WTI (Dec) $68.43 +31c, Brent (Jan) $72.28 +39c, Diff -$3.85 +8c
USNG (Dec) $2.99 +8c, UKNG (Dec) 112.53p +1.77p, TTF (Dec) €45.665 +€2.41

Oil price

Oil is up today as the market waits for the EIA inventory stats, a day late for Veterans Day, the API numbers last night were mixed, a smaller draw than expected but still down 777/- barrels. Stocks at Cushing drew 1.859m including a small add to the SPR. 

The STEO warned that India may become the ‘new China’ something I have been touting for a long time.

PetroTal Corp

 PetroTal has reported its operating and financial results for the three and nine months ended September 30, 2024.

Selected financial and operational information is outlined below and should be read in conjunction with the Company’s unaudited consolidated financial statements and management’s discussion and analysis (“MD&A”) for the three and nine months ended September 30, 2024, which are available on SEDAR+ at www.sedarplus.ca and on the Company’s website at www.PetroTal‐Corp.com. All amounts herein are in United States dollars unless otherwise stated.

Selected Q3 2024 Highlights

• Average Q3 2024 sales and production of 14,760 and 15,203 barrels (“bbls”) of oil per day (“bopd”), respectively;
• Despite record low river levels on PetroTal’s primary export route, production volumes were 39% higher than the same period last year (10,909 bopd) and 17% ahead of previous Q3 guidance (13,000 bopd);
• Generated Q3 2024 EBITDA(1) and free funds flow(1) of $47.5 million ($35.00/bbl) and $6.5 million ($4.82/bbl), respectively;
• Capital expenditures (“Capex”) totaled $43.0 million in Q3 2024, primarily associated with the drilling of wells 5WD and 20H;
• Exited Q3 2024 with $133 million in total cash ($121 million unrestricted), an increase of $20 million compared to the same period last year;
• Ended the quarter with a net surplus of $10.1 million, compared to $50.3 million at the end of the prior quarter, and $86.5 million at the end of Q3 2023. The decline in net surplus is mainly due to the impact of falling oil prices on a long-term, unrealized derivative liability, as well as to working capital adjustments associated with the Company’s ongoing capital program;
• Successfully drilled two new wells in the quarter, including one water disposal well and one production well. The 20H well has produced an average of 4,209 bopd over the last 14 days, as Bretaña field production and exports have returned to capacity;
• For the first time at Bretaña, PetroTal drilled and tested a lateral into the Upper Vivian sandstone (VS1). The brief production test of this zone in the 20H well flowed 320 bopd, potentially setting the stage for incremental reserve additions at year-end 2024;
• Q3 2024 net income totaled $7.2 million ($0.01/share), representing the 19th straight quarter in which PetroTal has returned net income profits; and,
• Paid total dividends of $0.015/share and repurchased 1.0 million common shares in Q3 2024, representing approximately $14.3 million of total capital returned to shareholders (approximately 3.5% of September 30, 2024 market capitalization).

(1)      Non-GAAP measure that does not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures presented by other entities.

Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented:
“The third quarter is typically the most challenging period of the year for PetroTal, due to seasonal declines in river levels which impact our ability to export crude oil from the Bretaña field. With that in mind, I am proud of the results our team has delivered this quarter. Although production declined relative to the prior quarter, we increased output by 39% compared to the same period last year and our YTD production is now tracking 23% higher than the first nine months of 2023, all while the Company is building cash and returning more than $51 million to shareholders through dividends and buybacks.

“Looking ahead to 2025, PetroTal is well prepared to handle a period of lower oil prices. We have no debt and a stable, high-margin production base. As planned, our drilling program at Bretaña is pausing in Q1 2025, while we import a new, modern drilling rig to Peru. The new drilling rig is expected to drive material cost savings, while allowing us to control the pace of development, giving us a higher degree of flexibility to respond to changes in oil pricing as necessary. We look forward to providing detailed guidance on our 2025 budget and operational program in January.”

Whilst this was a ‘typical’ 3rd quarter, ie one with lower river levels, PetroTal are getting better at dealing with the problem and with ebitda of $47.5m giving net income of $7.2m it was a good period. The output being up 39% y/y is mighty impressive and YTD is 23% on last year and indeed up on previous guidance.

