The UK West of Shetlands (WoS) doesn’t often take the limelight as a frontier area that is becoming a developing hub, but here are some reasons it should: Movers and shakers like Total, BP and Premier operate producing fields in the area; Chevron had been working to towards and FID for Rosebank, and Equinor will soon take over the reins; and Siccar Point and Nexen have exploration and appraisal drilling planned for the near future.
Fig 1 WOS fields
BP commenced production in the basin at Foinaven Field in 1997, and soon added Loyal and Schiehallion; all three fields produce oil via FPSO, and gas via pipeline to Sullom Voe terminal. Since then, Clair, Greater Laggan Area, and Solan have all been brought to production, with Clair Ridge set to join later this year.
Fig 2 WOS field discovery to production
To date, the basin has produced over 0.5 Bbo and 0.6 Tcfg, but the area is challenging due to the remoteness, harsh weather, and water depths which reach over 1,000m towards the UK-Faroe Islands border. The progression from discovery to production (Fig. 1.) has often been drawn out; Laggan took 30 years to bring online, Clair 28 years, and Solan 25 years. The delays at Clair can at least partly be explained by the difficult, fractured reservoir, and BP’s focus on Foinaven, Schiehallion and Loyal. The Greater Laggan Area development required significant investment to construct the Shetland gas processing plant and install a 142 km oil and gas export pipeline, one of the world’s longest deepwater tie-backs to shore. The Total-led partnership invested US$5.4 billion in the project but lead contractor Petrofac still lost over US$ 400 million on the project. Appraisal at Solan was initially unsuccessful, until Chrysaor obtained better drilling results in 2007 and then sold the field onto Premier.
Fig 3 WOS Annual Production
Fig 4 WOS Comparative Cumulative Production Oil
Fig 5 WOS Comparative Cumulative Production Gas
Ongoing development, exploration & appraisal
What you will likely have heard a lot about, is Hurricane Energy’s 100% owned early production system at the Lancaster fractured basement field due to come onstream via FPSO at the end of 2020, with estimated resources exceeding 200MMbo. Before that, BP intends to commence output from Clair Ridge, due online this year, and expected to produce until 2050. Elsewhere, Equinor is acquiring Chevron’s operator share of Rosebank discovery with 2P reserves of 125-150 MMboe in Flett Formation. Chevron had been working towards FID on the field, with development costs of US$ 7 billion indicated in 2017.
Siccar Point acquired OMV UK at the beginning of 2017, including the Cambo discovery in Palaeocene Flett Formation. Alongside new partner Shell, it was appraised during summer 2018, and Cambo resources are estimated at 177 MMbo and 109 Bcfg. And Total made the most recent discovery in the basin with the Glendronach NFW in Q2/Q3 2018, estimated to hold 1 Tcfg in Early Cretaceous reservoir (42m net pay), drilled from the Edradour platform location, and likely to be developed as part of the Grater Laggan Area.
Planned exploration and appraisal
Looking ahead, Nexen and partner INEOS plan to appraise Cragganmore discovery in Palaeocene Vaila sands during Q4 2018. Siccar Point intends to drill Lyon and Blackrock prospects in 2019. Lyon was scheduled for 2018 but delays at the WoS Cambo appraisal well pushed the drilling into winter 2018/19. Lyon has estimated 1-3 Tcfg recoverable in Flett sandstones which could justify a stand-alone gas hub development.
Spirit Energy, the Centrica and Bayerngas Norge joint venture, agreed to farm into Hurricane’s fractured basement play for 50%, and later operatorship in Lincoln discovery and Warwick prospect in September 2018 for full carry on a 2019 planned drilling campaign of two horizontal exploration sidetracks on the Warwick prospect and one appraisal horizontal sidetrack at Lincoln, plus partial carry of Hurricane’s costs of a resultant field development.
The WoS has benefited from the combination of new companies backed by investment and established supermajors working together. The UK 30th round, targeting frontier areas saw awards announced in May 2018 where companies producing and exploring in the WoS picked up the acreage adjacent to their existing licences. In contrast the Faroe Islands 4th Exploration Round in 2017 across the border had its sole application for acreage withdraw post-closing of the round. Overall, development in WoS is looking pretty attractive if you’re willing to put up the capital. The basin will likely see a continued moderately slow build-up of development that will allow small discoveries to be profitable, experience more exploration, and hence be an active region for decades to come.
