Malcy’s Blog – Oil price, Afentra, Empyrean Energy, Hurricane Energy, Jersey Oil & Gas, PetroTal Corp & finally

WTI $102.02 +32c, Brent $105.32 +33c, Diff -$3.30 +1c, NG $7.27 +42c, UKNG 130.0p -50.0p

By Malcolm Graham-Wood

Oil price

A quiet day when concentration was on the gas market which moved around vastly from continent to continent. Oil prices remain quiet today.

Jersey Oil & Gas

Jersey Oil & Gas has announced its audited results for the financial year ended 31 December 2021 and the time and date of its forthcoming Annual General Meeting.


  • The Company has aggregated a significant oil and gas resource base in the Central North Sea, the “Greater Buchan Area” (“GBA”)
  • JOG launched its GBA farm-out process and is actively engaged with multiple counterparties
  • Farm-out activities have intensified with JOG broadening the development solutions under ongoing evaluation with the various interested parties
  • Work completed by the Company during the year is facilitating an accelerated technical evaluation of the alternative development options under consideration
  • Key pre-FEED operations completed during the year
  • Strengthened Board and senior management team with significant industry experience
  • Year-end cash position of approximately £13.0 million, with no debt

Corporate Update

JOG has aggregated a significant oil and gas resource base in the heart of the Central North Sea.  As the sole owner of the GBA, the Company has the control and flexibility to advance an optimal new development capable of unlocking substantial long-term shareholder value.  To this end, the next major step for JOG is to secure an industry partner(s) in order to move the development into the next phase of activities and secure the regulatory approvals in 2023 for execution of the project.

GBA Focus

  • JOG is actively engaged with multiple high quality interested parties regarding the planned farm-out of an interest in the GBA
  • Work is progressing to expand the development options in order to facilitate the farm-out process, with opportunities to utilise existing infrastructure for future production from the GBA under evaluation
  • Engineering studies are being completed in collaboration with the various counterparties in order to validate and de-risk the different development solutions and facilitate the negotiation of commercial constructs for the GBA farm-out
  • The range of competing development solutions, including tie-backs to existing platforms and re-use of available FPSO’s, has the potential to enhance the overall development economics
  • Upon confirmation and selection of the optimal GBA development scheme the project will then move into Front-End Engineering & Design (“FEED”) activities along with preparation of the required Field Development Plan for the North Sea Transition Authority (formerly, the Oil & Gas Authority)
  • Pre-FEED operational work included JOG completing an offshore survey to support Phase 1 of the GBA Development project. The survey acquired geotechnical and environmental baseline data within the GBA
  • The GBA development solution that is taken forward for regulatory approval will seek to deliver upon both of the industry’s strategic objectives of “Maximising Economic Recovery” and “Net Zero”

Supportive Macro Environment

  • Recent geopolitical events, exacerbated by recent under investment in the upstream sector, have led to a material escalation in oil and gas prices that has served to underline the importance of maximising domestic energy supplies
  • The UK North Sea has only a limited number of readily executable oil and gas developments with the resource scale of the GBA

Attractive Outlook

  • Progressing the GBA development project remains JOG’s number one priority with a singular focus on converting value in the GBA through industry partnership
  • Opportunities to accelerate the Company’s corporate growth strategy through the execution of potential accretive acquisitions continue to be screened and evaluated
  • The Company remains well funded with current expenditure primarily related to workstreams that will facilitate securing a successful farm-out
  • Strengthened the team with the appointments of Les Thomas as Non-Executive Chairman, Graham Forbes as Chief Financial Officer and Richard Smith as Chief Commercial Officer

Andrew Benitz, CEO of Jersey Oil & Gas, commented:

“2021 was an active and exciting year for the Company, most notably involving the commencement of our Greater Buchan Area farm-out process.  Interest in developing the GBA has been strong and we are actively engaged with multiple serious counterparties.  Since launching the process our engagement strategy has been broadened to advance a range of competing development solutions, providing increased optionality.

 “The GBA is a high-quality, development ready UK North Sea resource base of scale and we look forward to concluding the farm-out process and moving into the next phase of activities.  The Company remains well funded as we progress at pace to deliver stakeholder value through securing a successful farm-out to ensure this exciting project can be developed in the most economic and sustainable manner.”

