During Q2 2018, 28 bid rounds were identified as ongoing offering over 725,000 square kilometres of E&P acreage worldwide. To date, during the quarter 17 bid rounds in 6 countries have opened and 7 have closed. There are 9 estimated to open through the remainder of the quarter. Typically, each country promoting acreage provides a fiscal regime under which the areas can be licensed. Three regime types are used: Royalty/Tax, Production Sharing Contract (PSC), and Service Contract. However, in recent years a fourth hybrid regime, referred to as a Revenue Sharing (RS) regime has also been introduced.
NEW TENDERS ANNOUNCED
Egypt – EGPC 2018 International Bid Round
One of the most recent rounds to open is the Egyptian General Petroleum Corporation (EGPC) 2018 International Bid Round. The round launched on the 22 May 2018 and includes 11 blocks: seven of these blocks are located in the Western Desert, with the remaining four located in the Gulf of Suez. The round is scheduled to close on 1 October 2018 and the blocks are being offered under a PSC regime. The commercial parameters accompanying the round have been released and indicate that the blocks awarded in the round will have a 7-year maximum exploration period, followed by a Development Lease (DL) which will have a maximum duration of 30 years. EGPC will pay the contractor’s Royalty and Income Tax liabilities. The cost recovery ceiling is biddable but may not exceed 40% and amortisation of exploration and development expenses will be a minimum of four years. Operating costs are expensed. Contractor Profit Oil is a biddable parameter and is based on production tranches linked to the Brent Oil Price. EGPC’s share should not be less than 75% at a Brent Oil Price less than or equal to US$40/barrel and at a production rate of less than 5,000 bo/d. Higher oil prices and production levels require a State share of more than 75%. The State Share of Profit gas is also biddable based on daily production tranches. Any excess cost recovery is allocated 85% to the State. Additionally, several bonuses are also required including: Signature Bonus (competitive); Retention of Relinquished Area Bonus; Development Lease Bonus (minimum of US$100,000 per Development Block); Production Bonus (biddable and dependent on daily production rates); Five Years Extension Bonus (minimum US$5 million); Training Bonus (minimum US$100,000 annually); and an Assignment Bonus (which will be 10% of any transaction completed by the contractor and associated with the block).
Norway – APA 2018 Bid Round
The largest round currently open is the Norwegian Awards in Predefined Areas (APA) 2018 Bid Round. The APA 2018 round opened on 9 May 2018 and offers 826 blocks covering over 225,000 sq km. For the 2018 release, 47 blocks in the Norwegian Sea and 56 blocks in the Barents Sea have been added to the previously available areas. The deadline for applications is 4 September 2018 and awards will be announced during Q1 2019. The APA rounds are held annually and apply to mature acreage on the Norwegian continental shelf. Previously in APA 2017, 75 licences totalling 21,748.5 sq km, were awarded to 34 companies.
Norwegian upstream oil and gas operations are governed through a Royalty/Tax regime. Acreage is awarded under a Production Licence which has a total length of 30 years; an extension of up to 30 additional years is also available. Royalties are not payable on oil production from fields where the development plan was approved after 1 January 1986. Additionally, the royalty rate effective since 1 January 1992 on gas production is zero percent. Instead a Special Petroleum Tax (SPT) at a rate of 55% is levied on gross revenue less exploration costs, operating costs, royalty, carbon dioxide tax, and depreciation of development costs. The SPT includes an extra allowance in the form of an uplift, which is 21.2% calculated at 5.3% over 4 years. Income tax at a rate of 23% is also applicable. In order to encourage new exploration in the area and support economically viable exploration the government introduced a reimbursement system in 2005. Under the system, companies making a loss can choose between requesting an immediate refund of the tax value of the exploration costs or carrying forward the losses to a later when the company has taxable income. Exploration costs under the immediate payment option are not deductible from income in later tax assessments.
Australia – 2018 Australia Offshore Petroleum Acreage Release
Additionally on 15 May 2018, the Australian Government released 21 new tender areas for the 2018 Australia Offshore Petroleum Acreage Release and seven re-released areas from the 2017 Australia Offshore Petroleum Acreage Release. Round 1 of this release is scheduled to close on 18 October 2018. In Australia upstream oil and gas operations are governed by location. Onshore and in state waters up to three nautical miles (~5.5km) offshore each state or territory has jurisdiction. Offshore beyond the three nautical mile limit the Federal government has jurisdiction.
The Australian Federal offshore area is governed under a royalty/tax regime through the Offshore Petroleum and Greenhouse Gas Storage Act 2006 and Federal tax legislation. A feature of the Australian fiscal regime is the use of the profit-based Petroleum Resource Rent Tax (PRRT) which was originally applied to Federal waters offshore, but which also applies onshore (and the Northwest Shelf Project area) from 1 July 2012. PRRT is a federal tax levied at a rate of 40% and is ring-fenced to individual petroleum projects. In 2017, there was political manoeuvres to alter the PRRT mechanism which advocated decreasing the uplift rates on exploration expenditure but the 2018 Federal budget, which was presented in May 2018, made no mention of any changes. However, despite the budget failure to address the PRRT uplift rates, industry is still of the belief that the PRRT uplift rates will be decreased in the medium term. The Corporate Income Tax rate is currently 30%.
Ecuador – Ronda Intracampos 2018
Ecuador was initially planning to open the Ronda Intracampos licensing round in March 2018, however the country is now anticipating launching the round in June 2018. Eight blocks in the Oriente-Maranon Basin in the north east of the country will be available in the round and will be offered under a ‘Participation’ contract which is a PSC regime. Previously Ecuador has governed activities under a Service Contract regime. Bids will be evaluated primarily on the production share offered to the State and also on the total exploration investment committed (annual work commitment plans). The blocks on offer will be carved out of state-owned Petroamazonas acreage and have 13 undeveloped fields between them.
The Ecuadorian government is hoping to entice more oil companies to the new Intracampos round with the change in the fiscal framework. Under the new PSC regime, private companies can take their share of production in kind and therefore book reserves. This was not possible with the old Service Contract model. Previously in 2010, Ecuador converted all its previous contracts signed with foreign investors, including participation contracts (as PSCs are referred to as in Ecuador), marginal field contracts, and “old” Service Contracts, into a new type of Service Contract.
Dominican Republic – 2018 Dominican Republic Licensing Round
One of the rounds planned for Q3 2018 is the 2018 Dominican Republic (DR) licensing round. The DR has been working towards a licensing round since 2015 and initial plans include offering four blocks for exploration in two phases. During Phase 1, two blocks are expected to be issued: Azua (~13.4 sq km) and Enriquillo (~177 sq km). This release will be followed by a second tranche which will focus on the offshore in the Bay of Ocoa (~435 sq km) and the San Pedro de Macoris play (~7,922 sq km).
Both phases will be offered under a PSC regime. Pertinent terms from the model contract dated 26 March 2018 include a Special Tax on Hydrocarbons (IEH) which replaces Income Tax established in Law 11-92 of 16 May 1992. The IEH rate is based on an internal rate of return (IRR) calculation and adjusted by an additional amount bid by the contractor (X%). The IRR calculation is in four tranches (based on effective interest rate of Dominican Republic sovereign debt (Y%) and adjusted by 0% to 10% according to tranche) with rates of IEH between 40%+X% and 55%+X%. The maximum share of gross income available for cost recovery is 80%. Additionally, annual fees are required at four milestones within the project which are: First production – US$50,000, 0 to 30,000 boe/d – US$80,000, 30,001 to 50,000 boe/d – US$120,000, and greater than 50,001 – US$180,000.
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