SEPLAT: Capital Investment, Oil Rally Brighten Earnings Outlook
Seplat Petroleum Development Company gets a better earnings outlook as Shell divests interest as part of the strategy to build a footprint in renewable energy. In a new report by Capital Asset Group, a London-based investment banking firm recognises that the oil exploration and production company investment has increased its earnings profile.
Seplat, a dual-listed blue-chip, upstream and midstream oil and gas business with assets and operations in Nigeria has increased its production and grown its reserves consistently since inception, and now generates over 54k boepd from 499MMboe 2P, Capital Access said in its initiation note.
Amidst the ongoing crude rally, Nigeria’s indigenous company’s oil production is sold internationally while its gas production is sold under a number of domestic gas sales agreements.
“In fact, Seplat’s gas powers more than 20% of Nigeria’s energy production, and this market offers huge potential growth as the Nigerian government pushes increased grid penetration alongside the increasing use of gas in the energy mix in order to meet its social and environmental improvement targets”, Capital Access analysts concluded.
The investment firm also said in the report obtained by MarketForces Africa that Seplat stands to benefit materially from the dual tailwind provided by both Nigeria’s energy policy and the backdrop of a young population in one of the fastest industrialising and growing economies in Africa.
“Despite the global situation in 2020, Seplat’s dividend was maintained (it currently yields 7.6%), $100 million of debt paid down, and the cash position remains strong”, Capital Asset analysts Oliver Juggings stated.
With consensus risked net asset value (NAV) of 158 pence per share investment analysts at Capital Asset expressed the view that there is significant upside potential here on current assets alone.
“Its successful history of assets and corporate acquisitions combines with a fertile environment for these to continue, suggesting material growth potential ahead.
“We believe the market is underpricing two imminent and highly certain catalysts, so we expect the shares to re-rate significantly once the Amukpe-Escravos oil pipeline starts flowing in early 2H21 and the ANOH gas processing plant comes online in the first half of 2022. Neither appears to be priced in”, the firm noted.
Business Operations
Seplat was formed in 2010 to pursue upstream oil & gas production in Nigeria – with a focus on opportunities arising from divestments being undertaken by major independent oil producers in the region.
Over the next decade, it took operating and non-operating interests in six blocks, before acquiring Eland Oil & Gas in 2019 to add a further two blocks (OML-40 and Ubima). As a result, Seplat now has a direct interest in 7 blocks, 4 of which it operates (OML-4, 38, 41, and 53), and a financial interest in one further block, OML-55, according to Capital Access’ analyst.
It also operates two gas processing plants, Oben and Sapele, with a third in progress via its 50% stake in an Incorporated Joint Venture with the Nigerian Gas Processing and Transmission Company, called the ANOH Gas Processing Company. This will build and operate a 300 million standard cubic feet per day gas processing plant in Imo State (on block OML-53, see map below) and a two-train condensate plant with additional facilities to support LPG recovery.
Its blocks are reasonably well spread geographically, and three are dominant in terms of scale: OML-53, OML-4, and OML-41 represent 34%, 28%, and 20% of 2P reserves respectively. Seplat currently produces 51.2k boepd from its 499 MMboe of (2P) reserves.
How Seplat Survive Two Major Oil Crises 7 Years
There have been two oil price crises since Seplat built its portfolio – the first in the 2014-2016 price collapse and the second in the 2020 COVID crisis. The 2016 crisis, driven largely by a supply glut and the seemingly (at the time) ever-lower wellhead break-even price for US Shale Gas, hit Nigeria particularly hard.
Gas
In 2020 Seplat’s earnings before interest tax, depreciation and amortisation (EBITDA) margin in gas was 79% and oil 38% – though in 9M20 oil was loss-making due to price volatility. To give an idea of more normal margins in these businesses, in 2019 the margins were 93% and 54% respectively (although gas revenues included a $66.9m gas processing fee not repeated in 2020).
