San Leon Energy Dividends - SLE

San Leon Energy Dividends - SLE

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Stock Name Stock Symbol Market Stock Type
San Leon Energy Plc SLE London Ordinary Share
  Price Change Price Change % Stock Price Last Trade
0.00 0.0% 40.00 01:00:00
Open Price Low Price High Price Close Price Previous Close
40.00 40.00
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Industry Sector
OIL & GAS PRODUCERS

San Leon Energy SLE Dividends History

Announcement Date Type Currency Dividend Amount Period Start Period End Ex Date Record Date Payment Date Total Dividend Amount
27/04/2020SpecialGBX631/12/201831/12/201907/05/202011/05/202029/05/20200

Top Dividend Posts

DateSubject
23/9/2021
15:50
hpcg: Yep, pencils sharpening to get a more than generous slice of Mid-Western. SLE can cut off negotiations at any time and trade instantly.
21/9/2021
09:47
1kempton: I'm sure sle management know all this and have it in hand
06/9/2021
07:49
kaos3: on the first glance there are problems - but I see it as an opp. for SLE our partner can not afford the hoped for needed consolidation. so SLE let it lapse - to strengthen its negotiation power - reducing own exposure risks and gain more out of it in a new variant hopefully - that is negotiated
23/7/2021
00:49
hpcg: alaric - in a merger neither side gains value, at least until synergies and cost cutting kick in. By definition when two or more parties pool they have agreed what they consider to be a fair share, so the total EV should go up, but our proportional ownership decline. If Midwestern is under some element of financial duress SLE can negotiate harder. Ultimately the market will judge whether the combination is worth more on the SLE share price.
16/7/2021
19:15
hpcg: With the cross holding I would somewhat expect the net value add to SLE and Midwestern shareholders to be nil. What they will be arguing over how to get to nil. SLE can walk away, so should have the upper hand. The combination should be more valuable to outside holders though.
15/7/2021
09:58
1kempton: Sle total assets are 158 mill.. MLPL's most recent unaudited accounts for the year to 31 December 2020 state that the company made a loss before tax of approximately US$93.8 million and showed total assets of US$408.5 million https://uk.advfn.com/stock-market/london/san-leon-energy-SLE/share-news/San-Leon-Energy-PLC-Proposed-transactions-AIM-su/85435317
24/6/2021
18:47
rimau1: The lawyers must love SLE, our deal structures are never straightforward!! Maybe its Nigeria because SAVE is similar. So, SLE buys out Westerns OML stake in its opco funded by SLE issuing so many shares to Western that Western end up as majority owner of SLE so we effectively reverse into Western? I guess the obvious question that no one can answer is - will the share price rise?
20/4/2021
15:55
1kempton: 15:03 Tue 20 Apr 2021 viewSan Leon Energy PLCSan Leon Energy: OML 18 A Springboard for Greater Growth OML 18 A Springboard for Greater Growth San Leon Energy PLC's (LON:SLE) 2016 acquisition of an interest in OML 18 in Nigeria is starting to generate value for shareholders and provides not only a strong presence in a highly prospective region but also the liquidity with which it can execute a growth strategy optimised in its favour. We have undertaken a sum of the parts (SOP) valuation, which we have “sense checked” against Proactive's valuation estimates for the principal assets. We estimate the fair value to be between US$459 — 743mln (76 — 121p a share). Strong Track Record Developed At the original announcement of the acquisition of an indirect interest in OML 18 there was little doubt over the complexity of the proposed structure or the scale of the task that was required to rejuvenate OML 18's operations. The performance of the transaction since completion, coupled with the stabilisation of OML 18's operations has provided management with significant experience. Consequently, the company has established a strong track record in not only executing the deal as outlined but also in working collaboratively with OML 18's operator. Consequently, we believe that the management team has established a strong track record of delivering value. OML 18 Drilling Programme to be a Catalyst Since the completion of the OML 18 transaction in 2016, San Leon has assisted the operator (Eroton) in updating operations at OML 18; however, it is the execution of the next stage that we see as the significant catalyst in the revaluation of the company. Once the programme is initiated, of which the installation of a floating storage and offloading (FSO) facility is an integral part, we believe that the market value's discount to its underlying asset base will start to unwind, and the share price will start to trend towards the assets' fair value range. OML 18 a Springboard The track record that the company has established, coupled with the cash resources that are increasingly at its disposal, means that the company will be able to aggressively high-grade the opportunities in its portfolio, such as that currently being contemplated with Decklar Petroleum, which also has the potential to add further to the current valuation. That said, in this limited liquidity environment, the most important factor contributing to value creation is the availability of liquidity, which provides the company with the flexibility to negotiate from a stronger position, thereby