WTI $83.82 +$1.70, Brent $$86.06 +$1.59, Diff -$2.24 -11c, NG $4.26 -1c, UKNG 210.0p -18.12p

Oil price

There is little I can add to my position on crude right now, a combination of factors are acting together to create a strong market for oil not least the easing of the pandemic, cold weather in the USA, Opec+ not filling its quotas and demand lifting stock drawdowns.

Today is Martin Luther King Day, a holiday in the US and oil will trade in some markets but expect varying prices. Interestingly the Baker Hughes rig count on Friday showed the first decent rise for a while, in oil up 11 to 492 units, I would wait for a week or two to see if there is a pattern emerging.

PetroTal Corp

PetroTal has provided the following updates:

Key Highlights

• Q4 2021 production averaged 10,147 bopd, constrained by temporary oil delivery disruptions;
• Oil production for 2021 was 8,966 bopd, up 58% from 5,675 bopd for 2020;
• Wells 9H and 8H continue to perform significantly above internal expectations, with average production rates over the past five days of approximately 8,500 bopd and 6,700 bopd, respectively;
• Production at the field is now again averaging approximately 20,000 bopd since January 12, 2022 with export routes, including the Northern Peruvian Pipeline (the “ONP”), fully functional;
• Well 10H drilling operations continue according to plan with estimated completion in early February 2022;
• Q4 2021 oil deliveries for export via Brazil were approximately 300,000 barrels and are expected to increase to approximately 240,000 barrels per month; and,
• December 31, 2021 total cash of $74.4 million, including $29.5 million of restricted cash.

Q4 Production Update

PetroTal’s production averaged 10,147 bopd in Q4 2021, impacted by unplanned and extended downtime of the ONP from social and protest issues at pump stations 1 and 5. October was the only month in the quarter with largely unrestricted production rates, with November and December having only 16 and five producing days, respectively, where all wells were producing fully. 

As a result of wells 9H and 8H generating large initial production rates in the quarter, PetroTal was still able to average over 10,000 bopd in Q4 2021 and demonstrate quarter on quarter production growth of 7% despite only producing unconstrained for approximately 57% of the period.  Included in Q4 2021, were five days where PetroTal averaged above 20,000 bopd.  

Current field production is again at approximately 20,000 bopd, having produced at that rate for the past five days.  As announced on December 16, 2021, PetroTal had to significantly constrain production, from that date until January 9, 2022, to an average of 5,006 bopd.  This allowed the Company to manage storage capacity and barge availability due to pump station 1 bottlenecks, which have now been alleviated.

Well 10H Update

Drilling of the 10H well progressed according to plan, with its 1,200 meter horizontal section successfully reaching total depth.  Well 10H is the longest horizontal well drilled to date in Peru and completion operations are now underway, with the well expected to be completed in early February 2022. 

Exports via Brazil Expected to Increase in 2022

During Q4 2021, oil deliveries to Brazil were approximately 300,000 barrels with an all-in differential, marketing and transportation cost of approximately $21/bbl.

In December 2021, PetroTal executed a new sales contract to deliver up to 240,000 barrels per month to Brazil, and is currently working to advance the logistics to further increase export volumes by 50%.  Including the current Iquitos Refinery point of sale, the expanded Brazil export route would allow PetroTal to market approximately 13,300 bopd without dependence on the ONP. 

Strong Liquidity Management in Q4 2021

PetroTal continues to manage liquidity exceptionally well despite the route to market headwinds.  PetroTal ended Q4 2021 with $74.4 million in total cash, of which $29.5 million was restricted, including $20 million dedicated to accretive acquisitions.  Ending Q4 2021 cash was higher compared to internal forecast as a result of receiving a $15.8 million revenue true up payment for exported oil at Bayovar.  Accounts receivable and accounts payable at year-end were approximately $0.5 and $54.0 million (11% due after Q1 2022), respectively.  Accounts receivable balances were substantially lower in Q4 2021 due to December 2021 ONP sales disruptions caused by nearby protests.

CPF-2 Commissioned

PetroTal is pleased to announce that CPF-2 has been fully commissioned and is operational, thereby allowing field production capacity of 24,000 bopd, water disposal capacity of 100,000 barrels of water per day and oil storage of 90,000 barrels at the field.

Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented:
“We are excited to start the new year with record production of 20,000 bopd, a solid base for ongoing growth.  PetroTal will continue to manage our business to maximize cash flow and support stable operations for shareholders while always placing safety above all else. 

