WTI (May) $72.97 -23c, Brent (May) $78.28 -37c, Diff -$5.31 -14c
USNG (Apr) $2.03 u/c, UKNG (Apr) 105.5p +0.17p, TTF (Apr) €43.0 -€0.995

Oil price

Oil is a bit better today, yesterday’s inventory stats were very helpful in crude and gasoline with big draws of 7.5 and 2.9m respectively but distillates disappointed with a modest build. With the Brent contract about to expire and the Iraqi pipeline showing no signs of reopening the market looks tight to me.

If you can bear it I would like to reprint an article written by the highly acclaimed bond and currency expert Marcus Ashworth in which he takes an interesting but very useful view on the dollar, if he is right, and he usually is, then greenback weakness might be worth noting. I’m sure next week’s Opec meeting will bear it in mind…

World Will Welcome the Dollar’s Coming Slide: Marcus Ashworth

(With thanks for permission to use of course)

(Bloomberg Opinion) - The dollar has lost some of its luster over the winter. The twin supports of its status as the preferred haven during the pandemic and being backed by the world’s strongest economy are fading. And now another prop for the greenback is wobbling amid doubts about how much higher the Federal Reserve will raise US interest rates as it has second thoughts on the likelihood of a recession. The dollar looks likely to suffer an extended bout of weakness.

This has no bearing on the dollar’s unrivalled position as the global reserve currency: King Dollar sits serenely on its throne. But what’s not so good for the dollar’s relative value is better for the rest of the world, because less focus is needed on keeping up with the dollar. This has led to oversized interest rate hikes to shore up currency valuations, above and beyond what monetary policy has needed to do to address specific domestic requirements on fighting inflation.

This shift is helping to correct a serious imbalance, known as the dollar smile, that had skewed too much in the favor of the US currency for much of this decade. We are likely more towards the base of the smile’s curve, where the dollar weakens steadily, as opposed to the raised sides when monies flow in on either a flight to quality or the perception that returns in the US will be superior to those available elsewhere.

The regional US banking crisis, which has seen the failure of three banks so far, is the type of stumble that could hasten an economic downturn. Furthermore, the perception of dollar safety is undermined if its banking system is under stress, particularly if the rest of the world’s financial system isn’t similarly challenged; the failure of Credit Suisse Group AG is being perceived as a one-off and, importantly, did not lead to a surge into dollars.

Minneapolis Fed President Neel Kashkari, a Federal Open Market Committee voter this year and an outspoken hawk, highlighted last weekend that bank strains bring the risk of recession closer. Although he was careful not to prejudge the outcome of the next FOMC meeting on May 3, he did emphasize how closely the Fed is monitoring the risks of a credit crunch.

Currently, the futures market suggests it’s a coin toss as to whether official rates rise by another quarter-point in May. Expectations are then for borrowing costs to start falling in the second half of the year, which is a big drag on the dollar’s forward pricing.

Any currency pair is a combination of relative value, and the most commercially important comparison is to the euro. The European Central Bank forged ahead with another 50 basis-point hike on March 16, whereas a week later the Fed chose to play safer with a more modest quarter-point raise. The shift in perceptions about the likely path of central bank rates is reflected in the euro’s 12.5% gain in the past six months to over 1.08 euros per dollar, reversing an 11-week period between August and November last year when the common currency dipped below parity versus the greenback.

Policymaker rhetoric also steers forward rate expectations and currency values. At the last ECB meeting, Executive Board Member Isabel Schnabel pushed for explicit wording that further rate hikes were possible, according to Bloomberg News. President Christine Lagarde, at the post-meeting press conference, only gave verbal assurances that a bias to tighten remains if its economic projections proved accurate. This dispute keeps alive the possibility that the ECB tightens policy to a greater degree than the Fed in the coming months.

According to economists surveyed by Bloomberg, the probability of a recession in the euro zone has almost halved this year, to below 50%. It’s now lower than the US, which is seen as having a 60% chance of a protracted contraction. That is a notable shift of expectations as the euro zone had been on the precipice of recession prior to the pandemic and has suffered most from the surge in natural gas prices since Russia’s invasion of Ukraine.

