During 2017, Aker BP increased its reserves (2P) by a net of 202 million barrels of oil equivalents (mmboe), to a total of 913 mmboe. The company delivered significant growth, while simultaneously chasing cost per barrel produced, and had efficient operations with high operational uptime. Aker BP has a strong cash flow outlook and a robust balance sheet with a USD 2.9 billion liquidity reserve, enabling the company to increase dividends for 2018 to USD 450 million, and further strengthen its position as the leading independent E&P company offshore.
'We are well positioned for further growth. The acquisition of Hess Norge in 2017 significantly enhanced our production and resource base, and the submitting of three PDO’s late 2017 represents further important building blocks in our growth ambition,' says Aker BP CEO Karl Johnny Hersvik.
Aker BP’s pro-forma production in 2017 was 160 mboepd, including the production from Hess Norway. About 80 percent was oil and 20 percent gas. 2018 production is expected to be between 155 and 160 mboepd, with an average production cost of 12 USD/boe. With its current portfolio, the company has the potential to produce 330 mboepd in 2023 (from both sanctioned and non-sanctioned projects), representing a compound average growth rate of 13 percent.
While the company’s oil and gas reserves grew to 913 mmboe at the end of 2017, contingent resources were estimated at 785 mmboe at year-end 2017, each with an increase of approximately 30 percent from the previous year. Organic reserve replacement ratio (RRR) was 2.3 times production, and the total RRR was 4.5 times.
Aker BP has a robust balance sheet with USD 2.9 billion in available liquidity, providing the company with ample financial flexibility and dividend capacity. At year-end 2017, the company’s net interest-bearing debt was estimated at USD 3.2 billion. Aker BP plans investments of approximately USD 1.3 billion in 2018. Exploration expenses are expected to be approximately USD 350 million, while decommissioning expenditures are estimated at USD 350 million in 2018. The increase in decommissioning spend is mainly due to the increased ownership at Valhall.
'Our financial position has been strengthened. We have seen a rapid de-leveraging, and foresee a solid cash generation combined with a strong liquidity position. We are proposing to increase dividends for 2018 to USD 450 million, and have a clear ambition to grow dividends further in the coming years by USD 100 million annually to 2021,' says Hersvik.
Aker BP has an ambition to discover a net of 250 mmboe oil and gas in the 2016 – 2020 period. The company will continue its active exploration strategy in 2018 with 12 exploration wells to be drilled, with risked pre-drill estimates ranging from 50 – 150 mmboe net to Aker BP.
In 2017, the company submitted three PDOs (Plan for Development and Operation) to the Ministry of Petroleum and Energy (MPE) for the Valhall Flank West, ?rfugl and Skogul fields. These developments will substantially strengthen Aker BP’s reserves and production from its operated field centers at Valhall, Skarv and Alvheim, while at the same time contribute to reduce the overall cost per barrel for the company.
Production output from the Alvheim FPSO increased compared to previous year due to new wells at Viper-Kobra and Volund infills. Further infill wells are being matured to arrest the production decline and minimize unit production cost.
Aker BP is maturing further infill projects at the Valhall area. New wells will be drilled from the Valhall injection platform, while abandoned wells are being plugged. The ambition is to produce another 1 billion boe from the area.
At the Skarv area, a PDO was submitted for ?rfugl in 2017. In the first phase, three new wells will be tied into Skarv. The estimated first gas from the new wells will be in 2020. New drilling opportunities to increase oil production and optimize production are being matured.
The first year of production from Ivar Aasen was successful, and plateau production was reached in Q4-2017, one year ahead of plan. Near-by exploration prospects are being evaluated, and area infill drilling opportunities identified.
Further infill wells at Ula and Tambar are being evaluated, and the Oda development is ongoing. The Tambar re-development is well underway, expecting first oil in 2018.
Summary of 2018 guidance:
2018 production: 155-160 mboepd
2018 Production cost: USD ~12 per boe
2018 CAPEX: USD ~1.3 billion
2018 EXPEX: USD ~350 million
2018 decommissioning expenditures: USD ~350 million
2018 dividends: USD 450 million
Year end 2017 2P reserves: 913 mmboe
Year end 2017 2C contingent resources: 785 mmboe