The Company is very supportive of community efforts and the active dialogue engagement that led to the reopening of pump stations 1 and 5.  Our team has been working hard to find creative sales business solutions so 2022 can be a record year for the Company from cash flow and production perspectives.”

Another exceptional performance from PTAL who have now made further solid progress across the board, the constant rise in production was laudable, up 58% y/y and then some added by the 9H and 8H wells delivering ‘significantly above expectations’. The dream of 20,000 bopd with exports routes fully functional is now a reality and the 10H well is expected to be completed in February 2022.

This of course means that cash at the end of December 2021 was $74.4m which included $29.5m restricted and directors are earmarking $20m for accretive acquisitions. Ending Q4 2021 cash was higher compared to internal forecast ‘as a result of receiving a $15.8 million revenue true up payment for exported oil at Bayovar’. 

Finally more good news, the CPF-2 has been fully commissioned and is operational, thereby allowing field production capacity of 24,000 bopd, water disposal capacity of 100,000 barrels of water per day and oil storage of 90,000 barrels at the field. 

I increased my target price for PTAL to 60p recently and can easily see that happening now with the increased production, well performance and CPF-2 commissioning. At some stage we should see further growth both from organic and non-organic contributions which make PetroTal such a good investment at today’s 27p.

Angus Energy

Angus has announced a Strategic Review, Formal Sale Process Update this morning.

The Company has announce that it has had at least six bona fide approaches to participate in the FSP and/or other indications of interest in a potential offer for either all of the shares of the Company or the Company’s licence interest in the Saltfleetby Gas Field.  In accordance with the Company’s announcement of 6 January, the Company considers it inappropriate to identify the Parties but the Company will engage with and evaluate each expression of interest until a firm proposal can be agreed and announced.

Angus is not a large and complicated group and the Company does not envisage an extended period of time will be necessary for the Parties to complete due diligence, other than that involved in familiarising themselves with the documentation details of the £12m Saltfleetby Gas Field Development Loan Facility (the “Loan”) and associated security arrangements and gas sales hedge.

Consideration of the capital structure of any combination will be of critical importance not just to shareholders, in the instance of a share for share offer, but also to the Loan and Hedge counterparties, each of whom benefit from change of control provisions.  Such provisions require the consent of those counterparties to any change of control if the Loan is not to be immediately refinanced and/or the Hedge accelerated.

Additionally, regulatory guidance, newly restated on 13 January 2022 by the Oil and Gas Authority (“OGA”), lays emphasis on evaluation of the financial resources available to the combined group and interested parties, whether for the Company or its Licence interests, are strongly advised to consult the OGA on this point.

George Lucan, CEO, commented:
“We are pleased with the expressed level of interest in the Company or in its principal asset, and will proceed with our formal sales process with due professionalism, expediency and confidentiality to achieve the best possible result for all of Angus’ shareholders.”

I won’t go into all the reasons that I gave a few days ago when Angus announced the possible sale of the company but looking at the world of oil and gas assets makes me think that there will be plenty of pound notes, or possibly dollars chasing these assets. 

Given the state that the company was in when he assumed control I think that CEO George Lucan and his team have done wonders by firstly seeing the scope for Saltfleetby and by starting the process of possibly monetising the assets.

Reabold/Union Jack

Reabold and Union Jack have announced initial results of analysis of the West Newton Extended Well Test programme carried out in the second half of 2021 by RPS Group  and the results of analysis carried out on fluids produced to surface.

Highlights

• Independent study by RPS Group indicates potential for initial production rates of 35.6 million cubic feet of gas per day (“mmcfd”) (5,900 barrels of oil equivalent per day “boepd”) from a horizontally drilled well situated in the gas zone, based on the data from the West Newton A-2 well
• Study also indicates potential initial production rates of 1,000 barrels of oil per day (“bopd”) from a horizontally drilled well situated in the oil zone, based on well data from West Newton A-2
• Fluid analysis confirms that hydrocarbon liquids recovered to surface are low specific gravity, low viscosity, light oil or condensate, and that gas recovered to surface is good quality with high heat content

Independent Review of West Newton Flow Rate Potential

Following the completion of the West Newton EWT in Q4 2021, the project operator, Rathlin Energy Limited, commissioned RPS, a highly-regarded independent consultant, to produce a review that assessed well productivity potential from the West Newton field, and investigated optimised drilling and well completion methodologies.

The RPS review concluded that the Kirkham Abbey reservoir is likely to deliver substantially higher production rates from horizontal wells compared to vertical wells.  The report also concluded that, based on RPS modelling, most of the acid stimulation carried out during the EWT only interacted with a small section of the perforated intervals due to the permeability contrast across the Kirkham Abbey formation in both wells. This suggests that potential flow rates from wells in the Kirkham Abbey reservoir would benefit from an optimised acid stimulation programme that includes active diversion techniques.