PetroTal successfully drilled two new wells in the quarter, including one water disposal well and one production well. The 20H well has produced an average of 4,209 bopd over the last 14 days, as Bretaña field production and exports have returned to capacity.

PetroTal continues to be amongst the best in the sector for returning money to shareholders, Q3 saw dividends of $0.015 per share and bought 1m shares back making a return of some $14.3m, the company yields 13% and add a couple of points for the buy back. There remains a great deal of upside in these shares and in the meantime few companies as good as this have not only income but capital gain to be made.

Selected Financial Highlights

1. Approximately 89% of Q3 2024 sales were through the Brazilian route vs 87% in Q2 2024.
2. Royalties include the impact of the 2.5% community social trust.
3. Non-GAAP (defined below) measure that does not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures presented by other entities. See “Selected Financial Measures” section.
4. Net operating income represents revenues less royalties, operating expenses, and direct transportation.
5. Adjusted EBITDA is net operating income less general and administrative (“G&A”) and plus/minus realized derivative impacts.
6. Market capitalization for Q3 2024, Q2 2024 and Q3 2023 assume share prices of $0.53, $0.56, and $0.45 respectively on the last trading day of the quarter.
7. Free funds flow is defined as adjusted EBITDA less capital expenditures. See “Selected Financial Measures” section.
8. Includes restricted cash balances.
9. Net Surplus (Debt) = Total cash + all trade and net VAT receivables + short and long term net derivative balances – total current liabilities – long term debt – non current lease liabilities – net deferred tax – other long term obligations.

Q3 2024 Financial Variance Summary

• Sales volumes declined by 18% QoQ, due to seasonal patterns in river levels which constrain PetroTal’s ability to export crude oil from the Bretaña field. However, on a YTD basis, sales volumes are tracking 20% above prior year levels;
• Brent oil prices declined by $6.13/bbl in Q3, compared to Q2 2024. However, PetroTal’s realized sale price only declined by $4.70/bbl. Relative to 2023, Brent oil and PetroTal’s realized sale price are essentially unchanged on a YTD basis;
• Operating and transportation expenses increased by $2.89/bbl in Q3 2024, mainly due to barging and logistics costs associated with the pilot shipment of Bretaña crude to the OCP in Ecuador. However, on a YTD basis, operating and transportation costs are essentially unchanged relative to last year;
• Net operating income and EBITDA both fell by approximately $7.00/bbl relative to the prior quarter, due in approximately equal parts to a decline in realized pricing and higher operating costs.
• Net income fell by $16.27/bbl in Q3 2024, mainly due to a large unrealized derivative loss ($21.5 million, or $15.82/bbl) related to the Company’s historical crude oil sales with PetroPeru.

1. See “Selected Financial Measures”.
2. Net operating income represents revenues less royalties, operating expenses, and direct transportation.
3. Free funds flow is defined as adjusted EBITDA less capital expenditures.
4. Net Surplus (Debt) = Total cash + all trade and net VAT receivables + short and long term net derivative balances – total current liabilities – long term debt – non current lease liabilities – net deferred tax – other long term obligations.

Additional Financial and Operating Updates during, and subsequent to September 30, 2024

Current Production

Bretaña field production has averaged 21,136 bopd in the first ten days of November, and 16,400 bopd on a Q4 2024 to-date basis. Supported by the results of its ongoing drilling program, PetroTal was able to respond quickly to rising river levels in mid-October and returned field production to capacity within a matter of days. The Company continues to observe strong production response from recently-drilled wells; the 20H well averaged 4,086 bopd over the last week of October, while wells 18H and 19H averaged 2,589 bopd and 2,774 bopd, respectively. PetroTal is reiterating previous guidance for Q4 2024 production to average approximately 18,500 bopd, on capital spending of $41-$53 million.

2024 Guidance

PetroTal reaffirms guidance for corporate production to average 16,500 to 17,500 bopd in 2024, on total capital spending of $150-175 million. With Brent oil prices averaging approximately $78.00/bbl YTD through October, in-line with the Company’s original budget assumption of $77.00/bbl, 2024 annual EBITDA is still expected to fall within a range of $200-$240 million. 