Secondly, Nigeria’s push to use gas to replace other energy sources is a material and significant tailwind as discussed below. Another advantage is a higher drop-through than oil due to lower royalties, taxes, and costs. Gas is also largely flared off in Nigeria as a by-product, so capturing it for more efficient, controlled burning to produce energy both improves margins and provides a strong environmental benefit.
Finally, gas revenues are independent of global oil prices and benefit from long term (>10 year) fixed price offtake contracts. The first 130Mscfd (for both Oben and Sapele on a Joint venture basis) of production is taken by the government at a relatively low fixed price ($2.50/mcf) under the Domestic Supply Obligation) and the remainder can be sold at market prices of $3.00/mcf and above.
During 2020 Seplat drilled two new gas wells (both of which are now complete), with Oben-50 producing in Q1 and Oben-51 expected to begin production this month.
Combined, these two wells are expected to produce 75 MMscfd. Seplat has positioned itself well as a reliable, attractive partner to the government on many O&G projects. It has partnered with the NNPC and the NPDC on multiple occasions, and we see no reason, given its record, why that status should change.
This should ensure it is well placed to participate significantly in the Nigerian National Gas Plan. For example, Seplat/NGC’s JV (AGPC) has recently raised $680m (o/w $420m equity and $260m debt) to build the ANOH gas processing plant on its OML-53 block in Imo State.
This should become one of the key gas processing plants in Nigeria it’s one of the government’s “Seven Critical Gas Development Projects, and at a processing capacity of 300MMscfd would be the 8th largest in the country, equal in size to the Oben processing plant Seplat operates on OML-4 in conjunction with a subsidiary of the Nigerian National Petroleum Company (NNPC).
Seplat and its subsidiaries and JVs already provide more than 20% of the gas used in Nigeria’s electricity generation, and we believe this number can be much higher.
“We note that this project has been run very well, with continual optimisations bringing the estimated construction cost, including financing and taxes, down from $700m to $650m”.
Of the 300MMscfd capacity, 90MMscfd has already been already contracted, 70MMscfd will be sold under the DSO, and the remainder is close to signing contracts.
There will also be condensate and LPG to be sold at market prices, linked to oil prices. Furthermore, this transaction underlines the ‘blue chip’ status of Seplat, given that the debt raise involved 7 major banks: Stanbic IBTC Bank Plc (advisor), United Bank for Africa, Zenith Bank, FirstRand Bank (London Branch),
The Mauritius Commercial Bank, Union Bank of Nigeria, and FCMB Capital Markets. It’s worth noting that the consortium allows for an additional US$60 million accordion at the time of completion to fund an equity rebalancing payment, “if considered appropriate”.
Remember that this was undertaken in a challenging COVID-crisis environment and was 50% oversubscribed. The debt terms are also favourable, with no recourse to Seplat itself other than a share pledge. We also note that completion guarantees were not deemed necessary by the consortium.
Oil
To provide low-risk oil growth, Seplat aims to unlock its existing 2C resources, which it estimates at c.106MMboe of oil and gas, as well as further exploring OML-40 to unlock what it hopes might be another 78MMboe.
It then aims to increase production through increasing wellhead efficiency and other short term oil generation activities, drilling new wells (prioritising the most profitable) and improving uptime. Part of this will be achieved through the new Amukpe-Escravos oil pipeline, which offers an alternative to the existing Trans Forcados oil pipeline.
This latter suffers downtime due to theft and vandalism (84% uptime in Q1 2021 with 12.6% reconciliation losses).
Already built and scheduled to be connected to the terminal in 2H21, this new pipeline is mostly underground and enjoys better security than its predecessor – as well as facilitating the transfer of oil from Seplat’s OML-38 and 40 blocks to the Escravos export terminal in addition to its existing route to market, the Forcados terminal, or its back-up route by barging to Warri. This development will therefore reduce costs, increase flexibility, and increase the stability of cash flows.
