WTI $64.60 -20c, Brent $68.00 -39c, Diff -$3.40 -19c, NG $2.53 -3c, UKNG 46.25p +2.04p

Oil price

Oil has been quiet all week as the vaccine worries in the EU are offset by good progress in the US. The Fed has upped US GDP forecasts to 6.5% from 4.2% and whilst acknowledging some inflationary risk says accommodative policies will remain.

EIA stats still impossible to read although refinery utilisation rose sharply after a couple of weeks being affected by the Texas freeze up. As I write the oil price is falling sharply…

Genel Energy

Full Year 2020 results from Genel this morning, net production averaged 31,980 bopd in 2020 (2019: 36,250 bopd), in line with guidance. This was following the ‘pause in the drilling programme at Tawke, appropriate to the external environment’ as the oil price at the time was c.$26 pb.

Very encouragingly, first oil from Sarta achieved in November 2020, with asset now producing over 10,000 bopd and at better than good margins and generating cash. Sarta will return more than that from Taq Taq which it is replacing. Next is Qara Dagh where preparations are underway to mobilise a rig for an April spud, this is described as being ‘a potentially sleeping giant’ where results are expected late in Q3.

$173 million of cash proceeds were received in 2020 ($317), the low-production opex per barrel of $2.8/bbl in 2020 helped deliver cash generation of $85 million in the year from producing assets giving free cash outflow of $4 million following ‘material’ capital expenditure on growth assets.

Dividends of 15¢ per share announced in 2020 (15¢) and the board point out that calling a dividend then looked ‘bold’ this time last year when the oil price was c. $26. The focus is very much on resilience to market conditions and the ability for Genel to ‘ride them out’ whilst targeting ‘a progressive and sustainable’ policy. This makes for two comments, firstly that if being bold at $26 paid off then at $68, today then the ‘base’ should be higher which is good news for shareholders.

Net cash of $6 million at 31 December 2021 following the call of the old 2022 bond, with cash of $274 million and reported IFRS debt of $268 million, sensible and active management of the debt reduced and extended debt to 2025.

In the ever increasingly important ESG area, carbon intensity of 13 kgCO2e/bbl for scope 1 and 2 emissions in 2020, significantly below the global oil and gas industry average of 20 kgCO2e/boe made Genel a market leader.

Unsurprisingly given how the company performed in what was a difficult year but worked through with confidence in the long term, Genel’s outlook is positive.  Production guidance for 2021 is maintained as slightly above the 2020 average of 31,980 bopd, ‘with the potential for a higher exit rate and further growth in 2022 depending on success of the Sarta appraisal programme’.

Margin of $15 per working interest barrel is expected in 2021 at average Brent oil price $60/bbl, with receivable recovery payments increasing that to $20/bbl. 2021 capital expenditure guidance is maintained at $150 million to $200 million, with the current macro environment and outlook supporting investment at the top end of this range. Genel have no shortage of potential to invest in varying areas of the portfolio but are not being gung-ho, for example Bina Bawi offers gas production and light oil opportunities but ‘only with agreement with the KRG’.

$100 million expenditure is forecast to be spent on growth assets, with three appraisal wells at Sarta targeting a material 2C resource and the QD-2 well, set to spud shortly, aiming to open up a new producing field. Opex are higher than last year at c.$50m ($33m) which is very low and only higher than last year due to the Sarta start-up.

Given the increase in the oil price and ‘confidence in ongoing payments from the KRG, including override and receivable recovery payments’, Genel expects to generate cash in 2021 post-dividend payments. These work out as follows, receivable recovery payments expected to generate c.$50 million in 2021 at an oil price of $60/bbl and a $5/bbl change in Brent impacts cash generation by c.$35 million in 2021.

Bill Higgs, Chief Executive of Genel, said:
“2020 was a uniquely challenging year for everyone. As for Genel, our continued progress and strong performance in 2020 has laid the foundation for a year of growth and operational catalysts in 2021. We continued investment in Sarta, which entered production in November, and the field is generating cash as we now move to rapidly appraise its exciting potential. Three appraisal wells will be drilled at the licence in 2021. The QD-2 well at Qara Dagh is also set to spud shortly, as we look to evaluate the potential to add a fifth producing field.