generating greater value than would otherwise be expected from a nominally identical transaction. In this respect, its investment in OML 18 is a regional springboard, and given the opportunities in Nigeria alone, this factor takes on greater significance. Value Potential We have undertaken a sum of the parts valuation, based on a desktop “per unit multiple” assessment of the enterprise value (EV) per attributable barrel of oil equivalent of production and 1P (proved) or 2P (proved & probable) reserves (EV/2P). We have checked this against our valuation estimates for the 1P reserves base for OML 18. We estimate the fair value to be between US$459 — 743mln (76 — 121p a share). Valuation Summary In valuing San Leon, we have applied an SOP valuation, which we have “sense checked” using our proprietary valuation methodology for the attributable 1P reserves. In conducting our SOP valuation, we have undertaken a review of exploration & production (E&P) companies worldwide, to provide an assessment of what the potential valuation has the potential to achieve. We have based our SOP valuation on the per-unit multiple of current attributable production and potential future attributable production, as inferred by attributable 2P reserves. Our SOP assessment values San Leon at US$743mln (121p), some 219% above the current market value. The contribution to the current SOP from current attributable production alone supports the current price, which once you consider the impact of the imminent commissioning of the standalone export route and the impact this will have on downtime and losses (see more below), provides us with confidence that the risk/reward balance favours investment. Our production growth assumptions can be reasonably deemed to be conservative, and the observed downtime and losses (D&L) that have averaged ~30% (higher more recently) will be reduced significantly by the installation of the proposed FSO facility, which we estimate will be commissioned in the second half of 2021. In conducting our “sense check,” we have estimated the value using our proprietary valuation methodology, focusing on the three significant current, near-term and mid-term assets that we believe overwhelmingly dominate the company's value proposition, namely: 10.58% initial indirect interest in oil mining licence-18 (OML 18), and associated loan note receivables;10% interest in Energy Link Infrastructure (Malta) (ELI) and US$10mln loan note receivable; and4.5% net profit interest (NP) in Barryroe. Note: Oza is not included in this valuation exercise as it has not yet been completed. Using our proprietary valuation methodology of the assets, we value San Leon between US$459 — 743mln (76 — 121p a share), at least 219% above the current price.   Peer Group Market Valuation   Proactive has undertaken a desktop “per unit multiple” assessment of the enterprise value (EV) per barrel of oil equivalent of daily production ($/boepd) and reserves (EV/1P or 2P) to arrive at an implied market value. In understanding the valuation metrics for reserves and resources and production presented in this document, the reader needs to appreciate the difference between “value” and “worth,” which are two distinct and separate concepts. Value is a monetary assessment of the importance or usefulness of something. In an oil & gas context, the valuation of E&P companies reflects not only the value of the cash flow from assets that have assigned reserves or contingent resources but also the “option” value estimated for exploration assets. Worth is the level at which someone or something deserves to be valued or rated, or what someone will pay. A respective asset’s valuation is only one of the contributory elements that investors rely on to assess what a company might be “worth”; this is known as the “market valuation.” The valuation metrics presented in this section are based on the respective company’s market valuation and is derived from its market value after it has been adjusted for certain balance sheet items to give what is known as the enterprise value (EV). We have limited our comparison to those companies that have reported their prospective resources according to the Society of Petroleum Engineers petroleum resources management system guidelines. Applying these metrics allows us to estimate the fair value that accrues to those barrels that may be classified as 2P. Exploration and production companies' portfolios are almost universally comprised of a combination of contributory elements, often making it difficult to say with certainty how much of the valuation contribution is provided by each individual category (flowing barrels, reserves, resources, etc.); however, given the number of companies in the various markets that have operations at various stages of operation individually, it is possible to imply a market value. In the case of San Leon, this is simplified somewhat by the fact that the significant proportion of its value is derived from its Nigerian investment, which has both attributable reserves and attributable production. Our estimate for OML 18's reserves (from which SLE's attributable reserves is derived), is estimated from Proactive's proprietary valuation methodology for OML 18, which consolidates the lifted and sales volumes for both oil and gas at the joint venture group level. In the following table, we summarise the oil and gas production attributable to San