Drilling Update

As disclosed previously, PetroTal commenced drilling well 21H at Bretaña on September 25, 2024. The well reached Total Depth in early November, and was brought onstream on November 9. The Company will provide an update on initial flow rates once the well has been onstream for at least 30 days. PetroTal will now drill the 22H and 23H locations, before pausing the Bretaña drilling program in Q1/25. Well 21H was drilled on-time and on-budget, at a cost of approximately $14.4 million.

Drilling Rig Acquisition

On October 11, 2024, PetroTal executed an agreement to acquire a drilling rig from a Houston-based equipment company. The purchase of the rig was financed through a lease agreement with a Peruvian bank, for a term of 36 months at a payment of approximately $0.5 million per month. PetroTal intends to import the rig to Peru in Q1 2025, and expects to bear approximately $3.0 million in one-time costs associated with the transportation and commissioning of the rig. The new drilling rig is expected to drive several key benefits for PetroTal, including immediate savings on day rates and improved uptime, while retaining more flexibility over its drilling program.

Erosion Control Project

Preparation for the erosion control project is ongoing. On October 10, 2024, PetroTal agreed to contract terms with its construction consortium, which were subsequently approved by the Company’s Board of Directors on October 25. The key details of the project are consistent with PetroTal’s existing public disclosure; the Company intends to invest $65-$75 million in erosion control over the next 18 months, with most of the cash impact to be felt in 2025. In total, it is expected that approximately 60-65% of the project costs will be allocated to opex, while 35-40% will be allocated to capex. PetroTal completed the advance purchase of steel components for the erosion control project in Q3 2024, at a cost of $7.3 million; these components have been included in inventory as of September 30, 2024.

Cash and Liquidity Update

PetroTal ended Q3 2024 with a total cash position of approximately $133 million, of which $121 million was unrestricted. This compares to total cash of $96 million at the end of Q2 2024, and $113 million at the same time last year. Net Surplus, a non-IFRS measure which PetroTal uses to describe its liquidity position net of working capital and various non-current liabilities, declined to $10.1 million at the end of Q3 2024 (from $50.3 million at the end of Q2 2024). The quarter-over-quarter decline was due to an unrealized change in the value of PetroTal’s embedded derivative liability, associated with the Company’s historical sales agreement with PetroPeru, and to other working capital adjustments. The change in value of the derivative liability was mainly due to a decline in forward oil prices. PetroTal still has 1.9 million barrels of pending crude sales with PetroPeru, of which 0.4 million barrels are expected to occur in 2025, and the Company will continue to adjust the value of this derivative liability at the end of each fiscal quarter.

During the quarter, PetroTal obtained two lines of credit with Peruvian banks, totaling $30 million. The interest rates are determined by the prevailing market rate at the time of borrowing, and the lines of credit have payment terms of 120-180 days. PetroTal now has total credit capacity of $77 million, which is completely undrawn at the time of this report.

As disclosed previously, PetroTal entered into a hedge agreement during Q3 2024, for an average of 172,000 barrels per month through August 2025. The costless collars have a Brent floor price of $65.00/bbl and a ceiling of $84.25/bbl, with a cap of $104.25/bbl. Subsequent to the end of the quarter, the Company executed hedges on an additional 570,000 barrels, at the same terms as the initial agreement. PetroTal is now hedged on approximately 50% of its forecast crude oil sales through January 2025, and approximately 25% of its oil sales through August 2025.

Share Buyback Plan Update

PetroTal’s updated liquidity strategy prioritizes dividend sustainability, the company’s ongoing development program, and erosion control working capital requirements. In Q3 2024, the Company set additional constraints on the share buyback program that better align daily buyback execution with lower share prices. As a result, the volume of buybacks decreased compared to previous quarters. The Company will continue to monitor buyback levels and will operate in the quarterly approved bandwidths announced in May 2024.

Q3 2024 dividend declaration

A cash dividend of USD$0.015 per common share has been declared to be paid in Q4 2024. This represents a 13% annualized yield based on the current share price. The dividend will be paid according to the following timetable:

• Ex dividend date: November 28, 2024
• Record date: November 29, 2024
• Payment date: December 13, 2024

The dividend is an eligible dividend for the purposes of the Income Tax Act (Canada) and investors should note that the excess liquidity sweep portion of all future dividends may be subject to fluctuations up or down in accordance with the Company’s return of capital policy. Shareholders outside of Canada should contact their respective brokers or registrar agents for the appropriate tax election forms regarding this dividend.