Jersey are finding themselves in a very strong position indeed, the building of the GBA is proving to have been a very wise decision indeed and now the company is in the enviable situation of assessing ‘multiple serious counter parties’ with multiple competing development options. 

The due process and the different options mean that the company are sitting on 100% of a de-risked project with substantial value at current oil prices. It is worth noting that Wood Mackenzie recently pointed out that JOG’s project is one of only 3 development ready oil fields in UKCS of over 100mmboe – two of which just sold to Ithaca. (equity in Rosebank and Cambo)

With the many options available, given major decisions such as platform, tie-backs or FPSO’s, the JOG team is understandably very busy but the process has offered up optionality they probably hadn’t expected and the current mood in the industry is one of getting deals done which for the GBA is a perfect asset. Indeed, as a field in the centre of the North Sea with ready to access regional infrastructure it is clearly exhibiting substantial value.

JOG shares have appreciated somewhat recently but as readers know I think that when the market fully understands the value in the GBA the shares will move upwards a very long way. 

PetroTal Corp

PetroTal has announced its financial and operating results for the year and three months (“Q4”) ended December 31, 2021.

2021 Significant Milestones and Highlights

·    Achieved production of 8,966 barrels of oil per day and sales of 8,449 bopd, up 58% and 48%, respectively, from 2020;

·    Recorded a 5th straight quarter of production growth; reaching 10,147 bopd in Q4 2021 from 9,508 bopd in Q3 2021;

·    Achieved a four year Company target of 20,000 bopd in mid December 2021 underpinned by strong production rates from the newly drilled 8H and 9H wells in late Q3 and Q4 2021 that each reached over 8,500 bopd, respectively;

·    Generated record net operating income (“NOI”) and EBITDA(a) in 2021 of $105 million and $90 million, up approximately 3.6x and 5x, respectively, from 2020;

·    Generated record funds flow provided by operations(a), before changes in working capital of $86.7 million, up over 5x from 2020;

·    Grew proved plus probable (“2P”) and proved plus probable plus possible (“3P”) reserves by 53% and 39%, respectively, to 78 and 147 million barrels of oil;

·    Material progression of 2P after tax net present value discounted at 10% (“NPV-10”) reserve value per share of $1.23, up 62% from 2020;

·    Generated 2021 proved (“1P”) and 2P reserve replacement ratios of 457% and 816%, respectively; and,

·    Created the framework for a social trust representing 2.5% of production, to create long standing alignment between communities and government, with a view to minimizing social downtime, maximizing social profitability, and developing community projects that will have a significant positive impact near the Company’s Bretana oilfield.

Selected Financial and Operational Highlights

Three Months Ended

Twelve Months Ended

 (in thousands USD)

Dec 31, 2021

Sept 30, 2021

 Dec 31, 2021

Dec 31, 2020


  Crude oil revenues










  Net operating income (1)





  Commodity price derivative (income)/loss





  Net income (loss)





  Basic and diluted net income (loss) (US$/share)





  Capital expenditures






  Average production (bopd)





  Average sales (bopd)





  Average Brent price ($/bbl)





  Contracted sales price, gross ($/bbl)





  Netback ($/bbl)(1)





  Funds flow provided by operations(2)





Balance sheet

  Cash and restricted cash





  Working capital





  Total assets





  Current liabilities










 (1)      Net operating income obtained from revenues less royalties, operating expenses, and direct transportation.

(2)      Netback per barrel (“bbl”) and funds flow provided by operations do not have standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures for other entities. See “Selected Financial Measures” section.

2021 Operational highlights

·    Robust well results.  Completed one deviated and two horizontal oil wells in 2021.  Both horizontal wells had the longest laterals ever drilled in Peru with production rates in excess of 8,500 bopd during the first month, and both paying out in under two months.  Well 7D, drilled as a deviated well in the spring of 2021, had rates in excess of 4,000 bopd and has produced over 0.5 million bbl in under one year.

·    Infrastructure achievements.  Achieved significant infrastructure milestones in 2021 with the completion of all major construction work on CPF-2 and the completion and coring of an additional water disposal well, essentially doubling water disposal capacity to 100,000 barrels of water per day and allowing the field to produce up to 26,000 bopd of oil.