Leon's indirect interest in OML 18 (attributable net production), and reserves attributable to San Leon's indirect interest in OML 18 and implied net crude volumes accruing to the 4.5% net profit interest (NPI) at Barryroe (attributable net reserves). Our proprietary valuation methodology does not include any assessment of attributable net contingent resources at OML 18, or attributable net prospective resources associated with either OML 18 or the wider Barryroe licence. In making this assessment, we have applied the peer average multiple to San Leon's (SLE's) attributable net production (~3.4m boepd or barrels of oil equivalent per day) and attributable net reserves (121.4mln boe). We have found that the company trades below the market average, indicating that the company is undervalued if we apply the sum of the parts valuation to the company's attributable net production and attributable net reserves. We believe that fair value is US$743mln (121p/share), some 203% above the current share price; we summarise the SOP valuation in the following table. Table 1 - SOP Valuation Summary Source: FactSet & Proactive data Per Daily Flowing Barrel Our review of global E&P company valuations provides a useful guide as to the market worth of production. We have averaged the data for those companies with production by the key international exchanges, and by predominant produced fluid, whether liquids or gas; this data is summarised in the following chart and table. Given that ~79% of production is liquids, the weighted per unit of production is US$31,154/boepd. In comparison to its peers, the company is currently trading below the average, which given the outlook for the growth in production, is disproportionate. Chart 1 - Peer Valuation of Production Source: FactSet & Proactive dataTable 2 - Per Daily Barrel Valuation Source: FactSet & Proactive data Reserves Basis Valuation The company's net attributable reserves are located in OML 18 and Barryroe, and are derived from our proprietary valuation methodology's estimate for the gross volumes attributable to the respective licences (OML 18 and Barryroe). The proprietary valuation methodology for the assets consolidates the estimated gross lifted and sales volumes for both oil and gas, which is based on our understanding of the current and future development plans for the assets, as well as the prevailing hydrocarbon price. On the London Stock Exchange, 2P reserves trade at US$7.70/2P boe for liquids-rich reserves bases, and US$3.01/2P barrels of oil equivalent (boe) for gas-rich reserve bases; the reserves applied to the valuation and the underlying data is summarised in the following table. Table 3 - San Leon Attributable Net Reserves Source: Company & Proactive dataTable 4 - Per 2P Barrel Valuation Source: FactSet & Proactive data We have assessed the weighted contribution of each element of the company's portfolio, applying a US$5.23/2P boe to SLE's portfolio; liquids account for 47% of SLE's portfolio. This implies that the value accruing to the attributable net reserves contributes US$635mln to SLE's overall valuation. As we can see in the following chart, this is significantly below its peer market valuation. Chart 2 - Peer Valuation of Reserves Source: FactSet & Proactive data Sense Check — Proprietary Valuation Methodology Summary We have focused on the three significant current, near-term and mid-term assets that we believe overwhelmingly dominate the company's value proposition, namely the: 10.58% initial indirect interest in oil mining licence-18 (OML 18), and associated loan note receivables;10% interest in Energy Link Infrastructure (Malta) (ELI) and US$10mln loan note receivable; and4.5% net profit interest in Barryroe. As our proprietary valuation methodology indicates, cash generation will remain a key feature for the company. In our current assessment using our proprietary valuation methodology, there are two key uncertainties, namely the: The extent to which any cash resources are available and distributed to San Leon; andTiming of the commencement of the economic benefits accruing to San Leon's 4.5% NPI in Barryroe. Furthermore, our estimates specifically exclude any impact of any projects in SLE's current portfolio that are pending investment completion. We provide more detail on the assets in the following text. Our proprietary valuation methodology for San Leon's OML 18, ELI and Barryroe investments/assets is illustrated in the following table. Table 5 - Proprietary Valuation Methodology Summary Source: Company, FactSet & Proactive data OML 18 San Leon's more active role in the management of OML 18 allows us to draw more conclusions from the future development programme that the company, along with the joint venture partners in OML 18 (the JV group), we believe is being planned. The JV group has provided indications of expected operational timings, via press comments from Eroton, which we have used to form the basis of our outlook for near, medium and longer term activity on OML 18. The JV group has indicated that its principal objective is to refocus on increasing liquid production to 100mln barrels per day (bpd) through the application of work-overs, infill drilling and new production wells, similar to that outlined as part of the 2016 circular. While the hydrocarbon accumulations cover a significant area, these do not pose an issue operationally. While, the combination