Corporate Presentation Update

The Company has updated its Corporate Presentation, which is available for download or viewing at www.petrotalcorp.com.                      

Q3 2024 Webcast Link for November 14, 2024

PetroTal will host a webcast for its Q3 2024 results on November 14, 2024 at 9am CT (Houston) and 3pm BST (London). Please see the link below to register.

https://brrmedia.news/PTAL_Q3_24

Zephyr Energy

Zephyr has provided an update on operations on the State 36-2R LNW-CC well  at the Company’s flagship project in the Paradox Basin, Utah, U.S.  

Preparations for the commencement of drilling operations to extend the lateral on the well (the “extended lateral”) are at an advanced state.  All regulatory approvals are in place for the planned drilling operation, detailed well planning has been completed and equipment procurement is underway.  A selection process for service companies (including drilling rig providers) has also commenced and is at an advanced phase.

Surface operations on the pad will begin as soon as possible, with the Company expecting full drilling operations to commence early in the first quarter of 2025 (subject to rig availability and weather conditions). 

The existing well was drilled to 10,200 feet, including 130 feet of completed reservoir interval in the short horizontal section of the well.  The extended lateral will be drilled horizontally from the existing wellbore and is expected to target an additional 5,500 feet of the Cane Creek reservoir.  The cost of the operation is expected to be circa US$7 million, a total which includes surface preparation, the drilling of the extended lateral, acidisation completion and production testing.

In conjunction with operational planning, and further to Zephyr’s announcement on 10 October 2024 regarding the funding Letter of Intent, the Company is pleased to confirm that the funding process for the extended lateral (the “proposed funding”) continues to progress in line with expectations.  This asset level investment, from an experienced U.S. based industry investor (the “investor”), would fund 100% of the expected costs required to drill, complete and test the extended lateral, and the Company expects to sign full binding documentation in the coming weeks.  No Company equity or warrants will be issued as part of the transaction and the investor will not receive any future interest or option in the Paradox project other than the working interest in the well.

Colin Harrington, Zephyr’s Chief Executive, said: 
“We are excited to be making material progress towards recommencing drilling operations on the well, and we believe that the extended lateral, combined with an effective acidisation completion, will deliver a large and highly productive well. 

“In parallel with our ongoing operational work, the proposed funding is progressing well and we expect to complete binding documentation in the coming weeks. The proposed funding will fully fund the next phase of our operational activity, as outlined above, without any equity dilution at the Company level.

It’s all systems go for the long lateral extension well, the State 36-2R LNW-CC in the Paradox Basin. Under way are the regulatory approvals for the planned drilling operation, detailed well planning has been completed and equipment procurement is underway including for oilfield service companies including the rig provision.

All the finances for the well are in place, as previously advertised so all being well there is no reason to believe a spud in the beginning of next year shouldn’t be on. Given quite how well the acidisation went on the last well, this extended lateral has the genuine ability to be a massive success for Zephyr and open up the paradox basin for once and for all…

Deltic Energy

Deltic has provided the following update in relation to the recent drilling operations at the Selene prospect in the UK Southern North Sea:

Rig Demobilisation and Well Cost Estimates

The Valaris 123 drilling rig was demobilised from the Selene site on 10 November 2024.

Following confirmation of demobilisation, the well Operator has provided an updated cost estimate for the well of USD$48M which is within the USD$49M carry cap pursuant to Deltic’s farm-out arrangements in relation to the 2024 Selene drilling and testing costs. Therefore, Deltic does not expect to have any residual cost exposure to the well drilling costs.

The estimate of well costs will be subject to variation as the Operator receives final invoices from service providers over the coming months. As at 31 October 2024, Deltic had an unaudited cash balance of £1.9M.

Entry to Second Term of the Licence

Following the announcement of the Selene discovery on 31 October 2024, Shell, in its role as licence Operator, has recommended that the Joint Venture (“JV”) enter into the Second Term of Licence P2437 and will now seek to agree a low-cost work programme and timeline with the NSTA to support the maturation of the discovery towards a potential Final Investment Decision (“FID”) in relation to the development of the Selene discovery.