Poland is amongst the fastest growing European economies, with an educated population, EU membership, and a strong industrial base. But its domestic hydrocarbon supplies are nowhere near adequate for its needs – gas production of around 220 Bcfg per annum meets about a third of requirements, whilst 15 MMbo per annum provides just 7% of the typical oil demand.
Poland currently imports around 60% of its gas from Russia but – unlike neighbouring Germany – is reluctant to depend on Russian gas to fuel its industrial development. State owned PGNiG, and partly state-owned LOTOS have invested in the Norwegian Continental Shelf and the Baltic Pipe is scheduled to be completed in 2022. Norway will then become Poland’s major gas supplier and direct Russian gas input is expected to end, although Russia will almost certainly contribute to future LNG imports.
Domestic production provides about a quarter of Poland’s gas demand and this figure is projected to drop to 20% by 2022. The country tried to reverse this trend when it embarked on Europe’s most aggressive shale gas exploration programme – attracting the likes of Chevron, ConocoPhillips, Eni, ExxonMobil, Marathon, Shell and Talisman – and 72 shale wells were drilled between 2009 and 2015. However the results were highly underwhelming and, with the industry hard-hit by falling prices, most foreign E&P investment withdrew.
Figure 1. Polish hydrocarbon concessions with Upper Silurian Coal Basin area highlighted
What Poland does have in abundance is coal and the country’s production of 150 million tonnes per annum satisfies the local market. However EU member countries are committed to a 7% reduction in CO2 emissions by 2030 (against a 2005 benchmark), so coal mining offers a poor long-term solution. But what about Coal Bed Methane (CBM) – a much cleaner process than coal mining?
During the height of the Polish shale rush, PGNiG drilled two CBM wells on its 2/2017/L Miedzyrzecze concession in the south of the country. Gilowice 1 & 2h targeted well mapped coal beds in the Upper Silesian Coal Basin (USCB), but the wells were suspended and only completed in 2016 when hydraulic fracturing, and testing over 9 months, produced sustained flows of 175,000 cfg/d.
Figure 2. Upper Silurian Coal Basin licensing – hydrocarbon blocks in green, coal blocks in red; Gilowice drilling highlighted via the bright green dots.
PGNiG has teamed up with three domestic coal companies – PGG, JSW and Tauron – to better understand the play and is now drilling a follow-up Gilowice appraisal programme. As well as Miedzyrzecze and nearby coal licences, several small local and regional companies hold prospective E&P acreage in the USCB which could be further exploited for CBM. Indeed, the Polish Geological Institute has estimated potential recoverable resources of 6 Tcfg.
Figure 3. Polish unconventional hydrocarbon exploration acreage
In the absence of offset Polish data, it’s useful to look at a US analogy for a hint of what might be in store for Poland, in this case, a multi-lateral coalbed methane well in La Plata Co, Colorado.
The well has grossed 4.29 Bcfg production in just under three years of production, has a relatively flat decline curve, and has a Best Efforts EUR of 14+ Bcfg, with a low current water cut, and a relatively small land footprint of about 0.5 sq km (130 acres) accommodating all laterals.
As the case study and preliminary resources estimates illustrate, success at Gilowice and the wider USCB could result in a very useful contribution to Poland’s future energy balance – 6Tcfg equates to 9 years of domestic demand at current consumption. Moreover, it could also re-invigorate unconventional exploration in Poland, with the government offering new shale prospective blocks. Polish CBM offers a potential gas supply guarantee in the near to medium term, and a bridge to the next phase of the country’s hydrocarbon sector.
New Zealand’s decision to ban future offshore oil and gas exploration has generated plenty of consternation for not only the energy industry, but the residents of New Zealand as the opposition party condemned the decision as “economic vandalism”. The future of oil and gas production in New Zealand since the government’s announcement has seen both sides of the coin, with industry commentators noting continued activity in the industry with planned and active projects continuing, but still wary of the plight of the industry if there are no further discoveries within the lifetimes of ongoing permits. In a move by the Labour Prime Minister Jacinda Ardern, to address climate change and honour her pledge of reducing the country’s net greenhouse gas emissions to zero by 2050, New Zealand becomes one of the world’s first countries to ban future offshore oil and gas exploration earning her the backing of environmental campaigners globally. France, Belize and Costa Rica are also primed to ban fossil fuel exploration and production; however, none are considered as notable energy producers.