Among G10 currencies, only sterling has performed better than the euro, rising more than 14%. The Japanese yen is 10% firmer to the dollar. The typical rule of thumb is that the large manufacturing export hubs of the euro zone and Japan benefit from a stronger dollar making their products look cheaper; but the sharp rise in energy prices has placed them in the same boat as all other hydrocarbon-dependent economies. The biggest gainers from a relatively weaker dollar, though, have been in Eastern Europe and South America, with the Chilean peso notching a 22.5% gain. It’s notable that the broadest gains are from energy-importing countries which had been hit hardest by the surge in gas prices. As most of the world’s commodity complex is priced in dollars, an appreciation of the value of local currencies to the dollar offers much-needed respite. Nonetheless, the sharp appreciation of the dollar through 2021 and much of last year caused a lot of problems in developing and developed countries alike, as central banks scrambled to raise interest rates to prevent their own currencies from collapsing as the Fed tightened conditions. The world will be thankful for the calm of a more subdued value for the global reserve currency.

PetroTal Corp

PetroTal has reported its operating and audited financial results for the three months and year ended December 31, 2022.

Select financial, reserves and operational information is outlined below and should be read in conjunction with the Company’s audited consolidated financial statements, management’s discussion and analysis and annual information form for the year ended December 31, 2022, which are available on SEDAR at www.sedar.com and on the Company’s website at www.PetroTal‐Corp.com.  Reserves numbers presented herein were derived from an independent reserves report prepared by Netherland, Sewell & Associates, Inc. effective December 31, 2022.  All amounts herein are in United States dollars unless otherwise stated.

Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented:
“I am proud of our performance in 2022, a year in which the Company was resilient despite facing a number of challenges.  We are pleased with 2022’s operational and financial results, having significantly improved the operating stability of the Company in recent months from both a sales and balance sheet perspective.  In addition, it was equally important that we fulfilled our promise to investors to fully repay our bonds and initiating a return of capital program to our patient and deserving shareholder group. 

In closing, I would like to thank our shareholders for their continued support, the PetroTal team for their considerable contributions to the Company, and our Board for strategic guidance.”

PetroTal are sans doubt delivering on their promises, good levels of historic production and even better at the moment mean that the balance sheet is strong and the bond has been repaid. That production has been 20,500 b/d in March and primarily sold through the higher priced Brazilian exit route. 

The company have indeed set up a particularly generous return of capital to shareholders scheme which consists of a buy-back of 10% of the public float, starting in Q2 2023 as well as a quarterly dividend of $0.015 per share an annualised 0.06c which gives a yield of 13.9% at 45c share price.

The shares today are 43.25p up some 10% which sounds good but my target price of 150p and in place for some considerable time is not an exaggeration of the value of PetroTal. In my view it would not be inconceivable if PTAL were to attract interest from the bigger beasts in the industry just sayin….. 

2022 Key Milestones and Highlights

• Achieved average annual production and sales of 12,200 and 13,168 barrels of oil per day (“bopd”) respectively, up 36% and 56% from 2021;
• Delivered a 46% increase in 2P reserves value per share (NPV-10, after tax) to US$1.75/share (CAD$2.29 and GBP1.45), and a 24% increase in 2P reserves to 96.8 million barrels;
• Provided strong 2022 year-end 1P and 2P reserve replacement ratios of 179% and 418%, respectively;
• Set a record for daily production of over 26,000 bopd on June 30, 2022 confirming the current facility oil handling capacity;
• Drilled and completed four highly productive horizontal oil wells in 2022, with wells 10H and 11H delivering initial production rates in excess of 10,000 bopd;
• During well 13H’s drilling operation the technical team encountered the target producing formation approximately three meters higher than prognosis which contributed to oil-in-place and reserves upgrades in the 2022 year-end reserve report;
• Generated record annual net operating income (“NOI”) of $274 million ($56.90/bbl) and adjusted EBITDA inclusive of realized derivative impacts, of $256 million ($53.28/bbl);
• 2022 free funds flow totalled $161.9 million, prior to working capital adjustments and debt service, and after $94.2 million in total capital expenditures.  This equates to a 38% free funds flow yield using the December 31, 2022 market capitalization and was approximately $33.66/bbl;   
• Announced in September 2022, Messrs. Luis Carranza and Jon Harris were elected as directors for the Company following the retirement of Messrs. Gary Guidry and Ryan Ellson; and,
• Exited 2022 with approximately $120 million in cash ($15.6 million restricted) and a $74 million net surplus on the balance sheet allowing for full bond repayment subsequent to December 31, 2022.