As we make this investment in growth, the low-cost and high-margin nature of our growing oil production means that we expect to generate significant free cash flow at the prevailing oil price. In turn, this gives us the confidence in our material and sustainable dividend distribution, including a final dividend of 10 cents per share announced today, as we continue to offer investors a compelling mix of growth and returns.”

The fact that the numbers worked so well for Genel last year when conditions were rough and the outlook uncertain means that provided the excellent management continue with their disciplined approach then shareholders can also remain confident.

With existing fields performing well and Sarta proving an inspired acquisition, Genel with its strong finances are in very good shape, add to that more from Sarta, a crack at Qara Dagh and the payback from the KRG and shareholders may be able to look forward to a dividend increase with the interims. A certainty to stay in the Bucket List where it is up some 40% since December.

Independent Oil & Gas

Finals today from IOG, whilst the numbers are neither here nor there it has been a busy time ahead of first gas due Q3 2021, development works extensively progressed across all four key project elements: platforms, subsea, drilling and onshore.

An EPCI contract was signed with HSM for the Phase 1 Blythe and Southwark normally unmanned installation platforms and engineering and fabrication activities progressed through 2020 at HSM’s yard in the Netherlands. Phase 1 SURF scope EPCI contract was signed with Subsea and fabrication, transportation, preparation and installation of Blythe 12” and Elgood 6” lines completed.

Extensive preparation, contracting and procurement undertaken for the five-well Phase 1 drilling programme including a rig contract awarded to Noble Corporation’s Noble Hans Deul jack-up following a competitive selection process. Petrofac was awarded a well management contract and approved as Well Operator for the Phase 1 whilst detailed Well Design initiated and extensive Tier 1, 2 and 3 services and tangibles contracts awarded.

Engineering, procurement and construction work progressed at the Thames Reception Facilities (TRF)  onshore at the Bacton Gas Terminal (BGT), where IOG’s gas will land to shore. The EIA and FDP were approved in the period and IOG were awarded a licence, P2589 as operator in the 32nd Round and reprocessing of 3D seismic over the portfolio is under way.

Those events that happened last year teed the company up for what is now the important stage in the development. The presentation included completion of the platform fabrication with its move imminent whilst other key activities now are led by the spud of the Elgood development well which is expected in April so only a matter of weeks to go now.

Andrew Hockey, CEO of IOG, commented:
“Last year we made tangible progress towards the safe, efficient and timely delivery of first gas, despite the challenges of Covid-19 and volatile industry conditions. That momentum is ramping up as we progress through 2021, with our strengthened team executing the platform, subsea, drilling and onshore project scopes. Following a rigorous recent cost and schedule review, we expect to achieve first gas in the latter part of Q3 2021, funded by our 2019 farm-out and bond issuance.

We see Phase 1 as the springboard for successive phases of growth under our infrastructure-led hub strategy, combining efficient development of nearby discovered resources with step-out exploration and appraisal activity. Our latest technical work has identified potential opportunities to develop additional gas hubs to build further shareholder value.

Besides generating strong returns, we believe IOG’s strategy can contribute to the UK’s Net Zero journey. By delivering domestic gas resources directly into the import-dependent UK market at low cost and with low carbon intensity via our reused infrastructure, we will be reducing reliance on more carbon-intensive imports.”

All is going well at IOG as the company approaches first gas from Phase 1 where a gas sales tender process has been initiated and a number of potential partners expressing interest in the company’s offtake. The shares have climbed inexorably as we approach the gas moment and local prices indicate that this will be a profitable development which will be very welcome to the UK where gas demand shows no sign of easing.

Bahamas Petroleum

BPC update on its assets in Trinidad and Tobago and Suriname this morning, workstreams substantially complete for drilling of the Saffron #2 appraisal well, with mobilisation of various services and equipment scheduled to commence in mid-April 2021, and the well is expected to spud on or around 17 May 2021, with a 25-30 day expected drill duration.

