Gazprom Neft Gets Down to Work in Iraq

Alexander KolomatskyInterview with Alexander Kolomatsky, the head of the Badra project in Iraq
March 2011. NEFTE COMPASS, Energy Intelligence Group, Inc

Gazprom Neft has two and a half years to bring on stream Iraq's Badra oil field, which it won in 2009. As operator of the 3 billion barrel field, Gazprom Neft has to ensure that front-end engineering and design (FEED) is completed by the middle of this year, and that a huge amount of work, including infrastructure construction, is completed by 2013. In an interview with Nefte Compass, the head of the project for Gazprom Neft, Alexander Kolomatsky, describes the challenges the company, which holds 30% of the project, is facing in a consortium with Iraq's Oil Exploration Co. (25%) South Korea's Kogas (22.5%), Malaysia's Petronas (15%) and Turkey's TPAO (7.5%).

Q: Why did Gazprom Neft chose the Badra oil field as its first project in Iraq?

A: In 2008, Gazprom Neft went through the prequalification procedure to take part in Iraqi post-war bidding rounds. Under the rules, participants were divided by the status they were ascribed: an operator without limitations, which could bid for any field tendered; an operator with limitations, which could compete for certain fields; and a participant. Gazprom Neft took part in the first licensing round as a participant. We were invited to form a consortium with Turkish TPAO and OVL, an international subsidiary of India's ONGC, to compete for the Zubair field. Unfortunately, our offer was not the best one and Zubair went to a consortium led by Italy's Eni. In the second tender round we were qualified as an operator without limitations, so we could potentially work at any of the 10 fields tendered and invite other firms to join us in a consortium. After studying the fields available, we chose Badra as the most attractive option for several reasons. First, we selected it because production at other fields, such as West Qurna-2 and Majnoon, is supposed to average 1 million barrels per day which exceeds Gazprom Neft's own domestic output. So we have chosen a smaller field compared to other Iraqi supergiants, but quite a big one for Gazprom Neft to take on as the operator of the project. Second, we knew that would be able to receive more data on the Badra field, where there was only one well drilled which registered commercial crude flows, while drilling of the second well was stopped when the war between Iraq and Iran started. So we had quite scarce data on the Badra field, but at that time we had already started negotiations with neighboring Iran on its Anaran block, where the Azar oil field lies, which in fact is a continuation of the Badra field.

Q: How did you manage to receive operator status in the second licensing round?

By the time the second round took place, the company had been working very closely with the Iraqi Ministry of Oil. Gazprom Neft was able to meet all the requirements to become a full operator except for one: a company should have had crude production overseas, while Gazprom Neft's output was all in Russia. But in a second round Gazprom Neft managed to prove that it is a fully integrated oil company able to solve problems, and this last limitation was dropped. Gazprom Neft received operator status and the right to form a consortium. Gazprom Neft's subsidiary, Gazprom Neft Badra, is responsible for all operations at the field.

Q: Last year, Gazprom Neft signed service contracts for mine clearance and 3-D seismic at the Badra field, which should be completed by summer. How is work progressing?

A: Mine clearance is a challenging task for all companies working in Iraq. The territory was left untouched since the war finished in 1988 and we still face the consequences of the fighting and battles here. Gazprom Neft has announced that 50% of mine clearance work has already been completed.

As far as seismic is concerned, we are planning to complete it by May-June since we hired another staff brigade in mid-February to accelerate activities.

Q: What should be done at the Badra field during 2011-12 before production starts up?

A: We plan to start drilling at the field in April-May as soon as we receive approval from the Ministry of Oil to award a drilling contract. Under the current plan, we should drill one deep exploration well to a depth of 6,000-6,200 meters and three appraisal wells, including the one which had already been started before the war. The deep exploration well is targeted to find undeveloped reservoirs in addition to two reservoirs we can develop under the contract. If we discover new reservoirs, we can sign supplementary agreements to develop those if it is commercially profitable. By mid-2013 when initial output should start, we should have eight wells, including three that will be transformed from appraisal to production wells. Under the current development plan, there should be a total of 17 wells at the field by 2017.