Selected Q4 2022 and 2022 Financial and Operational Highlights

1. Approximately 71% of sales in 2022 were through the Brazilian route vs 27% in 2021.
2. Royalties in Q3 and Q4 2022 include the impact of the 2.5% community social trust retroactive to the beginning of 2022.
3. Netback per barrel (“bbl”) does 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.
4. Adjusted EBITDA is Net Operating Income less G&A and plus/minus realized derivative impacts. See “Selected Financial Measures” section.
5. Market capitalization for 2022 and 2021 assume share prices of $0.50 and $0.33, respectively.
6. Free funds flow is defined as adjusted EBITDA less capital expenditures.
7. Includes restricted cash balances.
8. Net Surplus/Debt = Total cash + all trade and VAT receivables + short and long term net derivative balances – total current liabilities – long term debt – non current lease liabilities – deferred tax – other long term obligations.

Selected Q4 2022 and FY 2022 Financial and Operating Highlights
Production and sales.  Production and sales for the quarter averaged 10,374 and 10,420 bopd respectively.  Production was significantly constrained during October and November 2022 due to low river levels and a river blockade, however, the Company was able to produce an average of 20,766 bopd during the last two weeks in December once these two issues were resolved which allowed quarterly production to average above 10,000 bopd.

Net Revenue profile.  Oil revenue in Q4 2022, net of tariffs, fees, and differentials was $63.8 million ($66.51/bbl) compared to Q3 2022 of $84.2 million ($75.07/bbl) and Q4 2021 of $39.2 million ($58.9/bbl).

High margin operational cash flow.  Generated Q4 2022 NOI and Adjusted EBITDA of $48.4 million ($50.51/bbl) and $36.3 million ($37.87/bbl), respectively, compared to $62.3 million ($55.58/bbl) and $84.2 million ($75.10/bbl), respectively, in Q3 2022 and $25.7 million ($38.61/bbl) and $11.9 million ($17.84/bbl), respectively, in Q4 2021.  Net operating income for 2022 represents a 57% margin on contracted gross sales revenue allowing sufficient margin to fund CAPEX, G&A and debt service.

Capital expenditures.  Capital deployed in Q4 2022 totalled $32.0 million, of which approximately 65% was allocated to drilling and completing wells 12H and 13H and commencing drilling on the Company’s next water disposal well, 4WD.  For the year ended December 31, 2022, the Company invested a total of $94.2 million in capital expenditures, a $12.1 million (15%) increase from 2021, driving a 36% increase in year-over-year production.

Substantial Net income.  PetroTal posted Q4 2022 net income of $37.2 million, making Q4 2022 the 12th quarter in a row with positive net income.  Net income for the year ended 2022 was $188.5 million ($0.22/share) and approximately 44% of PetroTal’s exit 2022 market capitalization.

Solid balance sheet metrics allowing flexible capital allocation.  Year-end 2022 short and long term debt was $81.4 million including accrued interest payable generating an exit debt to 2022 adjusted EBITDA ratio of 0.3x.  Including working capital and cash, the Company exited 2022 with a net surplus of $74.2 million or approximately 17% of the Company’s market capitalization at year-end 2022.

Net derivative asset balance.  The total net derivative asset on the balance sheet as at December 31, 2022 was $20.4 million, an increase of $16.8 million from Q3 2022, driven by mark-to-market changes in the value of oil in the Northern Peruvian Oil Pipeline (“ONP”).  As at December 31, 2022 approximately 2.4 million barrels remained in the ONP with an average cost base of approximately $70/bbl.

Petroperu payment schedule finalized to reduce receivable balances.  During Q4 2022, PetroTal and Petroperu finalized a repayment agreement for the $64 million in true-up revenue owed to the Company by Petroperu from a July 2022 oil export of 720,000 barrels.  As at March 1, 2023 the Company has received nearly $27 million (40%) in accordance with the scheduled payments.  