of mangrove and river setting (see the Asset Base section for more details) provide their own particular hurdles, which need to be overcome, given the JV group's experience in managing drilling operations to date, we would expect the turnaround time between successive wells to be relatively short, despite the terrain. Our proprietary valuation methodology estimates that production will peak at 104mln bpd in 2025 (gross), while gas production will involve two stages of development. The first stage will be largely complete by 2027, where production reaches ~403mln cubic feet per day (gross), before a second stage of steady increases in production out to 2035 when our proprietary valuation methodology suggests that production will reach ~445mln cubic feet per day (gross). Our proprietary valuation methodology also factors in the impact that the commissioning of the new oil export pipeline and FSO facility, which directly affects sales volumes. We estimate that the export facility will be online during the second half of 2021, whereupon we estimate average D&L to fall from the average annual losses level of ~30% to a more normal 10% of gross production; (see the Asset Base section for more details). Proactive's production estimate for OML 18 is provided in Asset Base section later in this document. Furthermore, as will be seen in more detail later in this document, gas is a significant proportion of OML 18's revenue stream, which is secured on a long-term supply agreement to the nearby Notore chemicals facility. While we discuss hydrocarbon pricing later in this section, given that the Nigerian gas market lacks maturity, pricing can lack transparency and uniformity. In this respect, we have assumed that the gas price varies between US$1.80 - 2.50/mcf (millions of cubic feet), averaging US$2.10/mcf over the life of the field. While we recognise that this is below the average achieved for liquefied natural gas (LNG) sales in Nigeria, we feel it is an appropriate basis to conduct this valuation; however, we are cognisant that should the JV group sell a higher proportion of it produced gas to LNG offtake than we are currently estimating, it will have a positive impact on our valuation estimate. Our value estimate based on our proprietary valuation methodology assumes that, in time, future periods will have sufficient cash reserves in the operating entity to remit dividends to SLE. On this basis, the estimated value using our proprietary valuation methodology, attributable to San Leon's indirect interest, discounted at 10% (net present value or NPV(10%), is US$327mln (54p a share). Floating Storage and Offloading Facility As we have highlighted previously and will discuss in greater detail subsequently, OML 18 suffers from a high degree of D&L, which have historically ranged between 25 — 32%, significantly higher than when SLE acquired its interest in OML 18. Given the extent of these losses, it is unsurprising that the company has sought ways in which to minimise its impact. In this context, the planned construction of a dedicated export pipeline and floating storage and offloading facility will significantly increase OML 18's profitability. In August 2020, the company announced that it was intending to invest both equity and debt in Energy Link Infrastructure (Malta), the company that owns the proposed FSO facility. In that announcement, SLE informed the market that its equity investment would provide it with 10% of ELI's equity. While we will discuss the FSO facility in more detail later in the document, we have assumed for the sake of our proprietary valuation methodology that the FSO facility will only handle crude from OML 18, although we recognise that this facility could also be used by neighbouring third-party production as is the Bonny export terminal currently, which would further boost ELI's value to SLE. In arriving at our cash flow estimate we have also made the following assumptions: That the cash flow is remitted from the operating unit in-country (Nigeria) to the Maltese Topco by dividends;ELI will charge the JV group commercial transportation rates (~$4/bbl);Costs will account for US$1.5mm/monthDepreciation will account for 30% of revenues until recovery of US$150mln of capital expenditure;Corporate tax is levied at 30%;Withholding taxes of 10% are levied on dividends from Nigeria; andCash remitted from the Maltese Topco to the equity owners is achieved through dividends, without attracting any further taxes. Using our proprietary methodology, net to San Leon, discounted at 10% (NPV(10%)) the valuation is US$43.7mln (7p). This excludes any revenues generated from granting from third-party access. Barryroe Prior to its entry into Nigeria, San Leon restructured its interest in Barryroe, such that the company's net interest in the asset declined to a 4.5% NPI and SLE no longer bore any responsibility for funding Barryroe's development. To date, Barryroe has a long history of extensive appraisal, with six appraisal wells, each encountering hydrocarbons. Despite these successes, however, a combination of the decline in oil price and COVID-19 delays has historically resulted in significant uncertainty as to when, or how, the field will be developed. More recently, Providence Resources PLC (LON: PVR) announced that it had agreed to farm out a 50% working interest in Barryroe to SpotOn Energy, a Norwegian based resources company, who