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
On 8 May 2018, Noble Energy signed a Heads of Agreement (HoA) with the Equatoguinean Government, to supply gas to the Punta Europa LNG plant and the Alba Plant LPG facility, both located on Bioko Island. This is the first part of the Government’s gas MegaHub project, announced in May 2018 – which can be viewed as part of its ambition to become a major regional player in oil & LNG in Africa and beyond
Discussions and negotiations surrounding further gas development projects in Equatorial Guinea have been ongoing for a number of years. At present the country produces some 3.4 MMt/a LNG from the Punta Europa plant (also known as EGLNG), which came onstream in 2007, operated by Marathon Oil (60%), with state-owned Sonagas (25%), Mitsui (8.5%) and Marubeni (6.5%). Gas is supplied to the plant via pipeline from Marathon’s Alba gas-condensate field, located some 30 km NW of Bioko Island. According to third party sources, 65 cargoes were shipped from the plant in 2017 to markets including Argentina, China, India, Japan, Jordan, and South Korea. For many years the Government has been eager to see the construction of a second LNG train here, believing that gas reserves from Alba could support a new development. However, there have been repeated questions as to whether this is commercially feasible as reserves at Alba are dwindling and production is expected to fall dramatically after 2019/2020.
Figure 1: Location of Punta Europa LNG plant and Alba & Alen fields
The HoA signed with Noble Energy provides a framework for the development of gas from the offshore Alen gas-condensate field, including the construction of a 65km gas pipeline to the facilities at Punta Europa. Gas from the field is currently reinjected. If the project is sanctioned, Noble will monetise an additional 600 Bcfg and the life of the 3.4 MMt/a Punta Europa LNG facility will be extended; however these additional reserves are not expected to lead to an increase in the volumes of LNG produced at present.
The Alen Field is located on Block O/I, where Noble has made a number of discoveries and produces oil and condensate from the Alen and Aseng fields. Other fields on the blocks include the Diega and Carla South oil & gas fields. Noble had submitted a Plan of Development for these fields in 2015, however the Government was unwilling to approve this. Instead, it signed an agreement with OneLNG (a consortium of Schlumberger and Golar LNG) in May 2017 in order to investigate the technical and commercial feasibility of an FLNG project on these blocks, aiming to reach an agreement at some point in 2018. Whilst it is currently unclear what the status of this agreement is it seems more plausible that gas from these fields will now be developed via the onshore plant, in a future phase of development for the MegaHub project, rather than through any new FLNG development, which would likely be far less cost effective then utilizing in-place facilities.
It is also possible that gas from the YoYo/Yolanda field (which straddles the maritime border between Equatorial Guinea and Cameroon, operated by Noble Energy on both sides) may also be eventually processed at Punta Europa. In mid-2017, Noble Energy signed an agreement with both governments to develop the fields jointly. Resources for Yo Yo are estimated at 47 Bcfg and 18 MMbc, whilst resources for Yolanda have been estimated at 27 Bcfg. However, Cameroon has also brought an FLNG plant onstream; the Golar “Hilli Episeyo” vessel, only the second FLNG vessel in operation globally. It commenced FLNG production from the Perenco-operated Kribi gas fields in March 2018. Therefore, the Cameroonian Government may be keen to see gas from Yo Yo/Yolanda developed at Kribi, instead of at Punta Europa. Keppel (Singapore) converted the “Hilli Episeyo” vessel from a 1975 Moss LNG carrier, which had a 125,000 cu m storage capacity. It is the first such FLNG vessel conversion and took three years to complete. The conversion budget was US$ 1.2 billion. The gas resources earmarked to be tapped are around 500 Bcf (but with future upside), with production expected to reach 1.2 MMt/a. Gazprom has signed to take all the LNG product for an 8-year period. Cameroon had also studied the possibility of constructing an onshore 3.5 MMt/a LNG plant at Kribi (to be supplied with gas from the New Age operated Etinde fields), however, Engie (formerly GDF Suez) suspended the plans for the US$ 5 billion project in 2016, due to unfavourable market conditions. Whilst the Etinde fields are just 35km away from Punta Europa, regional politics means it is unlikely that gas from these fields will be developed via the MegaHub project.