Seplat will further diversify its oil export routes by feeding its OML-40 oil directly into the Escravos terminal, and then potentially by building a spur line to an offshore “floating storage and offloading” vessel, which would reduce handling costs and losses.
The company aims to make acquisitions to further increase reserves & production and increase cash flow. There are several routes available, from future government, licensing rounds to acquire “established and proven” assets from international oil companies who are divesting to de-carbonise their portfolios.
Shell, which accounts for about 40% of Nigeria’s crude and condensate output, has provided one such recent example in the January 2021 disposal of its share in OML-17, and its February 2021 strategy paper confirming that it will focus more on renewables and allowing its oil production to reduce by 1-2% p.a. through a combination of depletion and divestments.
Shell has further confirmed that it is in discussions with the Nigerian government to affect the disposal of all its remaining onshore assets in Nigeria, citing incompatibility with its current strategy. Seplat has the option to make more company acquisitions like Eland, where it could take on in-production assets and improve operating efficiency.
Eland also offers an example of successful integration, being on track a little over a year post-completion to provide operational synergies as expected. This is a testament to the quality and thoroughness of this management team, and we would expect future projects to enjoy similar success.
Market Environment and Growth
Nigeria is the largest oil producer in Africa, and benefits from well-explored and proven geology, a well-established regulatory and fiscal regime, and strong infrastructure.
Seplat offers exposure to a mix of domestic and global demand, with its gas output being sold entirely into the domestic Nigerian market (both through the DSO and into the private industry) via a number of long-term fixed price gas sale agreements, and its oil being marketed and sold internationally to off-takers at terminals including Forcados and soon Escravos.
We don’t propose to go into the global oil market environment in detail in this note, as there are much more qualified to do so than us – and most of them still fail to accurately predict oil prices in the short, medium, or long term.
However, we do believe that we are potentially on the cusp of an oil super cycle, with supporting factors including the dearth of investment in new capacity in recent years, the reduction in shale capacity in the US under a less friendly government, and the recovery in oil demand that would result from any degree of ‘normalisation’ post-COVID.
First, investment: according to the IEA, in 2015 global upstream oil & gas capital expenditure (CAPEX) was cut by 25% to $583bn (2014: $779bn) and has never recovered. In fact, it then fell a further 26% in 2016 to $434bn, before steadily rising a mere 15% over the next 3 years to $500bn in 2019. 2020 saw a further 34% cut to CAPEX, and this is not expected to turn around in 2021.
This level of CAPEX was last seen in 2004, which was the start of a significant run-up in prices to 2008. We also believe that the US shale market, which due to its ability to switch supply on and off quickly and produce at lost operating cost was something of a price moderator, is significantly weakened by a Biden presidency.
This has already resulted in the pause of production on federal land, and the cancellation of the major Keystone XL pipeline. Whether or not this is a prelude to broader restrictions, it will likely curtail capex in the US in the short term due to its aggressive signalling.
As such we believe that supply will be constrained over coming years if demand can recover to any significant extent. In the short term, the key demand driver is COVID and any associated rebounds. On the assumption that lockdowns can’t viably extend much longer (see civil disobedience via restaurant openings in Italy, increasing awareness of the societal and financial costs) then hydrocarbon demand should (and in China and India did) rebound sharply.
The IEA predicts oil demand in 2021 to be just 3% shy of 2019, at 96.4mmboepd. Indeed, the IEA’s base case is that demand in 2H21 will outstrip supply, leading to a rapid drawdown in crude stocks. OPEC is slightly more pessimistic at 96.1m barrels demand. Annual demand growth has averaged 1.2mmboepd for the last 20 years, but the longer-term demand picture from here is clearly fairly nuanced: efficiencies, government and market incentives, renewable power generation, and the potential long-term reduction in business travel will act as drags on this, with some commentators expressing the belief that demand has actually now peaked for good.