·    Material reserves increases.  Delivered excellent 2021 reserve report upgrades with increases for 1P, 2P, and 3P reserves by 68%, 53%, and 39% to 37.4, 77.9 and 147.1 million barrels, respectively.  In addition, PetroTal was able to decrease 2P Finding and Development Costs (“F&D”) by 6% to $4.68/bbl while adding seven 2P locations plus related infrastructure, leading to a record 2P after tax NPV-10 of just over $1 billion.

·    Expanded Brazilian sales.  Created a highly successful third sales route to market into the Atlantic region through Brazil that has surpassed the Northern Peruvian Pipeline (“ONP”) as the Company’s second most profitable sales route.  The first pilot cargo, completed in December 2020 was 106,000 barrels, and during 2021 PetroTal built a strong trusted commercial relationship that will allow Brazilian shipments of 400,000 barrel cargos (without the need for diluent blending), thereby providing a safe and stable offtake of nearly 14,000 bopd at attractive netbacks.

·    Social alignment mechanism established.  In an effort to facilitate long standing alignment between the government and communities, PetroTal announced and submitted a proposal to the Peruvian Ministry of Energy and Mines for creation of a new social trust aimed to promote direct investments into the Loreto region.  The fund will be based on 2.5% of crude oil production, payable over two week periods and calculated using the same methodology as Perupetro applies for royalties.  The fund committee and investment legal entities are in the process of being created with full transparency and auditability to the public. 

·    2021 capital program executed and optimized.  PetroTal’s 2021 Capex investment totalled $82 million in 2021 compared to $42 million in 2020, which was significantly curtailed due to the COVID-19 pandemic.

2021 Financial highlights

·    Leverage to kickstart development.  Successfully executed a $100 million senior secured bond issue at the trough of the oil price commodity price cycle with payment terms and amortization optimized to impact the Company in a much stronger oil macro backdrop, allowing PetroTal to commence its 2021 capital program in March 2021 with a sound liquidity injection.

·    Record net revenue.  Delivered net revenue after differentials and royalties of $150 million ($48.70/bbl) compared to 2020 of $74 million ($35.58/bbl).

·    Record net operating income.  Generated record NOI and EBITDA(a) of $105 million ($34.03/bbl) and $90 million ($29.31/bbl), respectively, as compared to $28.9 million ($13.84/bbl) and $18.3 million ($8.77/bbl), respectively, in 2020.

·    Successful 2021 capital program.  Executed an $82 million Capex program (originally budgeted at $101 million), deferring some non-essential infrastructure projects into 2022 to match with higher Brent pricing and more fluid labour movement.

·    Positive 2021 free cash flow.  Generated annual net positive free cash flow(a) before changes in non cash working capital and debt service of $8.4 million, a first for PetroTal.

·    True up revenue realized.  Received true-up payments from Petroperu of approximately $28.6 million in 2021 from oil reaching the Bayovar port and being sold at a higher price than originally received at pump station 1 of the ONP, enhancing financial metrics, and provided tailwind liquidity throughout the year.

·    Scalable lifting costs.  Maintained total lifting costs between $5.1 and $5.5 million per quarter in 2021 demonstrating significant scalability as production grew 60% from Q4 2020 to Q4 2021.  On an annualized basis lifting costs were $21.5 million ($6.99/bbl) for 2021 compared to $15.7 million ($7.51/bbl) in 2020. 

·    Variable costs impacted by higher Brent pricing.   Diluent and barging costs were $23.7 million ($7.68/bbl) in 2021 as compared to approximately $14.3 million ($6.85/bbl) in 2020.  Increased per barrel metrics are attributed to higher barging diesel, diluent, and floating storage costs in 2021, compared to 2020.

·    Reduced G&A per barrel.  2021 G&A of $14.3 million ($4.63/bbl) compared to $10.6 million ($5.07/bbl) in 2020, demonstrating a per barrel reduction of 10% and less than a 10% burden on adjusted EBITDA margins.

·    Record 2021 net income.  2021 net income was a record $63.2 million ($0.08/share) compared to a net loss of $1.5 million ($0.00/share) in 2020 driven by higher commodity prices, sales volumes and a derivative gain related to sales volumes moving through the ONP valued at a higher Brent price compared to initial entry into the ONP.

Operation and Financial Highlights Subsequent to December 31, 2021

·    Leverage reduction.  Due to early robust 2022 free cash flow generation and strong liquidity, PetroTal elected to repay $20 million of the original $100 million bond issue, on April 1, 2022, reducing its total long term debt to $80 million, thereby lowering future interest costs.