Robust production from wells 13H and 12H. Well 13H was drilled and completed in late Q3/early Q4 2022 and generated an initial peak production rate of 8,000 bopd during its first week of production.  The drilling team encountered the target formation approximately three meters higher than prognosis which positively impacted 2022 year-end reserves and oil-in-place estimates.  Well 12H was completed and tested around December 16, 2022, however due to export constraints the well’s pump was not activated to constrain higher production rates until mid Q1 2023. 

Financial and Operating Highlights Subsequent to December 31, 2022
Continuous development to increase production. Drilling commencement of drilling 14H began on February 8, 2023 following the successful drilling and coring of the Company’s third water disposal well on January 29, 2023.  Well 14H will be the longest horizontal well ever drilled in Peru with a total measured depth of around 5,135 meters. The well took 38 days to drill and encountered excellent Vivian sands with over 840 meters of net pay. Available production capacity is essential for allowing the Company to ramp up production quickly when additional sales capacity become available.

Full repayment of bonds. On February 15, 2023, the Company made the regularly scheduled payment to bondholders totaling $25 million, plus accrued interest. In addition, on March 24, 2023, PetroTal fulfilled its promise to shareholders and repaid the remaining $55 million of bonds, plus $3 million of accrued interest and prepayment fees, thereby allowing for shareholder return commencement. 

Production resumes at over 20,000 bopd from barge travel normalization.  Low river levels late in 2022 caused an overweighting of available barges to the field in late December 2022 and early 2023. During January and February 2023, the Company was only able to produce approximately 7,600 bopd and 8,000 bopd, respectively. Late in February 2023, the Company was able to ramp up production and will now produce and sell into an evenly distributed and expanded barge fleet chain for the remainder of the year.  Production from March 1, 2023 until March 29, 2023 has averaged approximately 20,500 bopd.

Well 12H on pump and producing at strong rates.  During Q1 2023, well 12H was put on pump and has averaged approximately 5,200 bopd since it was put on pump the last week of February, following the field’s type curve for horizontal wells. This drilling location has increased the probability for additional drilling locations to the south of well 12H and 13H.  

Return of capital focused 2023 budget. On January 16, 2023, PetroTal announced a $125 million fully funded capital program that targets average production between 14,000 and 15,000 bopd in 2023 with possible river level upside allowing 17,000 bopd in the second half 2023.  Under base case production guidance, EBITDA is projected to be $220 million using an $84/bbl average 2022 Brent oil price. This generates after-tax free funds flow of $55 million, strengthening total accessible cash in 2023 to $241 million prior to debt service. 

TSX-V award winner and TSX graduation. PetroTal was recognized as a top TSX Venture exchange performer for 2022 ranking 4th in share performance and market capitalization size in the energy sector. On February 16, 2023, PetroTal graduated to the TSX under the same trading symbol “TAL”.

2.5% community social trust approved into Supreme Decree. On March 9, 2023, the Company announced the publication of the Supreme Decree signed by Peru’s President authorizing Perupetro to execute the amendment incorporating the 2.5% Community Social Trust Fund into the Block 95 License Contract. Bylaw approvals for the trust are expected to occur by the end of April 2023, at which time the amendment to the License Contract shall be executed.

Barging fleet expanded. The Company has expanded its gross contracted barging fleet by over 25% to 1.5 million barrels from the previous capacity of 1.2 million. By increasing the fleet export capacity, the Company will be better able to mitigate situations where barge carrying capacity is limited and/or slow moving. The Company anticipates selling approximately 640,000 barrels of oil in March 2023, mostly through the Brazil export route, and expects deliveries of 550,000 barrels in April 2023, under normalized river conditions. March would then be the first month in PetroTal’s history that 600,000 barrels of oil are sold via Brazil, which was an initial goal when the first 140,000 barrel Brazilian export was completed in December 2020. Now the Company is committed to replicating this on a consistent basis.  

New working capital credit line secured.  PetroTal has successfully secured a revolving working capital line of credit for approximately $20 million with a Peruvian bank. The working capital line will allow the Company to better manage a stable return of capital program, in conjunction with ensuring cash liquidity.  The revolving working capital line can be drawn and repaid at any time.

Return of Capital Update

PetroTal is now long-term debt free and is excited to announce Board approval of a normal course issuer bid (“NCIB”) share buyback program.  Subject to approval by the Toronto Stock Exchange, the NCIB will allow the Company to purchase up to 10% of PetroTal’s public float, over a period of twelve months, commencing in Q2 2023.   Under the NCIB, common shares may be repurchased on the open market through the facilities of both the TSX and AIM exchanges, in accordance with TSX and AIM regulations.  