However, it’s worth noting that the IEA and OPEC both disagree with this outlook: neither expect demand to peak in the next 10 years, and the cost of the renewables infrastructure required to transition to a declining demand curve remains prohibitive. A key point here is that even were demand to flatten sooner, significant investment is still required to offset production declines, and it’s not clear that the current level of upstream capex is sufficient to achieve this.
The IEA believes that additional production of 27- 30mmboepd by 2022 and 68-70mmboepd by 2030 will be required to counter baked-in production declines. With the number of investors diversifying their portfolios away from oil & gas producers, it is possible that we have reached peak investment instead of peak demand!
This would clearly be beneficial to prices, although longer-term sustained high oil prices would likely accelerate the transition into renewables, which are ever more cost-competitive. On the domestic oil scene, the key driver to watch is the Petroleum Industry Bill, proposed by the President – it is hoped it will pass a vote in the National Assembly, in which President Buhari’s party enjoys a majority, in Q2 2021.
This bill is hugely significant, representing the first comprehensive overhaul of Nigeria’s oil & gas laws since the 1960s. This iteration of the bill was first proposed by Buhari in 2020 and if passed will ensure the creation of a more effective and transparent governing body for the industry, will maximise production and will establish a competitive framework for the NNPC.
The drive behind this bill is already visible, with the first license round in 15 years having been held in 2020 – with more frequent rounds promised to bring more marginal fields into production.
The Nigerian domestic gas market requires much closer attention, as it is of growing importance to Seplat and offers a path to significant growth.
The Nigerian market benefits from being rich in natural gas, government moves to transition to a greener economy via gas, and significant economic and population growth ahead: According to the Department of Petroleum Resources (DPR) Nigeria is estimated to hold c.203 trillion cubic feet of gas – over a third of Africa’s gas reserves, with the Delta region in which Seplat operates representing the majority of this.
The DPR aims to see this rise to 210tcf by 2025 and 220tcf by 2030. Nigeria is keen to use this extraordinary resource to transition towards a green economy.
Because renewable infrastructure is not viable in the immediate term, natural gas is the tool of choice to replace the huge quantity of local diesel generation; as well as maximising use of its own resources. Nigeria is therefore pushing hard to maximise natural gas-powered generation.
The NNPC estimates that as a result of these factors demand for natural gas in Nigeria’s domestic market, which currently predominantly comes from power and industry, could rise from 1.5 billion standard cubic feet/day (bscfd) to 7.4bscfd in 2027.
A complication in the domestic market is the Domestic Supply Obligation, or “DSO”, which obliges producers to supply and deliver a specific portion of their gas production to domestic users, the quantity and price of which are determined by the Petroleum Ministry.
For Seplat these are 130MMscfd (gross volumes) and $2.50/mcf respectively. However, we note that Seplat produces c.101 MMScfd, significantly in excess of this obligation, and is, therefore, able to sell this excess into the open market (although in reality this is mostly contracted under long term supply agreements) at around $2.90/mcf. (ii) The Nigerian National Gas Plan is a cornerstone of federal government policy.
Approved in 2017 it aims to use gas production and consumption to stimulate the economy, position Nigeria competitively in high-value export markets, and guarantee the long-term energy security of the country.
Nigeria’s stated aim now is to strive to create an environment that encourages gas exploration and production. Nigeria’s National Gas Expansion Program aims to take this even further and offers significant potential to increase domestic gas consumption.
It aims to convert generators and cars to run on natural gas instead of petrol and replace local diesel-generated energy with a national gas-powered grid. It is estimated that the national grid of Nigeria constitutes c.11GW of power (of which half is operational), vs. some 20GW estimated to be provided by local diesel generators.
Converting the distributed capacity to a central network powered by gas would be much cheaper & more efficient, more reliable, quieter, safer, and more environmentally friendly than today. But diesel generators are even worse for the economy than they first appear – because of inefficiencies and other issues, Nigeria’s state oil refineries only operate at about 10% of capacity.
