The article was published in the World Energy Weekly (Dec. 10 issue), a publication of Petrostrategies, a French think-tank specialized in research on energy, economy and geopolitics.
ExxonMobil and Chevron are pulling out of Azerbaijan, probably because the country’s contractual terms have become less attractive than before, while growth potential has been eroded and development and production costs are set to increase. The two US majors have therefore decided to sell their stakes in the Azeri Chirag and Deepwater Gunashli (ACG) fields and invest elsewhere in the world in more profitable projects with greater growth potential, such as ExxonMobil’s discoveries in Guyana, or Chevron’s US shales. Exxon currently has a 6.79% stake in ACG, while Chevron holds 9.57%. ExxonMobil is hoping to raise some $2 billion through this sale, according to sources close to the issue. This implies that Chevron may expect to sell at around $2.8 billion. While ExxonMobil has made no comment on the proposed divestment, Chevron has confirmed its intention to withdraw. “Chevron regularly reviews its global portfolio of assets to ensure alignment with its long-term priorities. As part of this review, we have decided to initiate the process of marketing, with a view to a potential sale, of our Chevron affiliate interests in the Azeri Chirag and Deep Water Gunashli project and the Baku-Tbilisi-Ceyhan (BTC) Pipeline”, the major said in a statement issued on December 4.
The original ACG contract, which came into effect on September 20, 1994, was to expire in 2024. In 2017, the consortium’s member-companies persuaded the Azeri government that a more distant deadline was needed. Otherwise, they would not be able to make the investments required to restore declining production and enhance the recovery of the remaining reserves. A new contract was signed on September 11, 2017. It was ratified by the Azeri Parliament on October 31, 2017, and runs until December 31, 2049. BP, as operator, therefore prepared a program to redevelop ACG. A final investment decision (FID) is to be made in 2019. In terms of improved production, the initial results of BP’s program are expected in 2023. The consortium’s member-companies have pledged to pay the government a bonus of $3.6 billion in eight annual installments. ExxonMobil and Chevron probably want to withdraw from ACG before FID in order to avoid engaging in heavy investments. In so doing, they will also be limiting their share of the bonus payments to only one or two annuities.
ExxonMobil and Chevron have probably decided that the profitsharing terms in the 2017 ACG contract are no longer very attractive
In 1994, BP accelerated the development of the ACG complex and started early oil production in 1997. However, the production target of 46.8 MMt (some 935,000 b/d) promised for 2009 could not be achieved. Production peaked at 40.3 MMt that year before starting to decline. It is about 580,000 b/d (29 MMt/annum) at present. BP is trying to stabilize it at this level by increasing gas injection, pending the implementation of the redevelopment program. Proven reserves were initially estimated at 5 to 6 billion barrels, and some 3.5 Gb has been produced to date. Some 1.5 to 2.5 Gb has yet to be produced. Redevelopment and production costs will probably be high.
In the new ACG contract, the production-sharing terms have been radically amended in favor of the Azeri state company Socar. The agreement stipulates that 75% of the profit oil will go to Socar and 25% to the consortium, regardless of the economic results. In addition, the bonus is no longer considered to be a recoverable cost. In the initial contract (1994), profit-sharing was dependent on the company’s real rate of return (RROR). According to the original contractual reference scenario, Socar’s share would have been 30% for an RROR of less than 16.75% if the cost of transportation to export ports was $3/b or less, and if early oil had been achieved (which is the case). Socar’s share rose to 55% if the RROR lay between 16.75% and 22.75% and climbed to 80% in the unlikely event that the RROR reached 22.75% or more. In its appendices, the 1994 contract provided for less favorable terms for the consortium if the latter failed to keep its promise of early oil, which was indeed achieved by the operator, BP. But did the British major take the necessary time and precautions to ensure optimal production and maximize recovery of reserves? The question arises due to the production failures experienced since. In any event, ExxonMobil and Chevron have probably decided that ACG’s profitsharing terms in the 2017 contract are no longer very attractive. Especially as the 20% tax on corporate profits was not removed.