along with a consortium of international service providers would fund, develop and produce Barryroe. Under the terms of the deal, SpotOn has agreed to fund 100% of a combination early development programme (EDP) and appraisal programme, as well as the full field development. Drilling is expected to begin in late 2022, pending the closing of the transaction. Given the fact that the company's interest in Barryroe is strictly an NPI, and therefore has very little operational input into the asset's running programme, we have estimated value accruing to SLE from Barryroe using our proprietary valuation methodology, based on information from the previous information releases and the latest update. While Barryroe has oil and gas resources, currently we are assuming that any gas produced will be consumed in the operations, resulting in zero sales of gas; however, should this prove to not be the case, we would anticipate that the sale price achieved by Barryroe gas would be in line with that achieved in the North Sea, which is generally based on NBP (natural balancing point) pricing. Under this scenario, we would expect our current valuation for San Leon's 4.5% NPI to increase. Our proprietary valuation methodology assumes a final investment decision in 2023 and commissioning in 2028. We estimate that Barryroe will break even at some time in 2029, which means that San Leon should start to receive the economic benefits of its NPI from 2030 onwards. While there remains significant uncertainty surrounding not only the amount of investment required but its timing, SLE may also elect to sell the NPI ahead of first oil; our valuation assumes that it is held until decommissioning of the asset. The unrisked valuation using our proprietary valuation methodology, net to San Leon, discounted at 10% (NPV(10%)) is US$85.9mln (14p). Hydrocarbon Prices Used in the Proprietary Valuation Methodology Oil prices in Europe and West Africa are generally priced off Brent. Given the relatively light nature of the crude produced at OML 18, we have assumed that there is minimal pricing discount applied in respect of the crude quality. The crude from Barryroe, however, has been suggested to have a relatively high wax content, certainly higher than Brent. While a high wax content can, in certain circumstances, command a higher price than similarly graded crude of a lower wax content, this is only generally achieved where either significant demand for the wax fraction exists, such as in certain speciality chemicals, or the respective refining complexity demands a higher wax content feedstock. In this context, we believe it to be prudent to assume that Barryroe crude will trade at a discount to Brent, which we initially estimated to be ~US$5/bbl. Consequently, our proprietary valuation methodology has used the Brent forward curve as at January 31, 2021 (see below), maintaining the price flat beyond July 2027. For the reasons that we have already provided previously, we have not undertaken any detailed analysis on gas prices. Chart 3 - Brent Forward$/bblSource: FactSet & Proactive data Asset Base San Leon's dominant value drivers are OML 18, ELI and Barryroe with its investment in OML 18 dominating the near and medium term outlook. Consequently, Nigeria is the most significant in terms of cash flow and future activity. San Leon is currently high-grading its portfolio, which is likely to see it differ materially from its current configuration. Consequently, we will be focusing on OML 18, ELI and Barryroe in this document. Nevertheless, for completeness, the current portfolio provides exposure to six countries, namely (i) Albania; (ii) Ireland; (iii) the Netherlands; (iv) Nigeria; (v) Poland; and (vi) Spain; the countries in which San Leon operates illustrated in the following map. Figure 1 - Areas in Which San Leon Operates Source: ESRI & Proactive data Albania The company’s Albanian exploration licence area is located offshore along the Apulian shelf edge oil trend. The licence contains a discovery (Duresi) that has both an oil accumulation and a biogenic gas accumulation (A4-1X well). We will not be looking at these assets any further in this document. Ireland Ireland is San Leon's second most important source of future cash flow and a contributor to our discounted cash flow valuation; however, the company has no direct interest in any licences, but a 4.5% net profit interest in Providence Resources’ Barryroe licence. The NPI provides the interest while not paying any future appraisal or development costs on the project. The Netherlands SLE is the ultimate beneficiary of a 1% royalty interest in relation to the Block Q13A (the Amstel Oil Field), offshore Netherlands, pursuant to an overriding royalty agreement entered into with Encore Oil as part of a sale and purchase agreement signed in 2007. Taqa subsequently purchased the interest from Encore Oil. Production from the Amstel Field started in 2014 but no royalties have yet been received as Taqa has stated they are not liable for the royalty and it is not due and payable to San Leon. The matter is currently the subject of legal proceedings. The royalty would be payable from the date revenues exceeded capital and operating expenditure. We will not be looking at these assets any further in this document. Nigeria OML 18 lies within the Eastern Swamp region of the southern part of the Niger Delta. A total of nine fields have