This means much unprocessed crude is exported and more expensive processed oil, diesel, etc. is actually imported into Nigeria! The GDP boost from stopping this negative spread trade would be significant in and of itself, and on top of improving its refineries, replacing demand for diesel with domestically produced natural gas would assist in this goal.
A reduction in reliance on generators in favour of an increasingly reliable grid would free up personal and business income and wealth, which can then be deployed more productively, boosting the economy and creating more demand for gas usage in a virtuous cycle.
It’s also an unfortunate truth that many households can’t afford a generator at all, and as such access to energy was only 60% in 2020. For much the same reason they can also not afford renewable energy generation in its current form.
The prevalence of local gas in Nigeria means it could deliver 100% access in due course – indeed the goal for this is 2030 under the UN’s Sustainable Development Goals framework. Further benefits can be derived from reducing or eradicating flaring – the practice of burning off gas that’s still often treated as a by-product of oil wells. Nigeria currently flares c.330Bscf per annum: for context, this is about the same amount of gas that it uses to generate electricity.
However, it targets 2030 as the year to end all flaring, which accounts for about 25% of its total CO2 output – not to mention wastes billions of dollars of potential revenue. COVID has stalled progress towards this goal, but as the world emerges from the crisis, analysts believe that environmental and revenue pressure will prevail, and more gas will be captured to use domestically to feed some of the expected growth in demand.
Clearly, Seplat’s processing facilities will benefit from this volume increase, and Seplat has procured 4 gas compressors for its Sapele field, which will cut flaring there (currently 25MMscfd of gas is flared) by c.90%. Sapele is the source of the majority of Seplat’s flaring activity.
The grid itself doesn’t provide significant geographic coverage and what coverage there is suffers from frequent blackouts. More and better infrastructure is clearly needed to facilitate this transformation.
In February 2021, President Buhari approved a $2.6bn infrastructure fund, seeded by its central bank, to invest in improving travel and power infrastructure around the country. The objective is to grow this to $40bn over time.
This is another clear indicator of the focus on using reliable power generation to improve the economic outlook of the country, and we believe improved power distribution infrastructure could play a crucial part in increasing demand for gas.
It will take time for business and households to trust a centralised system given the current unreliability, but once that trust is earned growth in gas usage could be phenomenal. Nigeria’s economic and population trends look positive and should supply a material tailwind for gas consumption.
The population is forecast to more than double by 2050, from 200m to 450m. Further, this population is getting wealthier, and we believe positive feedback loops from the currently underway overhaul of the oil & gas sector, which represents 10% of Nigeria’s GDP, could speed this development up materially. This increasing wealth will likely drive energy consumption up from its current level of less than 150kwh per annum – for context, the global average is 2,674kwh per annum through the use of refrigeration, air conditioning, and other luxuries that have become necessities elsewhere in the world.
Dividends
Seplat started paying a dividend in 2014: it offers a 5-cent baseline dividend each year (in the absence of major adverse circumstances), to be topped up depending on the growth achieved and the cash/liquidity position at the relevant year-end.
The baseline dividend (a 4% yield on its own) is currently well protected, with significant cash and retained earnings to cover it. Seplat seeks to employ a progressive dividend policy, though for obvious reasons (global oil market disruptions) hasn’t really achieved this goal in 2018-2020.
However, it has maintained both its 5c baseline and 5c top-up dividends in these 3 difficult years, which is a testament to the solidity of its business model and level of cash generation.
The 5c top up was confirmed for 2020, resulting in a 10c total payout of about 7.2 pence for 2020, equal to roughly $58.8m of cash.
Seplat has now adopted a quarterly dividend model, with its first, $0.025, announced on 29th April 2021 taking the cumulative return to 61c per share since the maiden dividend in 2014.
“We believe that with the oil environment improving and the domestic growth outlook strengthening, at least the same dividend could be paid throughout 2021.