Saffron #2 includes a production completion, allowing for immediate oil production rates of 200 – 300 bopd, on completion of Saffron #2, a further five to nine production wells are currently planned, to be drilled in H2 2021 as part of an overall field development of up to 30 wells. Assuming success of Saffron #2 and these further wells, the Board is projecting average daily production from the Initial Program of up to 1,000 – 1,500 bopd by the end of 2021, which could provide US$8 – 12 million of annual net incremental cashflows going forward at US$60 / bbl oil price.

Workstreams ongoing for drilling an appraisal well and conducting an extended well test on the Weg Naar Zee PSC in Suriname, with the well expected to spud in July 2021. Operational challenges arising from Covid-19 have caused a minor delay in well timing.

Baseline Trinidad portfolio production has stabilised at 450 – 500 bopd, with an additional 10 workover projects planned for Q2 2021 which is initially encouraging. Additionally, more than 40 potential infill drilling locations evaluated within the existing producing fields, with four infill wells high-graded and selected for drilling in H2 2021. These wells have projected production rates in the range of 50 – 100 bopd per well.

3D seismic re-processing trials across the South West Peninsula (SWP) area to be completed by October 2021, allowing for the selection of future exploration drilling targets and discussions are ongoing with various parties in relation to a potential prepay facility over the Company’s producing asset base in Trinidad and Tobago. Finally, technical and commercial due diligence progressing on certain potentially accretive production acquisition targets in Trinidad and Tobago.

Simon Potter, CEO of BPC commented:
“Since we acquired our Trinidad and Tobago and Suriname licenses, the team have worked tirelessly to fully understand their significant potential. This has progressed such that we are now looking at multiple value drivers via appraisal, infill and well testing campaigns across our portfolio during 2021.

Our immediate focus turns to the upcoming drilling of the Saffron #2 appraisal well, which we anticipate beginning 17 May 2021. Saffron #2 will further our understanding of the field and, in a success case, can quickly be put into production at extremely low cost, potentially adding 200-300 bopd.

It is our intention that through these actions we can continue to increase production to more than 2,500 bopd across our portfolio which, with a conservative oil price estimate, can generate significant cash flow.”

Predator Oil & Gas

Some technical data analysis from PRD this morning on the Guercif Scoping Development and Operating Costs for Pilot Compressed Natural Gas (“CNG”) Project. In accordance with the Company’s strategy to fast-track monetisation of an initial potential gas discovery at MOU-1 for the Moroccan industrial market, SLR Consulting Ltd, petroleum engineers and oil and gas advisors, were commissioned to develop a high level scheme for the transport of dry gas from the Guercif well site to existing reception facilities via a CNG “virtual pipeline”.

Capital and operating cost estimates have been generated together with a consideration of different trailer options for road transport. Diesel versus CNG fuel options for haulage trucks were evaluated for the impact on capital and operating costs and carbon footprint. Initial well head pressures were assumed to be 2100 psi declining to 500 psi over 5 years, road distance to market point was calculated to be 340 kilometres. An initial Pilot CNG project assumed a production profile of 10 mm cfgpd and a project life of 10 years.

The results of the scoping cost estimates based on actual CNG industry data are summarised below.

• Gross capital development costs for start-up production of US$15.185 to 15.833 million, depending on haulage fuel choice and steel components used. Net to the Company’s 75% working interest £8.2 – 8.6 million using an exchange rate of US$1.39 to £1.00.
• Total amortised capital and operating costs over the 10-year life of the pilot project of US$2.79 to 4.24/mcf, with the lower estimate based on using greener CNG and not diesel as haulage fuel.

Undiscounted net-back, excluding the drilling of an additional development well assuming MOU-1 is potentially completed as a production well, uses published gas prices for the Moroccan industrial gas market of between US$10 and 12 /mcf. These are underpinned by strengthening oil prices. Scoping net-back for example is  US$7.21/mcf at US$ 10/mcf gas sales price and using the greener CNG fuel haulage option.