Figure 2: Cameroonian fields
The “Hilli Episeyo” vessel was seen as a forerunner to Ophir Energy’s Fortuna FLNG project, to be located on Block R, in the west of Equatorial Guinea’s maritime area and some 100km west of Bioko Island. Ophir currently operates Block R with 80% equity, GEPetrol holds the remaining 20%. However, after a Final Investment Decision is made on Fortuna, the Fortuna Joint Operating Company (JOC) will hold Ophir’s 80%. The JOC is comprised of Ophir (33.8%) and One LNG (66.2%). The parties signed a detailed Umbrella Agreement in April 2017, establishing the full legal and fiscal framework for the project. Following this, midstream contracts were awarded in May 2017 and upstream contracts in October 2017. In late August 2017, the principal commercial terms for a sales and purchase agreement for 50-100% of the offtake from the project were also agreed with Gunvor Group, and Gunvor was nominated the preferred LNG buyer (it was also rumoured to be in discussions with Sonagas regarding the financing of Sonagas’ potential acquisition of 30% of the project). The final stage required for the project before the Final Investment Decision was taken was for project financing, worth some US$ 1.2 billion, to be completed. Ophir was initially expecting to have completed this by end-2017 and was in discussions with Asian lenders, including the Industrial and Commercial Bank of China (ICBC). However, ICBC was keen that the projects planned LNG output was sold exclusively to CNOOC and that engineering, procurement and construction contracts went to Chinese-state companies. Talks are still ongoing with other Asian lenders; Western banks are said to be less keen on the project due to Equatorial Guinea’s opaque political situation.
The Government has now set a December 2018 deadline for Ophir to complete project financing for Fortuna. Ophir was granted a one-year extension to Block R in November 2017, with the licence now expiring in mid-December 2018. Oil Minister Gabriel Obiang Lima has stated that the Government has a clear idea as to which company would be granted the licence if Ophir is unable to continue with the development. It is possible that if Ophir is unable to complete the financing deals required that gas from Fortuna would then be utilized at the planned MegaHub project – possibly providing enough gas for the much-coveted second LNG train.
Figure 3: Potential other sources of gas for LNG MegaHub
The final potential source of gas for future phases of the MegaHub project is from ExxonMobil’s Zafiro Field. The oil field was discovered in 1996 and brought onstream in 2003. It has produced over 1 billion barrels of oil to date (from an estimated ultimate recovery of ~1.2 billion barrels). Gas is currently flared; however, the Government has been keen to halt this. Given the maturity of this field, it seems unlikely that major new investments will be made here unless significant additional reserves are proven.
The Government is currently in discussions with new potential LNG buyers from Punta Europa; its existing 17-year agreement to sell LNG to BG (Shell) will expire in 2020. For various reasons, the BG deal is widely considered to be one of the most lucrative LNG supply deals ever signed, and the Government is keen to ensure it receives a far higher share of profits in future. Talks are progressing with CNOOC, Lukoil, Total, Vitol, Shell and a Lukoil/New Age JV. Supply deals will be offered for 3-5 years.
The Government is also in talks with a number of Africa countries regarding the supply of LNG via the LNG2Africa initiative, which aims to encourage the use of LNG in Africa, using Africa-sourced gas. A summary of the discussions held so far include:
- In early-April 2018, Togo signed a memorandum of understanding (MoU) with Equatorial Guinea to facilitate the trade of LNG between the two countries. Under the agreement, Togo will assess options for the import and regasification of LNG, and its use for power generation. A framework for Togo to import LNG produced in Equatorial Guinea is also provided.
- Burkina Faso also signed a MoU with Equatorial Guinea in September 2017 under which the two governments aim to negotiate an LNG sale and purchase agreement and a terminal use agreement. A technical study will also be commissioned for the construction of LNG regasification and storage facilities, and associated transportation infrastructure in Burkina Faso.
- Equatorial Guinea also signed a framework agreement for the export of LNG to Ghana in August 2017, which is in the market to import some 250-500 MMcfg/d; despite Ghana having indigenous gas production from the Jubilee Field and the Sankofa Field, the country has struggled to supply enough gas to satisfy its restricted demand. Ghana is also supplied with pipeline gas via the West Africa Gas Pipeline, however, supplies through this source are unreliable.
