Malcy’s Blog – Oil price, Genel, Kistos, Southern, Arrow, Coro, Predator & finally

WTI (May) $73.20 +39c, Brent (May) $78.65 +53c, Diff -$5.45 +14c. 

Author @mgrahamwood

USNG (Apr) $2.03 -5c, UKNG (Apr) 105.33p +3.3p, TTF (Apr) €43.995 +€2.89. 

Oil price

Oil was slightly better yesterday as the Iraqi-Turkey pipeline remained offstream.

Genel Energy

Genel notes that DNO, as operator of the Tawke PSC (Genel 25% working interest), has today issued an update on licence activity.

DNO has started an orderly shutdown of the Tawke and Peshkabir oil fields in the Kurdistan Region of Iraq, four days after it was instructed to temporarily cease deliveries to the Iraq-Turkey Pipeline. Oil production had previously diverted to storage tanks.

The Tawke and Peshkabir fields averaged combined production of 107,000 barrels of oil per day in 2022, representing a quarter of Kurdistan’s total exports. Peshkabir production was halted last night and plans drawn up to conduct deferred maintenance. Tawke production shutdown has started but will take an additional day or so given the much larger numbers of wells spread across some 10 kilometers.

Production from Taq Taq (44% working interest, joint operator) continues to flow into storage, with capacity for approximately three weeks, while there remains storage capacity at Sarta (30% working interest, operator) for several days.

Not much to add to what I said on Monday, the wind down is getting underway by DNO as detailed above and as expected. Both KRG companies I follow have said that firstly it is important to realise that events like this are built into their models and that there is ample scope for continued dividend payments and in the long term a beneficial effect may be achieved by greater cooperation between the KRG and Baghdad on oil policy, either way it’s in nobody’s interest for this situation to continue. 

Kistos

Kistos has provided an update on its drilling activities in the Netherlands and the United Kingdom.

United Kingdom

The Benriach exploration well, located on block 206/05c (Kistos 25%) West of Shetland and operated by TotalEnergies E&P UK, has been spudded by the Transocean Barents. The operator estimates it is targeting P50 prospective resources of 638 Bcf (160 Bcf or 28mmboe net to Kistos). The well is expected to complete in Q3 2023. The dry hole post-tax cost net to Kistos is forecast to be ~£2.5 million as a result of Kistos’ tax paying position and the enhanced investment allowances from the Energy Profits Levy.

Netherlands

After arriving on location at the Q10-A gas field (Kistos 60%) in November 2022, the Valaris 123 rig recently departed after safely completing its work programme.  The results of the campaign were mixed. This was due to mechanical issues arising from utilising the existing well stock rather than reservoir performance issues. The Kistos technical team, with the assistance of external consultants, is undertaking a detailed evaluation of the results and future production enhancement options.

Future work programmes are being considered and could include the drilling of further Zechstein clastics wells in 2024 in combination with development drilling at the Orion oil field. Engineering design work has now been completed to enable the installation of two more risers on the platform, which would allow it to host additional wells. The Orion field continues to progress through the Concept Select Phase, which Kistos is undertaking with the assistance of Rockflow Resources.

Andrew Austin, Kistos’ Executive Chairman, said:

“We are excited that the Benriach well is underway. It is an important milestone for the Company with the potential to add significant reserves. I look forward to updating stakeholders with the results of the well in due course.

I would like to congratulate our team in the Netherlands on the safe completion under difficult weather conditions of the operational work programme. The process of fully evaluating the results of the campaign is ongoing, and will inform the planning of future work programmes, including the potential operational synergies with the Orion oil field development.

Kistos has updated the market on both the UK and Netherlands drilling operations, partially as investors have been looking at marine trackers and in some cases getting the wrong readings. As it is I am very excited by the spud of Benriach which I have been waiting for ages for and could be a big plus for Kistos. Indeed with a combination of tax losses and the Looney tax enhanced investment allowances dry hole costs are just £2.5m.

In the Netherlands the ‘mixed’ campaign is not all bad in my view, whilst operational and mechanical difficulties are to blame rather than any reservoir disappointments, in due course new kit on the platform should mean more wells available.

Going forward I am confident that the outlook for Kistos remains exciting, I know the management team well enough to be able to say that I am sure that following recent choppy markets, for a number of well known reasons, deal flow has been slowed. I would bet that they are still on the acquisition trail but the stormy weather has slowed, rather than knocked off course the M&A activity. 