In addition, PetroTal is pleased to reinstate a US$0.015 per share quarterly eligible dividend(1) with expected record and payment dates in June 2023.  On an annualized basis, this represents US$0.06/share and an approximate yield of 13.9% based on a trading price of US$0.45/share.  This quarterly cash dividend will be designated as an “eligible dividend” for Canadian income tax purposes.

Petrofac-Do I like orange…

• Petrofac and Hitachi Energy have been awarded a multi-year Framework Agreement by TenneT as it works to expand offshore wind capacity in the Dutch-German North Sea
• The Framework Agreement, which represents the largest in Petrofac’s history, covers six projects. Each project comprises the EPCI of an offshore HVDC transmission station, onshore converter station and associated infrastructure
• Each project will be executed under a standalone contract valued at over 2 billion euros, split approximately equally between Petrofac’s and Hitachi Energy’s scopes. The first of these contracts has been awarded alongside the Framework

Petrofac, a leading international service provider to the energy industry, and Hitachi Energy, a global technology leader, have been selected by TenneT, the Dutch-German Transmission System Operator, to supply multiple offshore platforms and onshore converter stations to accelerate the integration of bulk renewables into European power grids.

Petrofac and Hitachi Energy were awarded the multi-year Framework Agreement as part of TenneT’s ambitious 2 gigawatt1 (2GW) high voltage direct current (HVDC) offshore wind programme.

The agreement includes an initial commitment to deploy six record-breaking renewable integration systems, five of which will connect offshore wind farms to the Dutch grid and the sixth to the German grid. Each of these connection systems has a capacity of 2GW and a voltage level of 525 kilovolt – a world-first for offshore wind.

The landmark Framework Agreement represents the largest in Petrofac’s history. It enables Petrofac and Hitachi Energy to plan in advance, secure the required resources and yard space, as well as capturing synergies between successive projects to meet in-service dates.

Petrofac will undertake the Engineering, Procurement, Construction and Installation (EPCI) of the offshore platforms and elements of the onshore converter stations. Hitachi Energy will supply its HVDC Light® converter stations, which convert AC to DC power offshore and DC to AC onshore.

The first contract under the Framework, for the Ijmuiden Ver Alpha project, was awarded with immediate effect. The second, Nederwiek 1, is expected to be awarded later in the year. The Framework also includes projects Doordewind 1, Doordewind 2, Nederwiek 3 and LanWin5, expected to be awarded over a 2024 – 2026 timeframe.

Sami Iskander, Petrofac’s Group Chief Executive, said:
“Today’s announcement represents an exciting next step in Petrofac and Hitachi Energy’s collaboration. We have already secured key resource and the yard capacity required to expedite the first two projects in TenneT’s ground-breaking programme. By combining Petrofac’s industry-leading EPCI expertise and Hitachi Energy’s well proven technology, we look forward to supporting TenneT to connect larger, more effective wind farms to deliver affordable clean energy for millions of European homes.”

Tareq Kawash, who takes over from Sami Iskander as Petrofac’s Group Chief Executive on 1 April, added:
“Today’s award demonstrates the significant new growth horizon presented by the Energy Transition, and the role companies like Petrofac will play. I will be very proud to support Petrofac’s collaboration with Hitachi Energy and delivery of our role on TenneT’s 2GW programme over the coming years.”

Niklas Persson, Managing Director  at Hitachi Energy’s Grid Integration business said:
“This innovative business model will set the course for the integration of a huge amount of offshore wind power and gives visibility of the future.  In fact, we are already hiring to expand our global delivery capacity and effectively fulfill these and other orders. We’re proud to be part of this journey and, along with our partner Petrofac, we are setting the benchmark for deploying offshore HVDC technology at scale and with speed.”

Marco Kuijpers, Director Large Projects Offshore TenneT said: 
“The new long term approach goes hand in hand with a fundamental change in values towards a strong partnership. This approach enables both sides with more flexibility, technological progress, and planning security. This benefits all parties and secures employment, growth, and the strengthening of supply chains. We can already see that our partners invest in extra resources and facilities.”