Scoping annual gross undiscounted potential revenues of US$26.3 million (US$19.7 million net the Company’s 75% working interest) for 3.65 BCF of gross annual gas production would support a potential commercial development in an MOU-1 success case and provide multiples of the development capital requirements necessary to attract reserves-based lending. For a 10 year pilot project life, total gross gas resources required are  36.5 BCF. For the first 10.6 BCF of net gas production no government royalties are payable and there is no liability for corporation tax until 10 years have elapsed.

The pilot CNG project concept is designed to have flexibility to facilitate upscaling to supply the growing industrial market. It requires low levels of capital investment and therefore market penetration and increased market share has the ability to be fast-tracked via a transparent and uncomplicated, de-risked, development option.

In the medium and longer term the ability to monetise larger volumes of gas from the considerable inventory of gas prospects and potential gas resources in the Company’s Guercif licence for gas-to-power in Morocco, and potentially for export, remains  an attractive commercial proposition for business growth.

The company also updates on the Offshore Ireland – Floating Storage and Regasification Unit  (“FSRU”) and LNG In the context of the Company’s Floating Storage and Regasification Unit  (“FSRU”) and LNG project offshore Ireland, designated “Project Rainbow” by the Company, the Company is making a submission to the Public Consultation on the expert advisory group report entitled “Expanding Ireland’s Marine Protected Area Network”, published by the Department of Housing, Local Government and Heritage. Deadline for submissions is 30 July 2021. This will be in conjunction with the Company applying for Marine Area Consent for Project Rainbow as part of conforming to new regulations put in place to replace some of the existing regulations.

The purpose of the submissions and applications is to demonstrate that the Floating Storage and Regasification Unit  (“FSRU”) and LNG project is in the public interest, as it is the only viable  near-term  solution actively being worked on to address diversity and security of gas supply and gas storage options. Security of energy supply is accepted by regulators as being of public interest.”

Paul Griffiths, CEO of Predator Oil & Gas Holdings Plc commented:
“The eagerly awaited receipt of the CNG scoping development design and capital and operating costs has demonstrated a simple path to early monetisation of gas from the Guercif area. It provides the input data necessary to help expedite a Plan of Development submission based on a potential gas discovery and required for the Environmental Impact Assessment. The development option is simple, easily managed and requires very low levels of capital to generate near-term gas revenues. Importing specialist haulage vehicles and trailers and storage capacity are the only significant long-lead items. The potential for early and material revenue generation and profits is very exciting. Successfully executing a  pilot CNG project will de-risk scalability and drive the potential to add large numbers of new industrial customers where no realistic alternatives to imported fuel oil currently exist.

Project Rainbow is being accelerated in Ireland as the regulatory process becomes clearer and more focussed on the public interest element of the project, which is driven by the developing security of energy supply and capacity near-term emergency.”

Block Energy

I noticed yesterday that yet another RNS from Block Energy confirming the exercise of options and PDMR dealing. This time CEO Paul Haywood has exercised his options to acquire 4,400,000 shares at 2.5p per share. This is part of a pattern of activity by board members over recent weeks to exercise options and making share awards.

My reading of this is that there is growing expectation around the production testing programme which is planned to monitor reservoir production and facility parameters in order to determine the maximum flow potential and optimum production rates. The company will continue the testing programme into Q2 this year and, on completion establish stable production from the West Rustavi wells.

Additionally I am hearing that there is some dissatisfaction amongst the ranks of existing and former employees, contractors and consultants who were forced to take 40% + of their salaries in BLOE equity back in April 2020. The plan to cut costs may have unwittingly played into the hands of the dissenting major shareholders as with many of these unhappy campers now outside the tent they appear to be adding further weight to the Block Shareholder Action Group which is pondering its next move.

This has played out for some time now but with these option moves rather telegraphing strategy they may have encouraged the dissidents to play ‘Check’ one more time and ‘Check Mate’ may only be a move or two away one might surmise. This is one to watch in the continued cat and mouse game that shareholders are playing…

KeyFacts Energy Industry Directory: Malcy's Blog