During the Second Term of the licence, the JV will complete the post-well analytical work and the various studies required to finalise a development concept. No further drilling is required prior to FID. Work will also commence on the various environmental studies to support the regulatory permitting and approvals required to progress to development.

Selene Preliminary Development Concept

Deltic has completed its preliminary reservoir modelling, and updated its preferred development concept, based on analysis of the data available from the 48/8b-3Z well. The technical work completed indicates that a potential development consisting of two horizontal wells would be sufficient to drain the majority of the Selene structure, based on the improved reservoir characteristics seen in the 48/8b-3Z well. Deltic’s base case assumption is that a minimum facilities, normally unmanned, installation positioned on Selene will be tied back to the Barque field infrastructure via a c. 20km subsea pipeline.  The Barque-Clipper-Bacton gathering system and onshore gas processing plant has sufficient capacity to accept the gas production from the proposed Selene development.

Deltic will be promoting this potential development scenario with its Joint Venture (“JV”) partners, however ultimately the maturation of the field development plan will be led by the licence Operator and will be subject to further review once the detailed post-well analysis has been completed.

Selene Updated Economic Model

Deltic has updated its internal development success case economic model, based on cost data provided by S&P Global in 2023, for the two well development concept summarised above and in light of recent changes to the UK’s fiscal regime announced in the budget on 30 October 2024.  The results from this update are summarised below:  

*Values are estimates based on Deltic’s own internal economic model and have not been subject to any third party review.

This preliminary economic evaluation indicates that the P50 discovered volume is more than twice the minimum economic field size and in the proposed assumed development scenario, Selene would have a post-tax NPV10, net to Deltic, of $61M (50 pence/share equivalent) which supports Deltic’s decision to support the entry into the second term of Licence P2437 and progress the work required to reach FID. 

Andrew Nunn, CEO, commented:
“I am pleased to report that the Selene discovery well was completed safely and within the carry resulting from the farm-outs to Shell and Dana. Getting JV agreement on moving into the Second Term of the licence is another key milestone on the journey from discovery to development for Selene. It also reflects the high quality nature of Selene’s reservoir and the expectation of a low cost development with enhanced production and economic potential from the asset.

This decision to move into the second term of the licence kicks off an incredibly busy period, as we support the Operator through the various engineering, environmental and regulatory workstreams that need to be pulled together to support a potential Final Investment Decision. The workstreams now in train are an important signal to our investors as you wouldn’t commence this process if you didn’t believe there was a material commercial return at the end it. We look forward to updating the market in due course.”

Further good news from Deltic as the rig demobilises from Selene and Shell has confirmed that costs were within the cap of $49m insuring no further costs for Deltic. With this the consortium moves to the second term of the licence which will mean ‘an incredibly busy period’ as they put together all the data needed for the FID.

As CEO Andrew Nunn points out, doing this work and preparing for FID can mean only one thing, the light of a commercial return is at the end of the tunnel.  Indeed, the preliminary data indicates that the P50 discovered volume is ‘more than twice the minimum economic field size and in the proposed assumed development scenario, Selene would have a post-tax NPV10, net to Deltic, of $61M (50 pence/share equivalent)’.

The shares are up 10% today, it should be masses more than that as a huge amount of value, created just by completing this stage of the process and the taking of initial steps for an actual development means that Deltic is pregnant with value.

How this value is created could be in many ways, but right now and particularly post-FID, Deltic has many funding options and does not include going to the market for equity raising purposes. For example they will be able to negotiate an RBL, could partner with a trading operation for forward gas sales or even farm-down for cash and carry, any of these mean that shareholders will not get diluted for their equity. But at 5p a share it is a minimum of a 10 bagger in anyones money and should go a great deal higher, the upside in Deltic shares is huge.

Petro Matad

Petro Matad has updated on production operations at the Heron-1 well and the well test results from Heron-2 in its Block XX Production Sharing Contract area in eastern Mongolia.

