have liked as a project partner.

"One of the most gratifying features of the restructuring is the way this has turned around for us," said Abbott. "Now we find more people come to us and say, 'Will you run our operations with us or even for us?'"

"This was part of the basis of our joint venture with Mobil, for example, and we see it as a great compliment coming from such an intensive competitor as Mobil."

As part of the transformation, BP also reviewed its operations from the assets and organizational viewpoints.

"We looked at every asset and decided what makes it a successful operation," said Abbott. "Then we asked: Does this asset pass the test, or can it be made to pass the test? Some clearly don't and can't. We are working through this process now, for example in refining, and it will continue.

"Every year we now look at the bottom 10% of our assets portfolio and ask, why are they at the bottom? These assets come in for particular study, although this does not necessarily mean they are put up for disposal."

Asset managers have been charged with running each asset group as a business in its own right, with responsibility for all aspects of performance from productivity through environmental performance to local community liaison.

BP found levels of performance among similar assets, such as downtime levels at refineries, could vary widely. Now the company is encouraging managers to share experiences as a means of improving overall results.

"The management process now causes people to share successes, failures, and ideas," said Abbott. "Part of the remuneration package for asset managers is now linked to the performance of the company overall, as well as to their own assets. This encourages sharing of information."

The refinery sales and merger showed BP is prepared to make great changes if the economics add up. But a story that probably shows best how BP's thinking has changed since 1989 is development of North Sea Andrew field (see Watching the World, p. 29).

Andrew development

BP Exploration began oil production from Andrew field on U.K. North Sea Block 16/28 on June 26, at an initial rate of 3,500 b/d from one well.

Output from Andrew and its Cyrus subsea satellite is expected to reach 60,000 b/d by yearend.

The timing of Andrew development, and the change in attitudes needed to make it viable, have meant it is viewed as a turning point in the company's approach to development work.

Andrew has estimated reserves of 119 million bbl of oil and condensate and 134 bcf of associated gas. The field was discovered in 1974, in 116 m of water.

The field was developed with a conventional steel platform, with four wells predrilled. Nearby Cyrus field, which had earlier produced through a production ship, was tied in as a two-well subsea satellite of the platform.

Paul Bibby, deputy project manager for Andrew, said that in the years following its discovery, many attempts were made to get development sanctioned by the company, but each time the field was declared marginal.

"In 1990," said Bibby, "BP had lots of major fields developed and entering a decline. We needed to do something drastic to make Andrew viable.

"Our challenge was to take Andrew as a test case, to drive development and operating costs down through finding new ways of working with contractors.

"This led to a radical rethink of how BP could develop and operate fields. We had the right technology, which is fairly standard for the North Sea, but we became convinced that new behavior towards contractors was needed to lead to cost reductions."

Gain sharing

Bibby said the starting point in making Andrew commercial was the realization that cost could only be cut significantly if operator, license partners and development contractors were to work toward the same financial goal.

BP selected seven contractors to work on the project and got them involved in cost estimations. These seven later became the Andrew development alliance, each with equity in the project.

The chosen contractors were: Brown & Root Ltd., London, responsible for design and project management; Trafalgar House Offshore Fabricators Ltd., Middlesbrough, which built the platform deck; Brown & Root Highland Fabricators Ltd., Nigg, Scotland, responsible for jacket construction; drilling contractor Santa Fe Drilling Co. (North Sea) Ltd., Aberdeen; installation contractor Saipem SpA, Milan; accommodation module fabricator Emtunga Mekaniska Verkstad AB, Vara, Sweden; and pipeline contractor Allseas Engineering BV, Delft, Netherlands.

"Previously," said Bibby, "BP had always put together its own cost estimates for developments and kept the information closely guarded. With Andrew we tried to create a gain sharing arrangement."

Under traditional contracts, said Bibby, the operators wanted to keep costs to a minimum, while the contractors wanted to maximize the number of man hours spent on a project to increase their earnings.

"This time we aimed for an alignment of interests," said Bibby, "and the first part of the process was to ask contractors for ideas on how to do this."

Brown & Root came up with the proposal for a risk-reward arrangement, and this was adopted in two parts: an alliance agreement set out interests and potential benefits/losses, established relationships between operator and contractors, and established an alliance board; and conventional work contracts between the operator and individual contractor specified individual work programs and methods of payment.

Together BP and the contractors came up with a development cost of £373 million ($560 million) for Andrew. This was low enough for BP's board in 1994 to sanction development.