- Discussions have also taken place with Mali, Morocco, South Africa and Guinea, plus Angola where talks have now ended.
All these discussions should, of course, be viewed in light of the “Africa Unite” theme that Equatorial Guinea is pursuing, under the belief that if the oil producing economies of the continent can work together they will hold much greater sway on the global stage. To this effect, a number of E&P co-operation agreements with various countries have also been signed, including with Angola, Mozambique, Uganda and South Sudan. Equatorial Guinea became the 14th member of OPEC in May 2017; declaring its intentions to become a representative voice for smaller Africa producers. It has been pushing for more African countries to join the cartel. Whilst its oil production is declining, global LNG demand is rising, and a well-planned gas and LNG strategy could well result in the Equatorial Guinea’s increasing dominance in the Africa E&P sphere.
On 24 April 2018, Thai Minister of Energy Siri Jirapongpha officially launched the auction of the producing Bongkot and Erawan gas and condensate fields after the National Energy Policy Committee, headed by Prime Minister Prayut Chanocha, had approved the terms of the auction which includes the condition that both fields must produce at a combined rate of least 1.5 Bcfg/d at gas prices not higher than current levels for a 10 year period with a minimum of US$ 4 billion and US$ 2 billion to be invested in the Bongkot and Erawan fields respectively. As of February 2018, the average price of gas per MMBtu from the Bongkot Field was US$ 6.34 (200 Thai Bhat) with gas from Erawan priced at US$ 5.07 (160 Thai Bhat). The DMF’s 2016 1P gas resource estimates for the Bongkot and Erawan fields have been placed at 1.38 Tcf and 0.43 Tcf respectively.
Veerasak Pungrassamee, the director of the DMF, announced that pre-qualification evaluation documents and data rooms for the auction will be available from 30 April-1 May 2018 with the submission deadline to participate in the auction scheduled for 15-16 May 2018. The screening period of the bids is expected to be between September-November 2018 with winning bids expected to be announced in December 2018 and official signing of the contracts for both blocks planned for February 2019. The blocks will be renamed and awarded as G 2/61 for Bongkot and G 1/61 for Erawan. Mr Veerasak added that bids for the auction may potentially be evaluated with a 65% weightage on the proposed gas prices and a 35% weightage on benefits to the state. In 2016, the fields produced at a combined rate of approximately 2.1 Bcfg/d with Bongkot producing 0.86 Bcfg/d and Erawan producing 1.24 Bcfg/d. The Bongkot Field is located within the B15-B17 concessions with the Erawan Field located within the B12 concession. Operator PTT Exploration and Production plc (PTTEP) and partner Total E&P Thailand, a wholly owned subsidiary of Total SA, are potentially planning to jointly bid to continue operating the Bongkot Field after its expiry in 2023. PTTEP had previously increased its rightholding to 66.67% by acquiring former partner Royal Dutch Shell Plc’s 22.22% equity. Total holds the remaining 33.33%. Mr Jirapongpha had indicated that Chevron Corp, the current operator of the Erawan Field, had expressed interest to continue as the operator after the concession expires in 2022. Equity in B12 is split between Chevron (71.25%), Mitsui Oil Exploration Co Ltd (23.75%) and PTTEP (5%) with PTTEP planning to increase its equity stake.
Abu Dhabi based Mubadala Investment Co is also understood to have also expressed interest in joining the auction in a bid to expand its existing business in Thailand. The auction, initially announced on 8 November 2016 with results planned to be announced by September 2017, was postponed to December 2017 with results expected in 2018 due to delays in the approval of the modified Petroleum Act. Subsequently, Thailand’s parliament approved an amendment to the Petroleum Act on 30 April 2017, that came into effect in late June 2017, that gave companies more options for exploration and production operations in Thailand such as negotiating production sharing agreements (PSA) or service contracts instead of the traditional concessions format. Unconfirmed initial decommissioning costs for the facilities within the fields had been estimated at US$ 7 billion.