Petrofac and Hitachi Energy began working together in June 2022, to provide joint grid integration and associated infrastructure solutions to support TenneT’s 2GW Programme2.

In the same year, Germany, the Netherlands, Denmark and Belgium agreed to install at least 65 gigawatts of offshore wind energy combined by 2030, as announced with the inter-governmental Esbjerg Declaration3. At 40 gigawatts, almost two-thirds of this capacity is accounted for by TenneT, with 20 gigawatts each in the German and Dutch North Sea sectors.

For someone who went a bit early on PFC late last year this has more than saved my bacon, I had written about how the PFC order book should gain in a number of key areas and wind farms is one, we have clambered over enough giant structures not to make it pay. 

With results due next month and currently in closed period there won’t be much to add until then, in the meantime I’m staying positive about Petrofac. 

Trinity Exploration & Production

Trinity has announced some key operational updates.

ABM-151 Onstream
The ABM-151 well in the Brighton Marine block, offshore the West Coast of Trinidad, was returned to production on 21 March 2023 following an extensive refurbishment of surface facilities and the installation of remote surveillance technology.  Trinity has a 100% interest in the Brighton Marine licence.

Trinity anticipates steady-state production from ABM-151 in the range of 60-110 bopd.  Production has gradually increased since the well restart and has flowed at rates over 200 bopd on a 10/64″ choke with 0% water cut.  The well will be managed closely in the coming weeks to achieve stabilised production rates within the target guidance and will further benefit from the SCADA automation system the Company has installed.

Jacobin Well Update
Wellsite preparation for the onshore deep Jacobin well is underway, with the well expected to spud in late April, in line with previous guidance.  Trinity has a 100% interest in the Palo Seco area sub-licences, where nine deeper prospects have already been mapped.

The Jacobin well has been designed to test an extensive and lightly-drilled Miocene age deeper turbidite play across the prolific southern onshore basin and will provide the Company with critical new data on this extensive play and the wider Palo Seco acreage.

The well objective is a structural prospect defined on 3D seismic.  The well will target mean oil in-place volume of 5.7 million barrels and an upside (P10) case of over 10 million barrels in-place.

Onshore Bid Round Update
On 20 March 2023 Trinity gave its Technical Presentation on the Company’s bid for the Buenos Ayres block in the 2022 Onshore and Nearshore Competitive Bid Round to the Government of Trinidad and Tobago’s Ministry of Energy and Energy Industries (“MEEI”).

Buenos Ayres is located west of Trinity’s existing Palo Seco production sub-licences – Blocks WD-5/6, WD-2 and PS-4.

The MEEI is expected to announce awards of licences in the bid round during April 2023.

Jeremy Bridglalsingh, Chief Executive Officer of Trinity, commented:
“I am delighted that we have ABM-151 back in production.  We have been looking at ways to boost production across our asset base and identified ABM-151 as a well where we could achieve quick, effective results.  ABM-151’s initial performance underlines the potential of our West Coast assets, where we have a number of infill and appraisal opportunities to mature as we look to increase production across the asset base.

The Jacobin well is an important catalyst for Trinity, significant in itself but also the first part of an extensive play where we have mapped multiple further independent targets across our existing, relatively mature, onshore acreage as well as having further relevance with respect to the Buenos Ayres block which we have bid for in the onshore bid round.”

It’s still pretty quiet over at Trinity, the best news is that the ABM-151 well in the Brighton Marine block, offshore the West Coast of Trinidad, was returned to production on 21 March 2023 and it seems that the work done has increased production modestly. 

Apart from that the Jacobin well has yet to spud and of course Trinity are involved in the current bid round.

IGas Energy

Commenting today Chris Hopkinson, Interim Executive Chairman, said:
“The production drive we initiated in October last year proved that we can overcome technical and operational challenges and I am delighted that we continue to maintain the momentum into the new financial year.

The higher oil and gas prices have been a welcome boost to revenue and cash generation giving us greater financial flexibility and enabling us to repay debt.   However, we believe now is the right time, given the prevailing price environment, to focus on driving opportunities for production, that pay back in a short time frame, and to that end we will seek to finance these near-term projects.  

It is also critical that we maximise the value of our oil and gas assets to facilitate a “just transition” to a renewable energy future through the growth of our geothermal heat business. Momentum is building in the geothermal business and we look forward to achieving financial close for the Stoke-on-Trent geothermal project and moving into the execution phase of that project during the year.”   