·    Exceptional continued well performance.  Achieved a 10 day record production level for well 10H of 10,050 bopd allowing the Company to set a new total production record of 20,891 bopd for February 2022, and well payout in under a month.

·    CPF-2 approved.  Received approval by Peruvian regulators for full commissioning and fluid processing of CPF-2 so that up to 26,000 bopd can be processed by PetroTal.

·    Free cash flow focused 2022 budget.  On February 22, 2022, PetroTal announced a $120 million fully funded capital program that could potentially generate up to $230 million of free cash flow in 2022, allowing the Company the optionality to redeem the remaining $80 million in bonds early and implement its return of capital to shareholders strategy in Q4 2022, subject to Board approval.

·    TSX-V award winner and OTCQX Best Market upgrade.  PetroTal was recognized as a top TSX Venture exchange performer for 2021 ranking 10th in the energy sector and in mid January 2022, PetroTal upgraded to the OTCQX Best Market in the United States under the ticker symbol PTALF.

·    Establishment of the 2.5% social trust brings interim dispute.  The establishment of the 2.5% social trust brought some anticipated demands from a minority group wanting to control the trust capital allocation process.   This resulted in the Company’s oil loading dock been blocked for five weeks requiring the intervention of Peru’s Prime Minister and the government’s full attention to the area’s social disputes.

Operational and Financial Highlights for Q4 2021  

·    Continued production growth.  PetroTal produced 10,147 bopd and averaged 7,242 bopd in sales, which was impacted by social disruptions at the ONP, along with intermittent downtime leading to constrained production schedules, compared to Q3 2021 production and sales of 9,508 bopd and 9,142 bopd, respectively.

·    20,000 bopd production target achieved.  The Company, with boosts from well 8H and 9H, achieved a five day trailing production rate of 20,000 bopd ending December 15, 2021, reaching its long standing target only four years after commencing operations at the Bretana oil field. 

·    Completion of well 8H.  Well 8H was completed in late Q3 2021 for under $12 million, had initial production rates in excess of 8,500 bopd, paying out in Q4 2021 from realized netbacks of over $38.00/bbl.

·    Completion of well 9H.  Well 9H, completed in early December 2021, achieved approximately 9,000 bopd in early testing, averaging 8,200 bopd for the subsequent ten-day period.

·    Strong net operating income despite constrained sales.  PetroTal generated $25.7 million in net operating income in Q4 2021, a decrease from $29.6 million in Q3 2021, driven by lower sales volumes stemming from social protests in November and December 2021.

·    Capex optimization.  The Company invested $26.6 million in Q4 2021, up slightly from the prior quarter due to ongoing consistent drilling activities in the second half of 2021.

·    Continued and expanding Brazilian exports.  PetroTal continued to utilize the Brazilian shipping route in Q4 2021, exporting 320,000 barrels in November and December 2021 compared to only 106,000 barrels in Q4 2020.

·    Opex and Transportation cost flexibility.  Lifting expense and direct transportation costs were $11.2 million ($16.82/bbl) in Q4 2021 compared to $12.6 million ($14.97/bbl) in Q3 2021, and $10.7 million ($21.23/bbl) in Q4 2020.  During Q4 2022, the Company effectively utilized barges for oil storage to manage production and sales fluctuations during social disruptions. 

·    Strong Q4 2021 exit liquidity.  Exited 2021 with strong balance sheet liquidity of $75.0 million in total cash and approximately $57.0 million of net debt which was approximately 0.63x net debt to 2021 EBITDA.   

·    Growing derivative asset.  The exit Q4 2021 net derivative asset was $36.7 million, representing the mark to market value of oil in the ONP, corporate hedges, and ONP hedges.

Operation and Financial Highlights Subsequent to December 31, 2021

·    Leverage reduction.  Due to early robust 2022 free cash flow generation and strong liquidity, PetroTal elected to repay $20 million of the original $100 million bond issue, on April 1, 2022, reducing its total long term debt to $80 million, thereby lowering future interest costs.

·    Exceptional continued well performance.  Achieved a 10 day record production level for well 10H of 10,050 bopd allowing the Company to set a new total production record of 20,891 bopd for February 2022, and well payout in under a month.

·    CPF-2 approved.  Received approval by Peruvian regulators for full commissioning and fluid processing of CPF-2 so that up to 26,000 bopd can be processed by PetroTal.