been discovered to date with an aggregate gross volume of ~1,100mln boe of 2P reserves. Given the importance of the company's Nigerian assets and the role that the company plays in OML 18's management, this will be one of the key items on which we focus in this publication. Poland San Leon no longer holds any direct working interests in licences within Poland. The company’s is exiting its Polish interests. We will not be looking at these assets any further in this document. Spain While the company still has licence interests in Spain, it is in the process of exiting the country. We will not be looking at these assets any further in this document. OML 18 Outline San Leon’s sole exposure to the Nigerian E&P segment currently is via its indirect investment in OML 18, which is located in Rivers State in the Niger Delta, 16km south of Port Harcourt and adjacent to the Bonny Crude & LNG Export Terminals; see following map.    Figure 2 - Location of OML 18 Source: Company, ESRI & Proactive data OML 18 contains 576mln barrels (bbl) of liquids and 3.2 trillion cubic feet (tcf) of gas across nine discoveries; these, along with the associated volumes are as at 2016's Petrovision competent person's report, summarised in the following table. While ordinarily the presence of gas is considered of marginal interest, the proximity of Bonny LNG and the Notore fertiliser facility means that the gas reserves in OML 18 have a greater commercial value than they would otherwise have done. Table 6 - 2016 CPR Accumulation Reserves & Resources Volumes Source: Company & Proactive data The Cawthorne production facility (see following picture) is located on the banks of the Cawthorne Channel, which drains into the Atlantic. All accumulations within OML 18 are produced into the Cawthorne production facility, where the crude is currently stabilised prior to export to the Bonny export facility. Figure 3 - Cawthorne Central Processing Facility Source: Company & Proactive data Future Drilling Programme & Production Operating in the Niger Delta can be difficult, not least due to the challenging terrain (see the following picture). Shell, the previous licensee of OML 18, had a poor relationship with the indigenous community, which has been improved immeasurably by the current operator, Eroton. This has meant that until recently, executing a drilling programme was not simple to carry out; however, given that these hostilities have been largely abated, due to a good relationship between the operator (Eroton) and the communities, and a wider peace agreement with the Nigerian government, we are confident that the most significant hurdles will no longer be those related to the operating environment, but operational, allowing the JV group to fully control the next phase of the development programme. Figure 4 - OML 18 Jungle Environment Source: Company & Proactive data We believe the coming four-year period will see the JV group refocus on executing its drilling programme, substantially increasing the number of producing wells, and maximising recoverability through the selective application of either rededication of historic production wells (as injection wells), or the drilling of new injection wells; our outlook for the well count is provided below. We estimate that oil production will peak at 104mln bpd (gross) in 2025; however, our estimate for gas production involves two stages of development, the first stage being largely complete by 2027, where daily production reaches ~403mln cfpd (gross), before the second stage of development increases production further, out to 2035 when daily production reaches ~445mln cfpd (gross). Furthermore, our outlook for production also includes the impact that the export facility will have on sales volumes. We estimate that the export facility will be online during the second half of 2021, whereupon we estimate average losses will fall from the current average annual D&L level of ~27.5% to a more normal 10% of gross production. This increase in production has a corresponding impact on cash flows, which in our analysis also benefits from a significant reduction in losses due to the commissioning of the FSO facility; we discuss this in more detail in the following section. Floating Storage and Offloading Facility The Bonny export line is a third-party-owned pipeline, and a key part of the regional production infrastructure, with a further eight production facilities also using the pipeline. While this would not ordinarily be an issue, there are significant discrepancies between what each participant alleges it injects into the Bonny export line, and what is measured at Bonny export facility. This difference is then spread proportionately over all the pipelines participants, recorded as “losses". In its most recent interim results, the company outlined that downtime and losses reached in excess of 30% of wellhead production, which if you assume a US$40/bbl oil price equates to about US$12mln a day in lost revenue across all OML 18's partners. While there is no doubt that there has historically been theft directly from the crude transfer line, known as bunkering, we think the practice has declined significantly since peaceful relations between the government and the local militia groups have been restored. Given the extent of these losses, it is unsurprising that the company has sought ways in which to minimise its impact. In this respect, the