Bibby said this figure was also a great improvement from the £450 million ($675 million) development cost BP had earlier estimated with a traditional approach that omitted the input of contractors.

"On the basis of this costing, a gain sharing development was established, which has since become fairly standard in the industry," said Bibby. "At a cost of £373 million ($560 million) the contractors would have a normal level of profit from their contracts."

Under the gain share agreement, BP and license partners would receive 46% of any benefits-or pay 46% of any losses-while the contractors would receive or pay a total 54% split as follows: Brown & Root 22%, Trafalgar House 12%, Saipem 6%, Hifab 6%, Allseas 4%, Santa Fe 3%, and Emtunga 1%.

If the alliance developed Andrew under budget, the agreement was that the contractors would share 54% of the difference between target and actual costs.

If the alliance developed Andrew over budget, the contractors would have to pay a penalty equivalent to 54% of the cost overrun to the field license partners.

When the deal was formulated the development cost target was seen as a difficult one, and meetings with contractors involved a great deal of debate about protection against risk.

"The gain sharing principle was that those companies which had a greatest say in the outcome of the project should have the greatest share in gain sharing equity," said Bibby.

"At first everybody's concern was about what they would be exposed to because of the tight target. Also, there was no 'man-to-man marking' by BP staff in the Andrew team, which required a lot of openness between BP and the contractors."

Cost bonus

As Andrew came on stream, however, BP said its final figure for total development cost was £290 million ($435 million). Also, the date for first oil was brought forward from the original schedule of January 1997 to June 1996.

"Now," said Bibby, "when we talk about our final cost, it appears the £373 million ($560 million) target was an easy one after all."

The target development cost was to cover everything involved in bringing Andrew into production. This was to include changes to the design, which under traditional contracts have been a source of legal claims.

"With Andrew there was no room for claims for extra payments," said Bibby, "since the alliance agreed to develop the field for the target sum. We made significant changes during the development, but there have been no claims, and in the end we made significant savings."

Andrew platform consists of a 6,500 metric ton steel jacket and a 10,400 ton integrated production, drilling, and accommodation topsides.

One of the major areas for potential cost savings for Andrew was in offshore hookup work. This was given special attention by involving contractors in the alliance.

The development plan was sanctioned with an allowance of 10 man-hr/metric ton for offshore work. But the team achieved hookup in 7 days, with only 45 min./metric ton required for offshore work.

"This was the clearest measure of the step change brought about by alliancing," said Bibby, "and resulted in a savings of £20 million ($30 million) out of an offshore work budget of £27 million ($40.5 million)."

Robert Brown, Andrew asset manager, said the project was a microcosm of what is now happening in the BP world.

Brown said the Andrew team had been talking with BP Oil managers recently about finding new ways to work with their contractors and with BP Chemicals managers looking to apply this approach to new projects in the Far East.

Exploration

John Browne, BP's chief executive, told the annual meeting the company has restructured its upstream portfolio and built a reserve base that will take the company well into the next century.

At yearend 1995 BP estimated net proved reserves at 2.7 billion bbl of oil and 6.59 tcf of gas in developed fields, and 1.97 billion bbl of oil and 3.79 tcf of gas in undeveloped fields.

The company produced a net 402 million bbl of oil and 534 bcf of gas during 1995 but increased its reserves base by 80 million bbl of oil and 136 bcf of gas through discoveries, revisions of estimates, and enhanced recovery.

"We can now confidently say," said Browne, "that we can replace production for at least the next decade, even though production is rising.

"We have new developments coming on stream this year in the North Sea, West of Shetland, and in the Gulf of Mexico. And more new fields will follow.

"Taken together, all those new fields will help to raise production by as much as 4-5%/year, with enough opportunities to continue the growth well into the next century.

"We have new discoveries in Colombia, Viet Nam, and the Gulf of Mexico, and we've won access the last few months to some of the most promising areas in the world, including Venezuela and Algeria."

Rodney Chase, chief executive of BP Exploration, told analysts in London in March the company's resources are sufficient to allow growth in production of 30% the next 5 years, taking output to 1.8 million b/d of oil equivalent (boed) by 2000 and to 2 million boed beyond then.

"At a margin of $4.50/bbl," said Chase, "this extra production could add $900 million/year to profit potential. In addition, the company believes it can gain a further $100 million by replacing 200 million bbl of its annual output with production that yields an extra 50¢/bbl."