Highlights

• Heron-1 is producing well with maximum deliverability estimated to be similar to or greater than the 821 bopd achieved on drill stem testing in 2019.
• The oil has more associated gas than expected which improves the flow potential but is also causing pressure fluctuations at surface and so production is currently choked back in the 200 to 300 bpd range.
• Production is being trucked to the neighbouring Block XIX TA-1 facilities and stored. The commercial terms of the Cooperation Agreement with Block XIX operator have been agreed and the final wording is being prepared for sign off by MRPAM. Once approved, export paperwork for Block XX crude can be prepared and sales will then commence.
• Heron-2 has been stimulated and tested with oil recovered together with stimulation fluid at a low flow rate. The well is being suspended and the stimulation and pressure data will be reviewed to determine the forward programme.

Heron-1 production

As previously reported, the Heron-1 well was brought onstream on 24 October and it continues to produce oil to surface under natural flow without the need for pumping. The well is producing with higher amounts of associated gas and at higher pressures than are generally observed in the basin giving the well high initial flow potential. Rate tests have achieved flow rates similar to, and in some tests, higher than the maximum 821 barrels of oil per day (bopd) rate recorded during the well testing operations in 2019. Given the high pressures observed at surface, the flow rate is being monitored carefully to ensure that casing and production tubing pressures remain within safety tolerances and production is currently choked back to a range between 200 and 300 bpd. Whilst this is in line with our pre-production aspiration for an initial stabilised rate, the indications of sustained potential for the well to produce at higher rates are under review, to see if modifications at surface can be made to increase the stabilised flow rate.

Regular transfer of oil to the TA-1 production facilities in Block XIX is ongoing. Meanwhile, all the commercial terms have now been agreed and the final wording of the Cooperation Agreement is being prepared to include details of exactly how the produced volumes will be offloaded, measured and confirmed by the relevant parties. Once agreed with the Block XIX operator the Cooperation Agreement will be presented to the industry regulator, the Mineral Resources and Petroleum Authority of Mongolia (MRPAM) for their approval. The Company is pushing to expedite these final steps after which export paperwork will be prepared and sales of Block XX oil to the buyer in China will commence. In the meantime, large storage capacity is available in Block XIX so Block XX production can continue uninterrupted.

Heron-2 testing

Heron-2 well testing operations commenced on 25 October following completion of a stimulation programme. Seven days were subsequently lost after the test rig suffered a major engine problem but repairs were completed and operations resumed. By end of the test, the well was producing a mixture of oil and what is interpreted to be stimulation fluids with productive potential estimated to be around 30 bpd. This is significantly lower than the rates observed in Heron-1 although it is in line with flow rates reported from some other wells in the basin. Pressure data recorded during the test and the details of the stimulation operation will be reviewed to determine if the flow rate is an indication of low reservoir permeability or some other down-hole issue. Heron-2 is now being suspended and once the data evaluation is complete, the forward programme for the well will be determined.

Mike Buck, CEO of Petro Matad, said:
“We are very pleased with the performance of the Heron-1 well so far and we are encouraged that higher than expected stabilised flow rates may be achievable. We are looking into this as a matter of some urgency, although if surface modifications are needed, these will likely have to wait until after the winter operational shut down. The transfer of production to Block XIX is settling into a routine and we are pushing to be able to export and sell Block XX crude as soon as possible.

The Heron-2 well testing has not achieved the flow rates we were hoping for given the enthusiasm with which Heron-1 produces, but the presence and recovery of oil is encouraging and we have some work ahead to understand the outcome so far and determine the forward programme for the well. This work will be done over the next few months as we finalise our operational programme for 2025.”

Just as it looked as if the two Herons could get up to high and attractive rates of production a number of problems have appeared and at Heron-1 that is higher levels of associated gas so the well is choked back to 200-300 b/d against the 800+ that might be available.

Production is being trucked to the neighbouring Block XIX TA-1 facilities and stored, whilst not being sold yet, currently due to sign-off by MRPAM on what seems like a regular problem in Mongolia. All it needs to be sold is a signature and of course…the paperwork…

Heron-2 has been suspended having only achieved some 20 b/d against capacity of nearer 500 b/d, drilling fluids have returned and so the lack of hydrocarbons may indicate a down hole problem or reservoir permeability, all will be checked. Whatever happens the work won’t take place in the winter so they will have plenty of time to analyse all the data.

Original article   l   KeyFacts Energy Industry Directory: Malcy's Blog