Since the announcement in April, material released under the Official Information Act has generated skepticism over the decision with the government’s own experts reporting the ban a lose-lose for both the economy and environment. The Petroleum Exploration and Production Association of New Zealand (PEPANZ) CEO Cameron Madgwick has been scathing of the decision stating that the ‘surprise’ decision hadn’t come with any consultation and there were better ways of achieving environmental goals of lower emissions and sustainability without, what he believes, costing the economy.
New Zealand’s aspirations to become a lower emission country have been labelled bold and ambitious with many fearing that the repercussions of such a decision will actually lead to higher global emissions as the shortage of future oil and gas supplies will likely not meet the demand for New Zealand’s industry needs and the country will be forced to turn to imported coal. The uncertainty throughout the sector is pushing investors to look elsewhere, creating stress on the future of employment with the impacts of the ban just becoming evident. A billion-dollar, emissions-reducing rebuild of the Kapuni plant has been shelved citing the uncertainty of the industry. Ms. Jacinda Adern remains steadfast in her decision under her Labour rule that it is a change in direction, after the nine years of conservative leadership which favoured the fossil fuel industry, for New Zealand. “We’re protecting existing industry and protecting future generations from climate change.” Ms. Ardern said.
With research currently underway, due to be completed in late August, commissioned from the New Zealand Institute of Economic Research (NZIER) to explore the economic and environmental impacts of ending offshore exploration PEPANZ CEO Cameron Madgwick asserted, “Ideally the Government would have done this work before making a decision. As an industry we share their goals of lowering emissions and sustainably growing the economy, but an end to exploration doesn’t seem the right way to achieve this.”
New Zealand’s ban doesn’t mean the end of the industry with 22 out of 31 offshore existing exploration permits for exploration and extraction allowed to proceed to their full term, while the remaining permits onshore are unaffected by any decisions for the next three years and are due for review in 2020. Any oil and gas discoveries from the firms currently holding these licenses offshore can still lead to a mining permit for up to forty years, meaning the policy change protects current production employment within the industry for several decades.
Fig 1 – New Zealand offshore blocks by company
New Zealand from a global perspective is a relatively small oil and gas producer, with the majority of its production extracted from the five offshore fields of Maui, Pohokura, Kupe, Maari and Tui in the Taranaki Basin. The Taranaki Basin is only one of 17 sedimentary basins, with New Zealand largely under-explored for possible commercial quantities of oil and gas in the world’s fourth largest maritime exclusive economic zone.
The timing of the announcement from the Prime Minister is of particular curiosity as the international interest in New Zealand rebounds after the effects of low oil prices were highlighted with only one exploration block awarded from the 2016 New Zealand Tender Round and one from the 2017 New Zealand Tender Round in comparison to 10 in 2014. However, with the oil price recovery, interest from several international companies has seen a resurgence of industry activity. New Zealand Oil and Gas, despite their misgivings at the lack of notice regarding the Labour government decision, are prepared to continue with their current projects and in a statement, informed the public that its financial position will not be affected immediately by the ban. The recent Sapura Energy farm-in to several offshore blocks and OMV’s bid to acquire Shell’s upstream assets displays the potential investments New Zealand stood to gain with reports that oil and gas exploration and production companies spent NZ$ 8.7 billion between 2011-2016. According to PEPANZ the country, on average, produces 175 Bcfg, 15 MMbo and 1.5 million barrels of LPG a year; contributing NZ$ 2.5 billion to New Zealand’s Gross Domestic Product (GDP).
Going forward New Zealand has released a proposed 2018 New Zealand Tender Round limited to the area in the onshore acreage of the oil-rich Taranaki region, which has done little to appease the region with the mayor of the Plymouth city, Neil Holdom, labeling it “a kick in the guts for the future of the Taranaki economy”. He has since also been quoted as saying: “What I heard from a number of companies was deals scheduled to be looked at by boards have been pulled.” With few details able to be elaborated on, but “we’re talking, in some cases, about tens of millions of dollars.” In what the region sees as a positive deal, keeping their hopes alive, methanol exporter Methanex surprised the Ministry of Business, Innovation and Employment by signing an agreement to continue to operate until 2029 after reports suggested without a new discovery the Vancouver-headquartered company would abscond.