The analysis was based on a comprehensive suite of data provided from operations to date at West Newton, including logs, core data, petrophysical analyses, drilling and completion information, stock tank oil analysis, and other existing third-party reports.

The RPS review modelled potential flow rates from the Kirkham Abbey reservoir, assuming horizontal drilling, similar acid concentrations and diluted volumes per interval as utilised during the EWT operations and an optimised acid-based stimulation and are as follows:

Whilst the well productivity and therefore project economics are significantly optimised through horizontal drilling, the modelling also indicates that optimised acidization should lead to both oil and gas flow from vertical wells.  Therefore, it may be possible to recomplete the existing wells to achieve sustained flow rates, which would further de-risk and help optimise subsequent horizontal drilling.

It should also be noted that the RPS modelling does not take into account any potential contribution to productivity resulting from the natural fracturing that has been identified within the Kirkham Abbey Formation. It is Rathlin management’s belief that natural fracturing is likely to be present within future completion zones, which may further enhance well productivity.

Further evaluation is ongoing to support the economic feasibility of horizontal wells, including an assessment of longer term production rates. A number of additional workstreams and studies are currently underway, and further announcements are expected in due course.

Analysis of Fluids Recovered from the EWT

A number of natural gas and liquid hydrocarbon samples were collected and analysed from both the West Newton A-2 well and the West Newton B-1z well. The natural gas had measured specific gravities of 0.63; a methane content of ca 90 per cent. and an ethane content of ca 4.5 per cent.

The liquid hydrocarbons had measured API gravities between 45.9o and 49o pointing to a very light oil or condensate. The samples also displayed a low viscosity measured at between 0.80 centipoise at 40o C, 0.91 centipoise at 25o C.

Stephen Williams, co-CEO of Reabold, commented:
“We are delighted by the findings so far following completion of the EWT, which demonstrate, as per the RPS Group report, that West Newton could be a significant hydrocarbon producer.

“Following this analysis, we have no doubt that we have a significant resource in place, and crucially the recovery of what we can now confirm to be high quality light oil in addition to good quality gas has further de-risked the project significantly. 

“The data garnered from the operation has allowed the modelling of potential flow rates, independently assessed, for the first time, and the results are extremely exciting. 

“Further work, including lab-based analysis of the core under reservoir conditions, is planned and ongoing, which will further inform optimal future drilling and completion methods at West Newton.  This will feed into our plans for the next phase of activity at the field, including the potential to re-complete the existing wells in order to achieve sustained hydrocarbon flow. We look forward to providing further updates in due course.”

Executive Chairman of Union Jack, David Bramhill, commented: 
“We are encouraged by the RPS review which continues to underline West Newton’s potential as a material hydrocarbon producer.

“This initial analysis confirms the significance of the in-place resource and crucially, has de-risked the project by indicating the potential recovery of what we can now confirm to be high quality light oil, in addition to good quality gas. 

“The mass of data obtained from the operation has allowed the modelling of potential flow rates, independently assessed for the first time. 

“Ultimately, all of the analysis currently being undertaken is aimed at reducing risk and providing the Joint Venture with sufficient data to develop our forward plan for the next phase of activity at West Newton.

“Further work, including lab-based analysis of the core under reservoir conditions is underway, which will further inform optimal future drilling and completion methods at West Newton. 

“We look forward to providing further updates in due course.”

For both companies this is the good news that they and the market had been waiting for some time, indeed the size of the prize at West Newton is still substantial and this work and that which is yet to come clearly demonstrates how big that is. 

With Angus Energy saying today that at least six approaches had been made for their assets it would not surprise me if that number and more were running the calculator over West Newton, it is clearly big enough for a pretty substantial company with a big cheque book wanting to be able to supply energy to UK domestic clients.

Hurricane Energy

Hurricane has provided a trading and operational update ahead of its results for the year ended 31 December 2021. This information is unaudited, and subject to further review and adjustments.