·    Free cash flow focused 2022 budget.  On February 22, 2022, PetroTal announced a $120 million fully funded capital program that could potentially generate up to $230 million of free cash flow in 2022, allowing the Company the optionality to redeem the remaining $80 million in bonds early and implement its return of capital to shareholders strategy in Q4 2022, subject to Board approval.

·    TSX-V award winner and OTCQX Best Market upgrade.  PetroTal was recognized as a top TSX Venture exchange performer for 2021 ranking 10th in the energy sector and in mid January 2022, PetroTal upgraded to the OTCQX Best Market in the United States under the ticker symbol PTALF.

·    Establishment of the 2.5% social trust brings interim dispute.  The establishment of the 2.5% social trust brought some anticipated demands from a minority group wanting to control the trust capital allocation process.   This resulted in the Company’s oil loading dock been blocked for five weeks requiring the intervention of Peru’s Prime Minister and the government’s full attention to the area’s social disputes.

Current Operations

The Company’s loading dock was re-opened on April 7, 2022 and PetroTal has been producing approximately 18,200 bopd over the last 10 days with priority sales going to Iquitos and Brazil thereafter.  Until the ONP maintenance is completed, the Company will be managing production volumes to fit the Iquitos and Brazil sales threshold of nearly 16,000 bopd. 

PetroTal is currently preparing to drill well 11H in early May with a late June or early July completion, at an estimated cost of $15.6 million.

Updated Corporate Presentation and upcoming investor update

PetroTal is excited to announce it will be hosting a virtual investor meeting on May 26, 2022 following the release of Q1 2022 results.  The objective of management will be to provide updates on certain aspects of the Bretana asset and to communicate the Company’s short and long term strategy.  The Company has provided an updated corporate presentation with these 2021 results, on its website.

Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented

“2021 will be remembered for many significant operational, commercial and financial milestones achieved by the PetroTal team.  When unconstrained, PetroTal is the largest crude oil producer in Peru and our management team is well aware of the responsibilities and deliverables that accompany that stature.  Our goals for 2022 are very clear, and given the tailwind of a robust commodity price environment aiding us, we believe the Company can add tremendous value.  Having met our original goal of 20,000 bopd, the team is now focused on achieving a new production target of 25,000 bopd with minimal social downtime.  I would like to thank PetroTal’s shareholders, directors, employees, and contractors for their continued support and I look forward to keeping the market updated on the Company’s progress throughout the remainder of 2022.”   

Whilst most of this is historic data and in the market it still fills me with joy as the news from PetroTal remains so positive. It has beaten production expectations and there is a significant increase in reserves and the NPV. Operational excellence continues with the CPF-2 approved for 26/- b/d and substantial cash flow has meant paying down debt and reducing gearing. 

I have recently upgraded again my price target which is now 100p. At change from 40p today that makes PTAL a hugely cheap stock in this market and investors should be taking advantage. 


Afentra has announced that its wholly-owned subsidiary, Afentra (Angola) Ltd, has signed a Sale and Purchase Agreement with Sonangol Pesquisa e Produção S.A. to purchase interests in Block 3/05 and Block 23, offshore Angola for a firm consideration of $80 million and contingent payments of up to $50 million (in aggregate) in the case of Block 3/05 and consideration of $0.5 million in the case of Block 23.

Acquisition Highlights

•         Strategic rationale – facilitates a first entry for Afentra into Angola, one of the Company’s key target markets in West Africa, with opportunities to build a material production business and contribute to a sustainable transition

•         Block 3/05 – acquiring a 20% non-operated interest in a high-potential long-life asset

o  Initial consideration of $80 million

o  Additional contingent consideration of up to $50 million to be paid in respect of each of the ten calendar years commencing 1 January 2023

o  Stable production of c.4,000 bopd net with strong cashflow

o  Net 2P reserves of c.20 million barrels1

o  Oil in Place of over 3 billion barrels1 provides significant resource upside

o  Highly attractive asset economics with low breakeven oil price of $35/bbl

o  To date, decommissioning costs have been pre-funded by previous and existing JV partners

•        Block 23 – acquiring 40% non-operated interest in a highly prospective deepwater exploration and appraisal opportunity for a consideration of $0.5 million

•        Funding – expected to be financed through new debt facilities and existing cash on the balance sheet. Discussions with prospective debt providers well advanced

Transaction Overview

Afentra is acquiring a 20% non-operated interest in Block 3/05 and a 40% non-operated interest in Block 23 for a total consideration of up to $130 million. The consideration is comprised of $80 million cash up front, subject to customary completion adjustments, up to $50 million in contingent payments, payable in respect of each of the ten calendar years commencing January 1, 2023 and subject to certain oil price and production hurdles, and $0.5 million in respect of Block 23. The Acquisition has an effective date of 20 April 2022.