planned construction of a dedicated export pipeline and FSO facility will significantly increase OML 18's profitability. As part of the FSO project, the export line will be laid along the length of the Cawthorne Channel from the Cawthorne processing facility to the floating storage and offloading facility, which is expected to be moored 18 km offshore (see following map). Trenching the export pipeline to the floating storage and offloading facility along the flow line of the river significantly reduces the potential for bunkering from this export line, thereby protecting revenue and the environment. Figure 5 - Proposed FSO Location Source: Company, ESRI & Proactive data We expect there to be effectively zero net effect on export costs in switching to the FSO facility, which we are currently estimating at about US$4/bbl, which will be offset by the cessation of payments to the existing Bonny export line owners; SLE has taken a 10% interest in the company running the FSO export facility. Niger Delta Basin - General Geology The Niger Delta Basin (NDB) is a prolific hydrocarbon province, and is one of a number of West African basins collectively known as the "West African Margin Basins," which were created by the growth of the mid-Atlantic Ridge; the location of the NDB is illustrated below.    Figure 6 - Location of the Niger Delta Basin Source: USGS, ESRI & Proactive data The growth of the mid-Atlantic Ridge is the key tectonic event that precipitated the separation of the African and American plates and contemporaneously formed the mirror basins on the western side of the Atlantic Ocean currently being developed in the Santos Basin, which is located offshore Brazil. Accumulations Oil and gas accumulations are prevalent throughout the Agbada formation in the NDB; however, several oil-and-gas-field trends form an oil-rich belt that has the largest fields and lowest gas/oil ratios. The belt extends from the northwest offshore area to the southeast offshore and along a number of north-south trends near Port Harcourt. The trend corresponds to the transition between continental and oceanic crust and is within the axis of maximum sedimentary thickness. Studies using sequence stratigraphy developed a hydrocarbon-habitat model for the NDB. The model was constructed for the central portion of the delta, including some of the oil-rich belt, and relates the deposition of the Akata formation (assumed low-stand source rock) and the sand-shale units in the Agbada formation (the reservoirs and seals) to sea level. The Akata formation shale, which was deposited in deep water during low-stands, is overlain by the Agbada sequences. The Agbada formation in the central portion of the delta fits a shallow-ramp model with mainly high-stand (hydrocarbon-bearing sandstone) and transgressive (sealing shale) system tracts. Faulting in the Agbada formation provided pathways for petroleum migration and formed structural traps that, together with stratigraphic traps, accumulated hydrocarbons. The shale in the transgressive system tract provided an excellent seal above the sand as well as enhancing clay smearing within fault zones. Source Several reports have debated the source rock for oil and gas within the Niger Delta. Source rocks include the interbedded marine shale in the Agbada formation, the marine Akata shale, and possibly Cretaceous shale. Some intervals in the Agbada formation contain organic carbon contents sufficient to be considered good source rocks. The source-rock intervals rarely reach thicknesses sufficient to produce a world-class oil province and are immature in parts of the delta. The Akata shale is present in large volumes beneath the Agbada formation and is at least volumetrically sufficient to generate enough oil for a world-class oil province such as the Niger Delta. Total organic carbon (TOC) analyses of Agbada formation siltstones and shales have been shown to be essentially the same, averaging 1.4 – 1.6% wt/wt. The TOC content, however, seems to vary with the age of the strata — an average of 2.2% wt/wt in the late Eocene compared to 0.9% wt/wt in Pliocene strata. Eocene TOC averages have been reported to compare well with those observed in Agbada-Akata shales; TOC values ranging from 0.4 – 14.4% wt/wt in both the onshore and offshore paralic sediments; the same sediments in the western reaches of the delta have reported lower overall TOC content at ~5.2% wt/wt. It was concluded that there is believed to be no rich source rocks in the delta and that the poor quality of the source rock has been partly offset by its great volume and excellent migration pathways. The oil potential is further increased by permeable interbedded sandstone and rapid hydrocarbon generation and over-pressuring resulting from high sedimentation rates. Some authors have proposed that oil-bearing Cretaceous rocks may be beneath and east of the present Niger Delta; this has not been tested due to the depth, which makes it prohibitively expensive and commercially unlikely. Migration of oil from the Cretaceous into reservoirs in the Agbada formation would require an intricate fault or fracture network, due to the excessive thickness of the Akata shale series, which is often in excess of 6,000 metres (m). No data exists to support this petroleum system, network, and an alternative system comprised of marine kerogen, which is supported by observed samples along the Nigerian