On 10 August 2018, the final Tender Protocol and model production sharing contracts for the 5th Production Sharing Round 2018 (5th Pre-Salt Round) were issued by the National Energy Policy Council (CNPE). This follows draft versions issued on 28 June 2018 and the CNPE publishing Resolution No. 4/2018 on the 11 May 2018 which established the technical and economic parameters for the round, as well as formally authorising the National Agency of Petroleum, Natural Gas and Biofuels (ANP) to carry out the bidding process. The 5th Pre-Salt Round will offer four areas located in the Santos and Campos Basins: Saturno, Titã, Pau-Brasil and Sudoeste de Tartaruga Verde.
5th Production Sharing Round blocks
The final fiscal terms that apply to the round are:
- Signature bonuses: Saturno — R$ 3.125 billion; Titã — R$ 3.125 billion; Pau-Brasil — R$ 500 million; and Sudoeste de Tartaruga Verde — R$ 70 million.
- A royalty rate of 15%.
- Biddable cost recovery ceiling in a matrix comprised of daily production (five biddable tranches) and oil price (four biddable tranches).
- Biddable state share of profit oil (after royalty and cost recovery) in tranches defined by an oil price and production matrix based on the Brent crude oil price and the average daily production of each producing well. The minimum state share of profit petroleum at a US$ 50/barrel oil price and average production of 12,000 bo/d for each producing well is dependent on block (all other oil price/production scenarios are based on pre-determined formulas for each matrix cell using the bid amount). The CNPE defined the minimum percentages of state profit oil for each block as: Saturno — 17.54% (was 9.56% in the draft version); Titã — 9.53% (was 5.80% in the draft version); Pau-Brasil – 24.82%; and Sudoeste de Tartaruga Verde — 10.01%.
- Petrobras will only participate in the Sudoeste de Tartaruga Verde block with a 30% interest as operator.
- The minimum mandatory local content rates are for Saturno, Titã and Pau-Brasil: (i) exploration phase — minimum global requirement of 18%; and (ii) development phase — 25% for the well construction, 40% for the collection and offloading system, and 25% for the stationary production unit. These percentages may not be waived. For the Sudoeste de Tartaruga Verde the minimum local content rates are: 55% in the exploration phase and 65% in the development phase.
- Income tax payable.
Brazilian President Michel Temer approved the 5th Production Sharing Round in May and on 13 July the ANP disclosed that 20 companies had indicated an interest in participating including Petrobras, ExxonMobil and Total. Registration for the round closes on 24 August with bid submissions due to take place on 28 September 2018.
On 2 March 2018, the Danish Energy Agency issued its approval of A.P. Moller-Maersk A/S’s sale of Maersk Oil & Gas A/S to Total. The Danish Energy Agency’s approval of the transfer contains conditions, including that A.P. Moller-Maersk, as seller, assumes a secondary liability for the decommissioning of existing Danish offshore facilities corresponding to Maersk Oil’s 31.2% interest in the Danish Underground Consortium, should Total be unable to cover such costs.
On 21 August 2017, A.P. Moller-Maersk A/S announced the sale of Maersk Oil & Gas A/S to Total for a total US$ 7.45 billion in shares and debt. Under the agreed terms, A.P. Moller-Maersk will receive a consideration of US$ 4.95 billion in Total shares and Total will assume US$ 2.5 billion of Maersk Oil’s debt. Total will issue to Moller-Maersk, 97.5 million Total shares (based on the average Total share price on the 20 business days prior to 21 August 2017) which represents 3.75% of the enlarged share capital of Total.
Total said Maersk Oil brings to Total the following:
• Proved plus probable reserves (2P) and resources (2C) of approximately 1 billion barrels of oil equivalent (boe), 85% of which are in OECD countries (more than 80% in the North Sea).
• The addition of 160,000 boe/d of mainly liquids production in 2018, acquired at an average price of US$ 46,000 per boe/d, offering high margins with an estimated free cash flow break-even of less than US$ 30/barrel and growing to more than 200,000 boe/d by the early 2020’s further strengthening Total’s leading production growth outlook.
• Total expects to generate operational, commercial and financial synergies of more than US$ 400 million per year, in particular by the combination of assets of Total and Maersk Oil in the North Sea, an area of excellence for both companies.
• The transaction is immediately accretive to both earnings and cash flow per share underpinning Total’s dividend profile.
Maersk Oil production comes from Denmark, UK, Norway, Kazakhstan, US Gulf of Mexico and Algeria. Exploration and development activities are on-going in Angola, Kenya, Brazil, Kurdistan in Iraq and in above producing countries. As at 31 December 2016, Maersk Oil proved plus probable reserves were reported to be 550 MMboe.
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In a press release dated 26 December 2017, Permanent Court of Arbitration on behalf of the Conciliation Commission conducting arbitration into the defining of a maritime boundary between Timor Leste and Australia, said that the two countries and the Greater Sunrise Joint Venture (GSJV) had agreed the signature of a maritime boundary treaty in early March 2018.
On 30 August 2017, the governments of Timor Leste and Australia reached agreement on a Comprehensive Package Agreement regarding maritime boundaries in the Timor Sea. This agreement was formalised into a draft treaty and initialled by each government in October 2017 in The Hague.
Timor Leste Maritime boundary
In broad terms, the draft treaty delimits the maritime boundary between Timor Leste and Australia in the Timor Sea and establishes a Special Regime for the area comprising the Greater Sunrise Complex (GSC). The draft treaty also establishes revenue sharing arrangements where the shares of upstream revenue allocated to each country will differ depending on downstream benefits associated with the different development concepts for the GSC.
The GSJV operates the GSC which currently straddles the Australia and Joint Petroleum Development Area (JPDA) boundary in the ratio 79.9:20.1 in favour of Australia. The GSC includes the Sunrise, Sunset and Troubadour Fields. Sunrise was discovered in 1974 which means the discovery and associated fields have been stranded for some 40 years. In 2010, the GSC total contingent resource was independently certified to be 5.13 trillion cubic feet of dry gas and 225.9 million barrels of condensate. The GSC joint venture comprises: Woodside (operator 33.44%), ConocoPhillips (30%), Shell (26.56%), and Osaka Gas (10%).