Fig 2 – Taranaki Basin E&P blocks and proposed onshore 2018 tender area
The long-term future of New Zealand’s oil and gas production, with the increased pressure of the offshore exploration ban, appears bleak with its present trajectory, as many of New Zealand’s fields reach the end of their economic lives. Austrian- headquartered OMV’s pending acquisition of Shell’s assets emphasizes the point, citing in its application to the Commerce Commission that despite the increase in its market share it would gain if the application is approved, those shares would drop off over time as the reserves of the Shell assets decline. Currently OMV holds a 26% partnership in Pohokura, one of the largest gas-condensate fields in New Zealand, and a 10% share in Maui. The Maui Field is expected to be depleted by 2023 barring the possibility of a new discovery within the production license PMP 381012 and the Pohokura Field, which supplies approximately 40% of the national gas market, is set to decrease its production over the next few years. Similarly, PMP 38158 which holds the Tui, Amokura and Pateke oil fields operated by Tamarind is set to enter its Phase 3 drilling project in a significant step to prolong the life of the Tui Field beyond 2019.
Fig 3 – Sapura Energy 2018 Taranaki Farm-in blocks
Despite the foreboding interpretations of New Zealand’s oil and gas future, the industry endures, with plenty of current continued activity and news of further planned projects emerging from the major players already invested in New Zealand. With the increase in oil price that appears, cautiously, to be stabilizing, the next few years in New Zealand will undoubtedly be noteworthy.
The Indian government intends that natural gas will become a far bigger proportion of the mix of domestic energy consumption in the future. Currently, gas (both imported and produced) forms just over 6% (or 58 Bcm for the year 2017-2018) of the energy requirement, with recent government policy statements envisages this to rise to 15% by 2030.
Source: BP Statistical review of World Energy 2018
Major investment in production from offshore gas fields (see below) is one element in the official plans, but is insufficient to meet demand.
Intergovernmental talks have been going on for years on major gas pipeline projects (from Oman, from Iran via Pakistan) but the progress has been snail-like. There are major geopolitical considerations which are impeding progress. So, the keystone to the policy is intention is to fill this energy gap by extending significantly LNG imports. Historically, Qatar has been the predominant supplier.
With the present LNG import of around 20 MMt/a, India is world’s fourth largest buyer, after Japan, South Korea and China. The plan to raise the share of natural gas will require a vast increase in imports and construction of more LNG terminals.
Diversifying sources of LNG imports
In 2012, state-run gas marketer Gas Authority of India Ltd (GAIL) signed a 20-year agreement with Russia’s Gazprom for the purchase of 2.5 MMt/a LNG. In June 2018, the first LNG cargo from Russia was delivered to the Dahej terminal in Gujarat.
Supplies have also started from the U.S. In March 2018, Cheniere Energy announced that it had a 20-year LNG supply to GAIL from the Sabine Pass liquefaction facility. The agreement for the supply of 3.5 MMt/a was signed in December 2011. GAIL’s Chairman stated that “GAIL is one of the foundation customers of Cheniere, having signed the contract in 2011. With supplies commencing from the U.S., GAIL will have a diversified portfolio both on price indexation and geographical locations”. LNG contracted by GAIL under the long-term deal with Cheniere Energy is priced at 115% of Henry Hub prices plus a fixed cost of US$ 3 / MMBtu. GAIL has also contracted to buy 2.3 MMt/a over 20 years from Dominion Energy’s Cove Point liquefaction facility.
Over the last three years, GAIL and state pipeline authority Petronet have reworked contracts with suppliers from the Middle East, Russia and Australia, reducing the negotiated price and increasing delivery flexibility.
At present, India has four LNG receiving terminals. All are on the west-coast: Petronet has a 15 MMt/a terminal at Dahej, and a 5 MMt/a terminal at Kochi; Shell has the 5 MMt/a terminal at Hazira; Ratnagiri Gas and Power operates the 5 MMt/a Dabhol terminal.
According to government spokesperson Narendra Taneja, the plan is to build no fewer than eleven new LNG terminals over the next seven years, to increase the import capacity to more than 70 MMt/a.
One of the first of these is expected to be commissioned later this year: Indian Oil Corp Ltd’s (IOCL) Ennore terminal in the south-eastern state of Tamil Nadu. This will be first LNG terminal on the east-coast and will have a capacity of 5 MMT/y.