“We do not expect share buybacks to feature due to the large strategic and insider ownership of the shares: a buyback would likely do more damage by exacerbating restrictions on liquidity than it would do good by signalling undervaluation.
However, there is a modest $5m programme to buy shares for the LTIP between March and May 2021 – we don’t expect this to materially impact liquidity”, Capital Access stated.
Financial Highlights – New Bond Issue
On 25th March, Seplat issued $650 million of 7.75%, 2026 senior bonds, which were used to redeem the $350m of 9.25%, 2023 senior notes and to repay $250m of drawings under the RCF – with the remainder to cover costs and be spent on general corporate purposes.
This 150bps reduction in interest rates suggests increased confidence in the business from debt investors and reduces refinancing risk by effectively extending the debt for a further 3 years.
The fixed coupon also reduces risk in what could become a rising rate environment.
Financial Highlights – 1Q21 Results Production of 48,239 boepd in 1Q21 (+0.5% Year on year) was at the lower end of the guided range of 48k-55k boepd, but volumes in April accelerated to 54k boepd as the Oben-50 gas well is now producing.
Gas production, on the other hand, was up 30% Year on year due to a favourable comparable – the Oben Gas Processing Plant having undergone maintenance in 1Q20.
The Oben-51 well has been drilled and is expected to flow in May, and work over activity at Oben-44 and Oben-46 combine to suggest that FY21 production could be nearer the middle of the guided range, perhaps based on April’s volumes as high as 52k-53k boepd.
Meanwhile on the cost side, management is confident that “ongoing cost-cutting initiatives and prudent management of cash will enable further reductions in debt, whilst supporting dividend payments and investment for growth.”
The oil business produced an average of 28,541 bopd, down 13.2% due to delays in citing a new storage vessel at OML-40 to replace the one damaged in November. Production resumed in March and volumes should therefore normalise in 2Q21.
Elsewhere, output increased at OMLs 4,38, 41, OML 53 and OPL 283 and the Extended Well Test at Ubima was completed, with production having commenced in March. The Amukpe-Escravos Pipeline, which remains outwith Seplat’s control, has seen slower progress, but the NPDC now owns a stake and is agitating to speed up its completion.
Management now expects the export of its initial permitted volume of 40k boepd through the terminal to take place in H2 this year. As a reminder, this pipeline should significantly increase uptime from its current 84% level and reduce theft and reconciliation from its current 12.6%.
The average price achieved was $60.76, vs $49.85 in 1Q20, reflecting the more positive global oil market. The gas business produced an average of 114 MMscfd (19,698 boepd) at an average selling price of $2.76/MSFC – compared to 101 MMscfd and $2.79/MSCF in FY20.
It contributed 18.6% of group revenue, +0.9bps Year on year.
Capex was $32.6m, roughly in line with the $150m guided for the full year; $18.7m of this related to the completion of two gas development wells and pre-drill & operations costs for two ANOH upstream gas wells at OML 53; $8.7m related to the Sapele Gas Plant upgrade and $5.2m to other facilities and engineering costs. Seplat’s safety record extended to >17m hours without an LTI on Seplat-operated assets.
In terms of financials, revenue was up 16.8% Year on year to $152.4m, with both oil (+15.5% due to pricing) and gas (+22.8% due to volume) contributing to the growth.
EBITDA was $77.8m and net profit before tax adjustments was $28m, vs. a loss of $95.7m in 1Q20. Operating expenses per boe fell to $8.70, from $7.70 in 1Q20, with higher total production operating expenses of $37.6m (including maintenance costs to support asset integrity work) offset by lower crude handling charges as the Liquid Heater Treater became operational, resulting in minimal water volumes being evacuated through the Trans Focados Pipeline.
Output is hedged through the purchase of put options, which during 2020 covered 6.5 MMbbls. Hedging added $22m to PBT in the year.
In 2021 the hedging continued as follows, with 7.0 MMbbls covered so far, at between $30 and $45/bbl, as illustrated in the table to the right.