coastline and offshore and oil seeps from Nigerian tar sands within the Dahomey Embayment (Figure 60), source-rock outcrops along the eastern margin of the delta, and geochemical data from wells. These source rocks could be contributors to hydrocarbon accumulations in the deep-water areas of the Niger Delta. In the northwestern part of the Niger Delta, the oil window lies in the upper Akata formation and the lower Agbada formation. To the southeast, the oil window is stratigraphically lower, as much as 4,000 ft below the upper Akata–lower Agbada strata. Reservoirs Oil and gas in the Agbada reservoirs is produced from sandstone and unconsolidated sand primarily found within the Agbada formation. Known reservoir rocks are Eocene to Pliocene in age, are commonly stacked, and range in thickness from less than 15m to greater than 45m, although the thicker reservoirs are likely to result from amalgamated bodies of stacked channels. Based on reservoir geometry and quality, the most important reservoir types have been described as point bars of distributary channels and coastal barrier bars intermittently cut by sand-filled channels. In some studies, porosities of up to 40% and permeability of up to 2 Darcies have been observed in the primary Niger Delta reservoirs as Miocene sandstones, with thickness of ~100m. The variation in reservoir thickness is strongly controlled by growth faults, with the sandstone thickening against the fault wall within the down-thrown block, although in these circumstances, porosity typically decreases with increasing depth. Traps and Seals Traps in Niger Delta oil and gas fields are mostly structural, although stratigraphic traps are not uncommon. Structural traps developed during synsedimentary deformation of the Agbada paralic sequences. Structural complexity increases from north to south within the depobelts in response to the increasing instability of the less-compacted, over-pressured shale. A variety of structural-trapping elements, including those associated with simple rollover structures, clay-filled channels, structures with multiple growth faults, structures with antithetic faults, and collapsed-crest structures have been described in the NDB; however, in the deep-water part of the delta, the primary reservoirs found in Akata reservoirs are mostly stratigraphic and include turbidite sands, low-stand sand bodies, and clastic fans, and structural traps are less common. The major reservoir seal rocks in the Niger Delta are interbedded shale units within the Agbada and Akata formations. The shale provides three types of seals in the Agbada: (i) clay smears along faults; (ii) interbedded strata against which reservoir sands are juxtaposed due to faulting; and (iii) vertical seals. On the flanks of the delta, major erosional events of early to middle Miocene age formed canyons that are now clay-filled. These clays form the top reservoir seals for some of the more productive offshore fields. Akata shale is the primary seal in
05/3/2021
18:47
1kempton: A0469514..yes Shell will have to reimburse eroton these barrels as they will the other companies involved by the looks of the article, regarding sle receiving its share, well put it this way, it opens the door for eroton to issue its shareholders dividends which sle are holders and sle has stated returning 50/60% of capital to shareholders.. And when you think sle are owed $80/100m from loan notes which is due to sle by year end, plus contributions from oza and the fso, the dividend or dividends should be very rewarding to shareholders.. And no imo this is defo not in the share price at the mo..
28/11/2020
11:19
1kempton: Barryroe now worth zero to sle at present, but with a 4.5% interest in production profits on the whole enlarged licence structure, this is going to worth 10s of millions a to sle.. and with no outlay... gas to be produced from as 18 months by what Alan Linn states in a proactive pres, says this is going full steam ahead. Then their is the oza field, which holds 20mboe plus!!!.. large hydrocarbon structures found but never tested by shell, this imo could be more than double the amount of oil to be recovered as mentioned in the fox Davies pdf regarding decklar, sle will be paid first by the recent rns's and once paid will hold 30% of decklar and its production... Then we have oml18, where we hold a 10.58% interest in erotons production, who have already paid sle back 190m through the loan notes scheme so we have that now for free, owed through interest is around 110m which will be repaid by end of next year of which sle have stated half will be returned to shareholders in dividends... plus we have a 10% share in the new fso facility which from day one will increase production from 10kbpd to 50kbpd plus. There are other companies wishing to use this line who like eroton will have to pay in advance for every barrel that flows through the line, and sle receive 10% on every barrel.. With this increase in production eroton who sle have 10.58% will be able to pay dividends out to sle who in turn have stated to return half to us shareholders All in all with cash in the bank and sle already paying a handsome 30% yield in the form of a 6p dividend earlier this year, things are looking really rosy for sle and its shareholders. . More deals and dividends next year and all years as stated by our ceo..
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