Mature assets

Having boosted the amount of future developments in the reserves portfolio, BP Exploration recently decided to strip out a few aging and increasingly less profitable asset groups.

In March BP put up for sale its Beatrice, Buchan, Clyde, and Thistle fields and satellites off the U.K., which currently produce a total 59,000 b/d, of which BP's share is about half.

The four fields and their satellites are known as the Mature Asset Team (Mast) fields. The Mast team was set up in 1994, when oil prices averaged about $12/bbl and the fields were losing money.

A BP official said, "Mast was set up to ring-fence the fields, then we set about staff reductions onshore and offshore and simplified business processes and introduced multi-skilling.

"The Mast management team has done everything without the use of capital expenditure, except for Cullen-related safety work, to make these fields profitable. They have taken it as far as they can go."

BP said these operations have extended field lives by a minimum of 2 years, which will enable them to produce "well into the next century."

However, they are still less profitable than BP's other fields and are thus at a disadvantage in competing with other assets for funds and management time.

The official said the Mast operation had attracted the attention of third parties that have approached BP with a view to buying the Mast fields. BP hopes a sale will be completed in late summer.

Beatrice field lies on Block 11/30a and produces from four shallow water platforms, with a dedicated export pipeline to Nigg terminal near Aberdeen.

Buchan lies on Blocks 20/5 and 21/1 and produces via a converted semisubmersible drilling rig, with oil sent via pipeline link to the Forties network.

Clyde field lies on Block 30/1b and produces from a platform that exports oil via the Fulmar platform. The Clyde asset includes Medwin and Leven satellites.

Thistle field lies on Blocks 211/18, 211/18a and 211/19 and produces from a fixed platform with oil exports via Brent field to Sullom Voe terminal. Thistle also incorporates Don and Deveron satellites.

The official said the sale continues BP's portfolio management strategy, which has been underway since 1992: "If something is worth more to somebody else than to us, we'll sell it."

The BP official said BP is also touting its Seillean production ship, currently being used to produce Donan field. He said the company was considering a number of offers.

Refining/marketing

BP surprised the oil industry early in the year with disclosures of sales or closures of refining capacity and of a merger of European downstream operations with Mobil.

In January BP Oil said it plans to sell or reduce capacity at its three least profitable refineries. This will leave it with 11 refineries worldwide, with total crude distillation capacity of 1.4 million b/d.

The Lima, Ohio, plant and the Lavera refinery in southern France are to be offered for sale. At Nerefco refinery in Rotterdam, partly owned by Texaco Inc., capacity will be trimmed by 70,000 b/d.

At the time Browne said the move would bring BP's worldwide refining capacity to sales ratio in line with other key refiners, most of whom refine less than they sell (OGJ, Jan. 15, p. 32).

This news had hardly been digested when BP and Mobil disclosed a plan to combine their European refining and marketing operations in a bid to cut operating costs.

Subsequently the companies were forced into disclosing details of the plan earlier than anticipated because of leaks to the press by an employee.

The venture will have $5 billion combined assets and sales of more than $20 billion/year and operate in 43 countries, often with a market share comparable with those of Royal Dutch/Shell and Exxon Corp.

BP said setting up the joint venture will cost about $400 million, after which pretax cost savings of $400-500 million/year are expected within 3 years. Duplicated assets will be closed or sold (OGJ, Mar. 4, p. 40).

BP Oil Chief Executive Rolf Stomberg told analysts in March that a mix of refinery rationalization and investments is expected to improve refining margins by $300 million/year after tax.

Stomberg said marketing rationalization could improve earnings by $100 million/year, while upgrading 1,000 service stations at a cost of $1 billion during 5 years could yield $150 million/year from increased volumes and shop sales.

Plans for 300 new gasoline stations in Eastern Europe and 200 more in Africa and Asia, at a total cost of $1 billion in 5 years, could return an additional $150 million/year, said Stomberg.

"That is why we've been restructuring our portfolio by selling or closing underperforming assets," said Browne, "while investing to bring the others up to top-class performance.

BP Chairman David Simon
Shareholder return is BP's key performance measure...1995 re- sults show the company is beginning to achieve its goals on shareholder return.

BP CEO John Browne
We can now confidently say that we can replace production for at least the next decade, even though production is rising.

Copyright 1996 Oil & Gas Journal. All Rights Reserved.