In July 2017, construction work started on Dhamra LNG terminal on the east-cost in the state of Odisha. Dhamra will be the second LNG terminal on the east coast, and will have an initial capacity of 5 MMt/a which may be doubled to 10 MMt/a. Some 3 MMt/a will be used by IOCL, 1.5 MMt/a by Gas Authority of India Ltd (GAIL) and the remaining capacity will be available to other industrial users. The project, expected to be in operation by 2020-21, is being developed by Adani Group (50%), IOCL (39%) and GAIL (11%). The terminal will be connected to city gas and industrial customers with a 2,540km pipeline, including the metropolis of Kolkata.
The construction of Mundra LNG import terminal on the west-coast is reported to have been completed and the plant is expected to come on-stream by late 2018-2019. The project, which has a capacity of 5 MMt/a, is a JV of the Adani Group and Gujarat State Petroleum Corp Ltd (GSPCL). The pipeline connection to the terminal will send out gas to Gujarat’s main grid, critical for commercial operations.
The state-run Hindustan Petroleum Corp Ltd (HPCL) has formed an equal JV with Shapoorji Pallonji Port Pvt Ltd to build a 5 MMt/a capacity LNG terminal at Chhara Port on the west-coast. In addition, the Jaigarh LNG terminal in Maharashtra is being constructed by Hiranandani Energy, which has signed a contract with a US-based firm that wants to bring its own gas through this terminal.
Operations are also underway at existing facilities to enhance their output. While Shell at Hazira and Petronet at Dahej are planning to double the capacities, the completion of a breakwater project at Dabhol, along with pipeline connection at the Kochi, will see the Dabhol terminals operate at maximum capacity.
An aggressive approach to raise domestic production – the deep-water Krishna-Godavari Basin to be the key
With emphasis on importing more LNG from new sources, and investing in developing infrastructure, state-run ONGC and a major private player Reliance Industries Limited (RIL) are investing heavily in the deep-water Krishna-Godavari (KG) Basin.
RIL and JV partner BP announced in June 2017 that contracts will be awarded to progress development of the ‘R-Series’ deep-water gas field on the KG-DWN-98/3 (D6) deep-water block. This is first of three planned projects (Satellite and MJ-1 discovery being the other two projects) that are expected to be developed in an integrated manner, producing from about 3 Tcfg resources (in place or recoverable). Development of the three projects, with total investment of around US$ 6 billion (INR 40,000 crore), is expected to bring a gas production from this acreage to 1 Bcfg/d, ramped up over 2020-2022.
In March 2016, ONGC approved the Field Development Plan (FDP) for Cluster 2 on the KG-DWN-98/2 deep-water block, for a project cost of US$ 5 billion. The project is expected to produce cumulatively around 183 MMbo and 1.5 Tcfg, with peak production of 78,000 bo/d and 529 MMcfg/d. ONGC expects to bring first oil and gas from this project to market by late 2019. Cluster 2A’s peak production is pegged at around 78,000 bo/d plus associated gas (105 MMcfg/d), while Cluster 2B’s peak output is touted at 450 MMcfg/d.
In terms of consumption of the domestic gas, ONGC and RIL have started discussions with potential industrial customers in west India to supply them with gas expected to come on-stream in the next three years from the Offshore KG Basin. RIL is reported to be offering contract durations of three, five, and ten years. The companies are planning to use Reliance’s 1,375km pipeline which was built in 2009, connecting Kakinada in the east of the country to Bharuch in the west. The pipeline has been operating under-capacity in recent years due to a decline in production from RIL’s D1-D3 field in the KG Basin.
The government’s serious attempt and planning of a move towards increasing the use of natural gas in energy consumption is surely a path in the right direction. Backed by not just the financial commitments but also making use of technology from the likes of BP in the KG Basin, can certainly deliver results. However, in the past, execution of such effective plans has seen some delay in the country. But given the already vast middle classes grow in numbers, and consumer demand rises, execution of such plans will be crucial for India’s growth story.
The Campos Basin in offshore Brazil has been explored and produced since the 1980s, making it a relatively mature basin with a known working hydrocarbon system. Primarily Petrobras has been the dominant operator in the area exploring the post-salt resource. Resource potential in the Campos and Santos basins (includes only pre-salt) was published as 176 BBOE by a study conducted by the Federal University of Rio de Janeiro. A look at the current operator activity in the basin shows majors like Shell, BP, ExxonMobil and Equinor present in addition to Petrobras. After the late 1990s and the Brazil energy reform, Brazil and the Campos Basin were opened for operations and ownership to companies besides Petrobras.
