Figure 1 – Map of 85 countries with current bid rounds and open-door opportunities
Over the past 18 months there has been a surge of bid round activity around the world. In fact, some 85 countries have either launched a bid round (more than 105) or held open-door policies (Figure 1). This activity covered approximately 1.6 million sq km on offer representing a total of 3,569 blocks located both onshore and offshore, including deepwater areas (Figure 2). Out of a total of 49 countries offering bid round acreage, those which dominated in the period included: Australia, UK, Denmark, Mexico, India, Argentina, Brazil, Ukraine, Poland and Croatia.
Figure 2 – Past bid round activity compared to oil price
The trends observed in acreage offers in the period 2018 – Q1 2019 are:
- Very busy bid round activity
- Regime changes significant
- Increases in flexibility of regime choice
- Countries continue to issue incentives and disincentives
- Many countries continue to offer deepwater terms
- Gas terms remain more lenient reflecting higher costs and marketing obstacles
- Typically, no terms specific to unconventionals (shale/CBM)
- Bans on exploration became more prevalent due largely to opposition to fossil fuel developments by environmental lobby groups
- Increased instance of countries having first bid round
One of the most marked changes is the emergence of the revenue sharing contract (RSC) in such countries as Indonesia, Mexico, India, and Ecuador. In most cases, the reasoning behind the shift from a production sharing contract (PSC) regime to an RSC regime is the removal of the cost recovery element. In both Indonesia and India cost recovery issues caused a great deal of problems over exactly what is cost recoverable and how this cost recovery is funded by the state. In Thailand, unlike Indonesia and India, the trend has been to adopt a PSC regime after the country had preserved solely with a concession regime for many years. The authorities have retained the concession system but adopted the PSC for specific blocks, most notably in the renewal of the Erawan and Bongkot gas field blocks located offshore in the Gulf of Thailand. The PSC is also to be used in the long-delayed 21st bid round.
Another trend observed during this period is the preponderance of cancelled or suspended exploration in many areas of the world due largely to the influence of environmental lobby groups against the usage of fossil fuels. Often, this also stemmed from opposition to the practice of fracking on adverse environmental grounds. Some of the countries involved in partial bans and/or moratoriums on exploration include France, Denmark, Germany, Ireland, Italy, Norway, UK, onshore eastern Australia and offshore New Zealand (Figure 3).
Figure 3 – Countries issuing partial bans or moratoriums on exploration
Also notable are countries planning or holding their first bid round including Ghana, Guyana, Kenya, Dominican Republic, Panama, Senegal, Somalia, and Cuba (Figure 4). Most of these inaugural bid rounds have been delayed or extended multiple times.
Figure 4 – Countries planning or holding their first bid round
The most notable fiscal incentives to be offered in this period have been in Angola, Indonesia and India, again showing the governments’ intention to encourage exploration activity. In Angola, the authorities have issued several incentives in an effort to slow declining production. These incentives include tax relaxation on some deepwater blocks, unique terms for the development of marginal fields and additional legislation allowing stand-alone gas field developments to proceed. In 2017, Indonesian authorities introduced and then amended the “gross split” RSC scheme, to take account of field variables and oil & gas prices with the effect that, in some cases, increase the contractor’s share of gross production to as much as 70 percent. In India, the authorities introduced a new policy to encourage exploration in unexplored areas and applied reduced royalty rates (10 percent concessional) on additional gas production from established production areas.
The most notable fiscal disincentives to be offered in this period have been in Romania and Australia. In Romania, authorities introduced the “Offshore Law” which requires offshore developments to pay extra income tax based on gas prices and the requirement to market at least 50 percent of gas production within the country. The advent of this law caused the postponement of investment decisions on two Black Sea gas developments (Midia and Neptun). In Australia, as a response to growing disgruntlement over low returns to the state from large export LNG projects, the authorities adjusted the uplift rate applied to exploration costs for the calculation of Petroleum Resource Rent Tax (PRRT) — the rate was lowered from 15 percent to 5 percent but is not retrospective. In addition, onshore developments were removed from the PRRT net after they were first included in 2012.
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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%).