This represents a strategic entry into a highly attractive West African jurisdiction with an implied acquisition cost of ~$4/boe, based on 2P reserves1.

The Acquisition is expected to be funded with new debt facilities and existing cash on the balance sheet. Discussions with prospective providers of debt finance are well advanced and will be finalised in due course.

While completion is expected in the third quarter of 2022, next steps in the process include the conclusion of Afentra’s due diligence exercise, the provision of a bank guarantee in respect of the 10% transaction deposit and the completion of the right of first offer process by Sonangol. Government approvals and a license extension for Block 3/05 are anticipated to be granted, with the publication of the AIM re-admission document and resumption of trading anticipated to occur mid-year. In addition to the conditions described above relating to regulatory consents, right of first offer, license extension and due diligence, the Acquisition is subject to the receipt of shareholder approval pursuant to an ordinary resolution to be proposed at a General Meeting and re-admission of the enlarged group to trading on AIM. Further details of the Acquisition and SPA will be set out in the re-admission document.

Asset Overview: Block 3/05

Block 3/05, in which Afentra is acquiring a 20% non-operated interest, is located in the Lower Congo Basin and consists of eight mature producing fields. The discoveries were made by Elf Petroleum (now part of TotalEnergies) in the early 1980s. Development was by shallow-water (40-100m) platforms that included successful waterflood activities with first oil in 1985. Sonangol assumed operatorship from 2005 and has focused on sustaining production through workovers and maintaining asset integrity. No infill drilling campaigns have taken place in the last 15 years. The asset has a diverse portfolio of over 100 wells and currently produces from around 40 production wells and has nine active water injectors. The facilities include 17 well-head and support platforms and four processing platforms, with oil exported via the Palanca FSO.

In 2021, the average daily gross production was 17,000 bopd, with an exit rate of 21,000 bopd, and gross 2P reserves of approximately 100 million barrelsat year end 2021.

Block 3/05’s existing Production Sharing Agreement (PSA) expires in 2025 and this is expected to be extended to 2040. This extension is a condition to completing the Acquisition. To date, the asset decommissioning costs have been pre-funded.

Sonangol is an experienced operator with a sustained track record across the leading and lagging indicators for safety and environmental considerations, including COemissions and flaring measurements. Afentra looks forward to working with Sonangol to determine action plans to further reduce future emissions.

Post completion of the Acquisition, the JV will be comprised as follows: Sonangol (Operator, 30%), Afentra (20%), M&P (20%), ENI (12%), Somoil (10%), NIS-Naftagas (4%) and INA (4%).

Asset Overview: Block 23

Block 23 is a 5,000 kmexploration and appraisal block located in the Kwanza basin in water depths from 600 to 1,600 metres and has a working petroleum system. Whilst the large block is covered by modern 3D and 2D seismic data sets, with no outstanding work commitments remaining, the majority of the block remains under-explored.

The block contains the Azul oil discovery, the first deepwater pre-salt discovery in the Kwanza basin. This discovery made in carbonate reservoirs has oil in place of around 150 mmbo and tested at flow rates of around 3,000 – 4,000 bopd of light oil.

Post completion of the Acquisition, the JV is expected to be comprised of: Namcor, Sequa and Petrolog(40% and operator); Afentra (40%) and Sonangol (20%).

Strategic Rationale

The Acquisition is consistent with the strategic objective set by Afentra at the time of its launch in May 2021 to build a balanced cash flow generative portfolio of assets where the Company can contribute to emissions reduction to drive a sustainable transition. These assets give Afentra exposure to a high-quality asset base with long-life, low-cost production, access to additional production optimisation opportunities, upside potential and opportunities to reduce future emissions.

Angola is a jurisdiction where the Afentra team have significant knowledge and previous experience. It offers an attractive operating environment, with good fiscal terms which have been improved in recent years to attract new investment. It is a material hydrocarbon province with a wealth of future opportunities and was a key target country for the Company.