Figure 1: Map showing the current block operatorship as well as Daily Oil Production (BBL/D) from producing fields in the basin.
There are over 40 producing fields in the Campos Basin, primarily operated by Petrobras, with one being appraised by Shell and two recent discoveries by Equinor (Figure 2). The production is the basin has been declining at about 9% per year recently, so new fields coming online will be welcomed with underutilized infrastructure capacity by the basin (Figure 3). Activity has been primarily post-salt, but there is potential for secondary and tertiary recovery efforts to be implemented in the declining fields plus additional pre-salt exploration opportunities to fill the under-capacity infrastructure in the basin.
Figure 2: Map showing the discovered fields in the Campos Basin. Many are actively producing, with a few currently being appraised and two that have recently been discovered.
There is development and production activity in the Campos Basin as Petrobras is in the bid process and/or actively deploying FPSOs to three fields (Figure 4). Petrobras is in the bid process to deploy an FPSO with 100,000bo/d and 176 MMCFg/d capacity. The Jubarte Field has an interesting story, as it originally was six separate post-salt fields, each with estimated resources in the 100 MMBOE range. Today, 25 wells are producing from the pre-salt in the Campos Basin, with 14 of these in the Jubarte area producing over 180,000 bo/d.
Figure 3: Block level production in the Campos Basin. Starting in 2008 there is a 9% decline/year in the basin.
The result of the large pre-salt discovery forced Petrobras to unitize all six separate fields into one field plus it kicked in a special participation tax, as the discovered resource is so large. In addition, Petrobras plans to deploy two new FPSOs to revitalize the Marlim Field production and its pre-salt component, and another FPSO is allocated for the pre-salt resource at the Albacora Field.
Figure 4: Zoomed-in view of the Campos Basin where Petrobras has plans to deploy three FPSOs.
Bid Rounds and Future Activity
The most recent bid round, APN Round 15, concluded earlier this year with 47 blocks offered in offshore Brazil and 22 blocks awarded. All nine blocks covering 6,100 sq km offered in the Campos Basin were awarded (Figure 5). Participants of the Bid Round included: ExxonMobil, Shell, Petrobras, BP, Repsol and Qatar Petroleum. Partnerships between the participants were the key to this bid round to enable companies to put up the impressive bonuses and premiums. Block C-M-709 was awarded to Petrobras (operator 30%), Equinor (30%) and ExxonMobil (40%) with a bid of R$1.5 billion. Block C-M-657 was awarded to the same consortium with a signature bonus of R$2.128 billion. The highest bid in the round went to Block C-M-789. This block was won by ExxonMobil (operator 40%), Petrobras (30%) and Qatar Petroleum (30%), bidding a signature bonus of R$2.8248 billion and easily besting a partnership bid from Shell and Chevron.
Figure 5: Map highlighting the nine awarded blocks in the Campos APN Round 15 offering.
With the conclusion of the last sale, what is the future for the Campos? There are multiple upcoming licensing rounds in June and September, plus the permanent cycle offer in the basin as well (that will not include the pre-salt – Figure 6). Also, with the improvement of technology to image through the 1-2 km salt layer in the basin, TGS was approved in March 2018 to shoot a 9500 sq km 3D seismic survey over the offered blocks in APN Round 16 in 2019.
Figure 6: Map showing the current operator blocks, planned wells, current and future bid rounds in the Campos Basin.
In conclusion, with the upcoming licensing rounds offering blocks in both the Campos and Santos basins, the Campos Basin might be a better value for a few reasons:
- More infrastructure in place in the Campos versus the Santos
- Both basins have pre-salt prospects, but the Campos has post-salt reserves that are easier and cheaper to drill
- Possibility of more favorable concession regime in the Campos Basin
- Giant fields maturing or declining but very little done for secondary recovery on most of them
Based on some of the above-mentioned factors, the Campos Basin has commanded high prices on the recent rounds, meaning you need to come ready with deep pockets.
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).
Egyptian EGPC 2018 International Bid Round blocks
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.
Norwegian APA 2018 Bid Round blocks
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%.
Australian 2018 Australia Offshore Petroleum Acreage Release blocks
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.
Ecuador’s Ronda Intracampos 2018 blocks
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.
2018 Dominican Republic Licensing Round blocks