Trading Update

Operations

• Production for the final three months of 2021 averaged 10,000 bopd, within guidance
• Production and oil sales for the year ended 31 December 2021:
• Production: 3.7 MMbbls (average of 10,267 bopd)
• Oil sales: 3.6 MMbbls across seven cargoes
• Aoka Mizu FPSO uptime of 99% during 2021

Key financials for the year ended 31 December 2021:

• Revenue: $239 million (2020: $180 million)
• Average realised oil price: $67/bbl (2020: $35/bbl)
• Year-end total debt: $78.5 million following repurchase of $151.5 million of outstanding Convertible Bonds for cancellation during H2 2021
• Year-end net free cash(1): $50 million
• Year-end net debt(2): $28.5 million

1. Unrestricted cash and cash equivalents, plus current financial trade and other receivables, current oil price derivatives, less current financial trade and other payables.
2. Net free cash less the par value of the outstanding Convertible Bonds (being the total remaining amount repayable on maturity of the Bond in July 2022)

Lancaster Field Operations Update

The following table details production volumes, water cut and minimum flowing bottom hole pressure for the 205/21a-6 (“P6”) well during December 2021.

December 2021 Lancaster Field Data
 

• The 205/21a-7z (“P7z”) well was not on production during December 2021
• Expressed as total water produced divided by total fluid (oil and water) production
• Pressure reported is the monthly minimum from well downhole gauge
• December month average rate impacted by downtime arising from testing and pigging operations

During December, the well gauge pressure reached and declined below bubble point, in line with the previously guided timing of this occurring between late December 2021 and mid-February 2022. No production issues arising from reaching bubble point have been observed to date.

As of 15 January 2022, Lancaster was producing c.9,650 bopd from the P6 well alone with an associated water cut of c.39%.

The next cargo of Lancaster crude is anticipated to be lifted towards the end of January 2022.

Financial Update

As of 31 December 2021, the Company had net free cash(1) of $50 million, compared to the last reported figure of $127 million as of 30 November 2021. There were no liftings of Lancaster crude in December.

During December 2021, $73.5 million in aggregate principal amount of the Company’s $230 million 7.50 per cent. Convertible Bonds due 2022 were repurchased and cancelled by a subsidiary of the Company for a total cash consideration of $70.3 million (including accrued interest). As a result of the repurchases of the Bonds in December 2021, and the $78.0 million tender offer which settled on 15 September 2021, the Company has generated a combined net saving of $29.5 million in debt repayment and interest charges. $78.5 million in aggregate principal amount of the Bonds now remain outstanding, resulting in net debt(2) of $28.5 million as at 31 December 2021.

The Company, in finalising its tax returns for the years ended 2019 and 2020, has made claims for R&D tax credits, including via the surrender of certain of its subsidiaries‘ brought forward tax losses. Should these claims be approved by HMRC, the Company anticipates a cash credit of up to c.$4.5 million to be received during Q2 2022.

The Company believes that net free cash provides a useful measure of liquidity after settling all its immediate creditors and accruals and recovering amounts due and accrued from joint operation activities, outstanding amounts from crude oil sales and after settling any other financial trade payables or receivables. It should be noted that the net free cash is calculated as at the balance sheet date and does not take into account future liabilities that the Company is already committed to but have not yet been accrued. As such, not all of the net free cash would be available for repayment of the remaining outstanding Convertible Bonds at their maturity in July 2022.

Antony Maris, Chief Executive Officer of Hurricane, commented:
“Despite the major challenges faced by Hurricane last year, the team has done a superb job at delivering excellent production performance and high uptime on the FPSO, as well as finding cost savings. All this has been done while at the same time maintaining high levels of HSSE performance, which is always the first priority for the Company.

“Oil prices, while volatile, have been stronger in the second half of the year and, combined with the impact of the bond buybacks, production performance and cost reduction measures, we are optimistic that the ability to repay the bonds in full at maturity is now within reach.

“Given our current prediction of performance and assuming oil prices continue to be within the range experienced over the past month, we believe that post clearing our bond debt Hurricane will have between $8-38 million of net free cash at the end of July 2022. This needs to cover any subsequent working capital requirements until revenue is received from the next lifting. The amount of net free cash will also be reduced by the level of escrowed cash that Bluewater, our FPSO provider, requires as part of any extension deal. We continue to engage with Bluewater and remain optimistic of finding a mutually acceptable deal that will enable the Company to continue production beyond repayment of the bond.

“As such, going forward we are working hard towards ensuring a confident future for Hurricane based upon a sustainable financial platform.”

There is not much that can be said about this that doesnt look like saying I told you so. However I and many others did tell them so and the bond purchases, revenues and cost effectiveness of the FPSO have proved that the shenanigans were right to dismiss those who would have wiped out over 90% of their equity. 

 Right now Hurricane is beginning to look on the bright side of life, proof if any were needed that sometimes the little people know best. 

KeyFacts Energy Industry Directory: Malcy's Blog