Afentra are acquiring a meaningful interest in Block 3/05 alongside an experienced and credible operator and an aligned JV. Consistent with Afentra’s Purpose and Strategy, Afentra will be working alongside Sonangol to support its transition strategy which is closely aligned with Afentra’s ESG agenda. A key outcome of the due diligence work to date has been to identify the opportunity to work with the JV to enhance the environmental performance of Block 3/05 through emissions reductions.

Commenting on the update, CEO Paul McDade said:

“We are delighted to have agreed terms with Sonangol and signed the SPA for our entry into Block 3/05, Lower Congo basin and Block 23, Kwanza basin in Angola. This transformative deal marks our first acquisition since launch last year, and sees the Company enter Angola, a major oil and gas jurisdiction with significant opportunities ahead to build a material business and positively impact the energy transition in Africa.

This highly accretive transaction gives Afentra exposure to a high-quality asset base, underpinned by strong cash flow from stable and long-life production and 20 million barrelsof net 2P Reserves. The assets, containing over 3 billion barrelsof oil in place, provide significant scope for further value creation from production optimisation, infill drilling and incremental developments. The attractive deal metrics and strong cashflow generation demonstrate Afentra’s commercial discipline and focus on robust cash flow. The entry into Block 23 provides us the opportunity to work with Sonangol to better understand and unlock the potential of this exciting and highly prospective exploration area.

We are looking forward to partnering with Sonangol, which has run a very pragmatic and transparent process, and supporting them in delivering an effective energy transition strategy. We are also looking forward to demonstrating our commitment to the ESG principles upon which Afentra was launched and working to create value for all of our stakeholders.

The next steps will be to complete our due diligence process and to conclude our discussions on the debt facility to fund the acquisition, with a view to completing the transaction in the third quarter of 2022.

I would like to thank our shareholders for their patience through this process and hope they share the management’s excitement about the value creation implications of this deal. We look forward to communicating on our progress as we move towards the publication of the re-admission document and the recommencement of trading thereafter.”

This looks like a cracking deal by Paul McDade and team with the entry into Angola at a cost of some $4/bbl and break-even at some $35/bbl. This looks like it pays back in less than three years at $75 oil as a material shallow water production asset and yet the accretive deal also brings with it potential significant exploration upside. 

Expect the documentation to be published by June/July so one can expect a resumption in dealing in the shares shortly after that. This is going to be one to watch, no doubt. I am hoping to catch up with Paul McDade next week but the webcast was very positive indeed, watch this space. 

Hurricane Energy

Hurricane has announced its full-year results for the period ended 31 December 2021.

Financial results

·    Revenues of $240.5 million from seven liftings of Lancaster crude (2020: $180.1 million from 12 liftings)

·    Cash production costs of $28.2/bbl (2020: $17.9/bbl)

·    Generated $135.7 million of free cash flow†, equivalent to $36.2/bbl (2020: $74.2 million, $14.6/bbl)

·    Profit after tax for the period of $18.2 million (2020: loss after tax of $625.3 million)

·    Net free cash of $51.5 million (31 December 2020: $111.4 million)

·    Net debt of $27.0 million (31 December 2020: $118.6 million)

·   Repurchased $151.5 million of Convertible Bonds at average price of 86%, saving $29.5m in future principal and interest


·    Production within guidance with average daily rate of 10,267 bopd (2020: 13,900)

·    Excellent operational uptime of 92.3%, covering planned and unplanned events

·    Crude oil sales reached over 10 million barrels with 3.6 Mbbls sold across seven cargoes in 2021

·    FDPA consent received allowing for production below bubble point

·    Following unsuccessful farm out process, JV partners agree surrender of P1368(S) (Lincoln) licence


·  The Company’s proposed financial restructuring was ultimately not pursued following the High Court Judgment that the restructuring should not be implemented

·    In June 2021, the incumbent Non-Executive Directors resigned from the board, with John Wright and David Craik appointed to the board as Non-Executive Directors and John Wright assuming the position of Interim Chairman

·     In October 2021, Philip Wolfe was appointed to the board as Independent Non-Executive Director


·    FPSO Charter extension agreed in March 2022

·    Full bond repayment anticipated in July 2022

·   Net free cash of at least $60m projected following bond repayment, assuming production in line with guidance and oil prices of at least $90/bbl

·    Focus on efficient capital allocation to deliver most value for shareholders

·    Consideration of opportunities within existing portfolio and new assets

Antony Maris, CEO of Hurricane, commented:

“This last year has been one of profound change for Hurricane. Despite all the recent volatility in the oil price, with the expectation that oil prices remain over $90/bbl, post bond repayment we forecast to have over $60 million of net free cash†.