Seplat gives guidance on production levels, not on group financials – which are clearly heavily influenced by the oil price, amongst other factors outside the company’s control. It also guides on capex.
Production guidance has been reiterated at 48k-55k boepd – originally this was set at the FY20 results, and represented an increase at the top end of the range.
Capex guidance also remains unchanged at $150m for the year, in line with 2020, with a focus on gas projects. However, the spending will also cover an exploration oil well to meet reserve replacement targets.
It’s also worth noting that capex can’t be viewed in isolation as levels required vary by the type of asset acquisition undertaken – if Seplat buys in a producing asset, capex is lower than if it wins a license and has to set up wells, etc. itself.
Balance Sheet
Seplat is focused on reducing its net debt from its current $458.1m (1Q21) – of which $236.3m is represented by cash offsetting a gross debt level of $694.4m. This deleveraging will happen naturally to some extent through the repayment of the Westport loans, which should net Seplat c.$414m.
There is an undrawn RCF, paid off by the recent $650m senior note issue As of December 31, 2020, the balance on the Westport-Elcrest Loan was $417m and the loan is due to be fully repaid by December 31, 2024. While the loan is outstanding, Seplat will consolidate 100% of Elcrest into its accounts.
On full repayment of the loan, Eland’s working interest in OML 40 will revert to 20.25%. Through the Eland Acquisition, Seplat also acquired a 40% interest in the Ubima marginal field, for which Eland is carrying the cost of the development in return for an 88% working interest until the carry has been reached.
Elsewhere in the balance sheet, one has to watch receivables, because in Nigeria some companies have had problems being paid by power generators and other in-country organisations.
Receivables owed by the Nigerian Petroleum Development Company (NPDC, a subsidiary of the NNPC) fell by 52% to $107m at the end of FY20 after it made catch up payments of $154m, and fell again to $97.2m in 1Q21.
We see this as further evidence of the strength of Seplat’s governmental relationships. Receivables are generally paid promptly.
Cash Flow –
Key things to watch in the cash flow include acquisitions and investments, and movement in loans. As discussed in the balance sheet, analysts stated the expectation that debt reduction to be a drain on cashflows for a few years, but this should be offset by cash coming in from the above-mentioned Westport loans and from the ANOH joint venture.
Cash generation obviously swings materially with moves in the oil price and with production levels.
Operating cash flow in 1Q21 was $84.1m, up slightly year on year from $81m. Due to timing differences in the lifting dates scheduled towards the end of Q1 and resultant settlement dates that included $36.8m for sale crude oil in trade receivables, operating cash flow after working capital movements was $5.3m (Q1 2020: $64.5m).
The overview of consensus suggests material growth ahead, following a tough 2020, with material revenue growth provided by oil price increases, which also flow down to net income.
Looking into the detail, there is quite a range of forecasts for 2021 and 2021 across all metrics. We have broken out the minimum and maximum forecasts, as well as the first and 3rd quartiles to account for outliers:
The consensus for production is in the middle of management’s guidance range of 48k-55k boepd, so expectations here aren’t controversial. The more recent estimates for oil prices were higher than those last updated in 2020. In its March Outlook, the EIA expected 2021 Brent to average $61, and April spot has oscillated around $60-$70.
Given post-period moves in the price of oil, and the current environment discussed above, we wouldn’t be surprised to see this increase for the rest of the year. Revenue and profitability numbers are clearly derivatives of price and production, those having the largest influence on both.
That said, consensus expects an EBITDA margin uplift from 50% to 54% from FY21 to FY22, which is clearly driven by the forecast lift in production and, to a lesser extent, prices.
Growth in the oil price should obviously feed straight down to the bottom line, whereas growth in production has a corresponding operating expense but should still increase margins significantly.
SEPLAT: Capital Investment, Oil Rally Brighten Earnings Outlook
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source https://dmarketforces.com/seplat-capital-investment-oil-rally-brighten-earnings-outlook/