Things are changing over at IGas big time, someone has been to business school and the strategy has changed, to be renamed Star Energy to get rid of the shale fraccing baggage,the company is transitioning to become a geothermal company. ‘Energy security through decarbonisation’ is the slogan in the IGas rebranding exercise…

In the meantime the company is apparently ‘buzzing’ as the board has decided to fund the portfolio of existing projects which at current prices pay back in next to no time and should substantially increase production. That number was somewhat disappointing last year, just missing guidance at 1,898 b/d the board have settled on a hardly challenging 2,000 b/d for this year. 

Clearly the board think that the short term investment in the portfolio will carry the company over until geothermal delivers the goods, they have some 35 projects from a number of different users ranging from the public sector to commercial and corporate clients. 

Financial Performance

* Adjusted EBITDA, Net Debt (borrowings less cash and cash equivalents excluding capitalised fees) and Underlying Operating Profit are used by the Group, alongside IFRS measures for both internal performance analysis and to help shareholders, lenders and other users of the Annual Report to better understand the Group’s performance in the period in comparison to previous periods and to industry peers

Corporate and Financial Summary

• Higher operating cash flow resulted in a significant reduction in the Group’s net debt to £6.1 million. Cash balances as at 31 December 2022 were £3.1 million
• The Group made a loss after tax of £11.8 million. This was after deducting a £30.0 million impairment of our shale assets following the reimposition of the moratorium on hydraulic fracturing
• Net cash capex of £7.9 million in 2022 primarily on our conventional assets 
• Successful RBL redetermination confirming $17.0 million (£14.0 million) of debt capacity
• We remain focused on maintaining a strong balance sheet and funding to support our strategy. We will continue to assess funding opportunities to optimise our capital structure and manage our debt facilities effectively
• 60,000 bbls hedged for H1 23 at an average swap price of $94.9/bbl (we are no longer required to hedge under the terms of the RBL)
• Energy Profit Levy charge for 2022 of £nil
• Ring fence tax losses at 31 December 2022 were c.£260 million
• As the Company has been reshaping its strategic direction to reflect the transition to a lower carbon economy, the Board is proposing a change in the Company’s name to Star Energy Group PLC (subject to shareholder approval at the AGM in June 2023)

Operational Performance

• Restructuring and reorganisation of the business to enable improved strategic planning and more efficient decision making
• Net production, averaged 1,898 boepd for the year, heavily impacted in the first half by equipment failure caused by supply chain issues, which was subsequently resolved
• A production drive was initiated in October leading to a strong recovery in H2 resulting in peak production (averaged across 5 days) of 2,432 boepd and December production averaged 2,221 boepd (net to IGas)
• Reserves and Resources updated CPR values 1P NPV10 of $144 million (2021: $139 million): 2P NPV10 of $215 million (2021: $190 million)
• Planning permission submitted and validated for Glentworth Phase I – potential for additional 200 bbls/d
• The drilling of a new well in Corringham is planned for H2 2023 with both planning and permitting in place, which, if successful, is anticipated to add 110 bbls/d peak production
• Awaiting imminent outcome of the Green Heat Network Fund grant application for Stoke-on-Trent geothermal project
• We anticipate notification as to our success in the five NHS tenders through the Carbon and Energy Fund in Q2 2023

Outlook

• We anticipate net production of c.2,000 boepd and operating costs of c.$41/boe (assuming an average exchange rate of £1:$1.23) in 2023
• 2023 abandonment costs of c.£6.5 million as we ramp up the abandonment and restoration of old and uneconomic fields, in line with our licence obligations and to focus on profitable fields.
• In the process of purchasing a rig as part of setting up a dedicated abandonment division
• We expect cash capex of £15.3m in 2023
• This includes £5.9 million for near-term incremental projects to generate c.150-170 boepd and £4.0 million to develop the Bletchingley gas-to-wire project which is expected to generate circa 47 GWh of power from late 2024/early 2025, subject to financing, and £1.0 million to progress developments at Singleton and Bletchingley
• The remaining capex will be spent on the maintenance and optimisation of our existing conventional sites

 KeyFacts Energy Industry Directory: Malcy's Blog