The UK Government’s renewed emphasis on security of supply is welcome and we are working hard to identify how best to optimise capital allocation in future activities to build further value for our shareholders. We have opportunities both within our existing portfolio, and in new opportunities in the UK oil and gas sector.

Against the backdrop of our demonstrable operational track record, financial discipline, and the significant rise in oil prices, we are preparing Hurricane for the future. Our thoughts are therefore fully focused on building on our position of increasing strength and value.”

As expected Hurricane is now an extremely efficient machine, something perfectly visible for some time. There is now significant upside after production beating guidance, revenue of $240m and substantial free cash flow and hardly any debt. Put the cash per share of around 4p this quarter, growing to, say 8p by the year end and this makes the current price of 9.45p quite laughable. 

Other key “new news” is the company putting a figure on the value of the tax losses- $410m- that’s 16.8p a share not to be sneezed at and 85% achievable by the looks of it. Total that all up and take a look at the margins on very creditable realisations and wise investors might just call this a no-brainer. 

Empyrean Energy

Empyrean yesterday, after the blog published,  provided the following update on drilling at the Jade prospect at its 100% owned Block 29/11 permit, offshore China:


·     LH 17-2-1 well at the Jade prospect reached final total depth of 2849 metres Measured Depth (“MD”) in Pre-Tertiary granitic formation

·     The interpretation from logging while drilling (LWD) and mud logging equipment has indicated no oil pay in the target reservoir

·     Current operations are running final logs before commencing demobilisation of the NH 9 rig

Empyrean is the operator of Block 29/11 in China and has 100% working interest during the exploration phase. In the event of a commercial discovery, its partner, China National Offshore Oil Company (“CNOOC”), may assume a 51% participating interest in the development and production phase.

Well results

Excellent quality reservoir rocks in the Zhujiang Carbonate target were intersected as prognosed. The interpretation from logging while drilling (LWD) and mud logging equipment indicated no oil pay in the target reservoir. The well reached a final total depth of 2849 metres MD at 6:00am this morning local time. Current operations are the running of wireline logs. The wireline logs are not expected to change the initial interpretation of no oil pay seen on LWD.

Current operations

Wireline logging tools will now be run following a wiper trip before commencing demobilisation operations of the NH 9 rig.

The information contained in this announcement has been reviewed by Empyrean’s Executive Technical director, Gaz Bisht, who has over 31 years’ experience as a hydrocarbon geologist and geoscientist.

Empyrean CEO, Tom Kelly, stated:

“We are extremely disappointed with the results of the well, particularly after conducting a systematic and comprehensive technical analysis followed by running a safe drilling operation. We would like to thank CNOOC for all their support, CNOOC EnerTech for managing a successful operation and COSL for conducting a safe drilling operation. We plan to conduct a thorough analysis of well log data before deciding the next step in Block 29/11”.

 Like everyone else I’m sure I am gutted on behalf of Tom, Gaz and team about this result. Like others I have watched this journey from start to finish and had hoped that the CoS could deliver a find but it was not to be despite the most encouraging seismic. 

I will try and talk to Tom about the prospects for the portfolio and will add further when I am properly brifed. 

And finally…

Last night Liverpool beat Villareal 2-0 in the Semi Final first leg, the night before the Noisy Neighbours beat Real Madrid 4-3 going back to Spain.

Tonight the Hammers take on Eintracht Frankfurt in the first leg of the Boropa Cup.

And Chelsea have a trip to the Theatre of Dreams where unfortunately the Red Devils are fielding a B team even by their low recent standards…

The opinions expressed here are those of the author

Malcolm Graham-Wood

Disclaimer: Malcy’s Blog is provided for general information about the international oil and gas industry and the companies that operate within it. It does not constitute investment advice and Malcy does not buy or sell shares, warrants or bonds in any company written about within the blog. Information is taken from publicly available sources and any comment is that of the author who does not take any third party comment in the blog

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