The second big task we have to accomplish before production starts is infrastructure construction at the field, located in the remote Wasit Governorate.

Q: Has the budget for 2011-2012 been approved?

A: The project's total costs were preliminarily estimated at $2 billion. This year's budget has been approved at $243 million. In 2012 investments are preliminarily planned at $436 million.

Q: How will financing be divided among partners?

A: Financing is carried out by consortium members proportionally to their shares. The only exception under the contract is our Iraqi partner, Oil Exploration Co. (OEC), which means that Gazprom Neft pays 40% of the expenses although it has a 30% stake in the project.

Q: Can you describe how cost recovery (compensation) and remuneration mechanisms work?

A: We start to receive payments as soon as we reach initial output at the field of 15,000 b/d. Under the contract, we should start and maintain first commercial production in mid-2013, four months before Dec. 5 when the Iraqi government should legalize it. Under the contract, we are entitled to petroleum costs, supplementary costs and remuneration. Petroleum costs are audited annually and cover all expenses for developing a field, while supplementary costs include expenses on construction facilities outside the contracted area – oil and gas pipelines, storages and reloading facilities in Nasiriyah. These costs are compensated. In addition we receive a remuneration fee of $5.50 per every barrel of oil equivalent. The base for all payments is the value of net hydrocarbons production. Petroleum costs and remuneration shall be paid to the extent of 50% of the deemed revenue from net production, plus we have an additional 10% for supplementary costs. Payments should be split between participants equally to their stakes. OEC, which is freed from financing, receives only revenues.

Q: Will the consortium receive payments in dollars or barrel equivalents?

A: Under the contract, both compensation and remuneration payments can be made either in money or in crude equivalent. A single decision has to be taken annually before Apr. 1. We have preliminary agreements with other participants that we want to receive payments in barrels of crude. But whatever option we chose, payments should be equal regardless of whether we receive crude or the money equivalent. If we decide to be repaid in barrels, each participant will market it separately.

Q: What kind of crude is it going to be in terms of quality and will you need extra facilities to treat the crude? What are the production plans?

A: By 2013 we should prepare final production plans based on seismic, appraisal and exploration data. Under the current plan production is expected to start at 15,000 b/d in 2013 and average 22,000 b/d by the year-end. After that output will grow constantly to 64,000 b/d in 2014, 117,000 b/d in 2015, 135,000 b/d in 2016, and plateau at 170,000 b/d in 2017 and for the next seven years. Badra crude is a light crude of 34°-35° API, close to Brent in characteristics. But its sulfur content is 3%-4%. Under the contract, we should clear the sulfur from the crude. But we only have the right for all hydrocarbons produced at the field, so we are still negotiating with the Iraqi side as to what would be done with the sulfur -- granulated or liquid – received after crude treatment.

Q: Why have Badra reserves figures been revised several times? Will the participants be able to book the reserves?

A: The Iraqi government put Badra reserves at 1.2 billion bbl when the tender was announced. Coupled with the data received from Iran, we later estimated reserves at 2.4 billion bbl and later at 3 billion bbl. Once 3-D seismic is completed and appraisal wells have been drilled, the figures may go up again. Participants will probably have a chance to book the reserves. We are working with auditors to find out how this can be done.

Q: The Badra field in Iraq and the Azar field in Iran are two parts of the same field. What would be the benefits of developing them simultaneously?

A: First, both the Iraqi and Iranian governments should win if there is one operator and one development plan for the two fields, allowing each side to receive fair production. Second, that would certainly help to cut costs. Third, simultaneous development of both fields should help avoid any disagreements between the states.

Q: Is Gazprom Neft considering other projects in Iraq?

A: First, Gazprom Neft Badra was set up to implement this particular project and we are currently committed to it. But Iraq is the world's second-largest country in terms of reserves and it has great potential. There are two options Iraq may offer in the fourth licensing round. One is the number of fields which were not awarded during the first and second rounds, including the giant Kirkuk, East Baghdad fields. The second is exploration in the Western Desert. Both perspectives look attractive not only in terms of huge oil and gas potential, but also in terms of production costs, which average $2-$3/bbl in Iraq, lower than those that Russia has in West Siberia.