As a result when I do the quarterly update of the Bucket List in the next few days despite unusual recent performance it will show that if you believe the Kistos story, and I most certainly do, then it will look like the proverbial diamond in the rough and shares should be snapped up at these prices…

Southern Energy

Southern Energy today announced its:

·    2022 Year End Reserves Upgrade:

§ an increase in proved developed producing (“PDP”) reserves of 25% to 6.2 MMboe

§ an increase in total proved (“1P”) reserves of 44% to 14.1 MMboe

§ an increase in total proved plus probable (“2P”) reserves by 31% to 25.5 MMboe in 2022

§ before-tax net present value (“NPV”) of 2P reserves, discounted at 10% (“NPV10”), of $142.5 million (an increase of 61% on year end 2021) 

·    Gwinville Operational Update:

·    Capital Budget Update:

·    Broker Appointments:

Ian Atkinson, President & Chief Executive Officer of Southern, commented:

“Although the drop in natural gas prices has brought us to the decision to moderate our Gwinville capital program, the overall impact of the applied learnings from the 2022 appraisal program have paid off and we are happy with the early results. In the current program we have drilled seven horizontal wells with longer laterals than the original appraisal wells in half the time on a per well basis and proven that the re-interpretation of our 3D seismic has improved our overall ability to stay within the targeted zone. We have positioned ourselves for the inevitable rebound in natural gas prices and look forward to moving equipment and manpower back into the Gwinville field quickly as price recovery occurs to re-initiate our organic growth plans and take advantage of maximising cashflows at the opportune time.”

Gary McMurren, Chief Operating Officer, commented:

“We are excited to report another year of material reserves growth in all major categories for the Company, highlighted by conservative additions to our Gwinville horizontal Selma Chalk inventory following our successful appraisal program in 2022. In our current development program, we will be testing two Lower Selma Chalk and two City Bank horizontal laterals with our modern completion design. The Lower Selma Chalk has only minimal reserve bookings in this year’s report, and we have yet to book any City Bank development reserves, so upon completion of these horizons over the next few months, we expect to continue to add significant and predictable reserves growth in Gwinville for years to come.

This is a lengthy update from Southern Energy which is stuffed full of data and into the bargain there is an updated presentation on the website. Starting with the reserves report the 2P number of 25.5m (20.2m)  is up 31% and I’m sure that talking to the management team today that they could have easily booked more reserves but that the full programme will deliver predictable, more material growth. 

The natural gas price has been remarkably weak in recent months, a combination of US production growth after Covid shut-ins, the delay over Freeport which is now coming back onstream and of course an unseasonably mild winter have all meant that prices have suffered. The company have, in my view wisely, cut the capital programme thus protecting the upside for what seem like inevitably better times. 

As for the recent drilling programme of 7 horizontal wells, 3 were completed and four are DUC’s waiting for a rebound in natural gas prices at which time the company plan on moving equipment and manpower back into the Gwinville field quickly as price recovery occurs.

There is plenty of material in this document and the new presentation that show that recent performance has been highly creditable with last year over 100% of PDP replacement in what was a conservative programme indicating that the company are taking a highly conservative view on both any future bet on natural gas prices whilst protecting the balance sheet. 

In my view this makes the company not only backed by a huge portfolio of high quality assets but also with an astonishing upside potential, the management are taking way the best action at the moment and SOUC remains in the Bucket List. 

The NSAI Report highlights the extensive running room and future development potential of only one of our existing core assets which will deliver long term sustainable free funds flow and organic growth. Further work is expected to unlock additional value for Southern shareholders, with the potential to significantly grow reserves in our portfolio in a short time frame.

With an average operating cost in 2022 of under $0.80/Mcfe, Southern has some of the highest margin natural gas assets in North America, which continues to benefit the business model and provide strong cashflow for the Company.

Gwinville Operational Update

The Company is pleased to summarize the results of the current capital program to date as compared to the 19-3 padsite appraisal program:

Well Name

Zone

Spud to TD (days)

Lateral Length (ft)

% in zone

Frac Stages

Total Proppant (million lbs)

Proppant Loading (lb/ft)

IP30 (MMcf/d)

Historic Appraisal Drilling

19-3 #2

Upper Selma

20.2

3,498

90

41

6.6

1,884

6.5

19-3 #3

Upper Selma

18.5

4,146

50

44

7.0

1,700

3.6

19-3 #4

Upper Selma

22.2

4,623

50

50

8.0

1,650

4.0

Current Drilling Campaign

18-10 #1

City Bank

14.4

5,744

100

50

10.0

1,747

TBD

18-10-#2

Upper Selma

12.0

4,699

50

43

8.6

1,830

3.3

18-10 #3

Upper Selma

11.6

5,091

80

44

9.0

1,771

TBD

14-6 #3

Upper Selma

10.4

5,525

85

Not yet completed

14-6 #4

Lower Selma

9.4

5,521

100

Not yet completed

13-13 #2

Lower Selma

9.3

5,302

96

Not yet completed

13-13 #3

City Bank

12.9

5,118

100

Not yet completed

Gwinville 18-10 Padsite

The Company is pleased to report the initial 30-day production rate (“IP30”) on the first well of the 18-10 pad out of a total of seven wells drilled to date in the capital program. The 18-10 #2 Upper Selma Chalk well recently reached an IP30 of 3.3 MMcf/d, which is similar to the 19-3 #3 and #4 appraisal wells, and below early type curve expectations for these Generation 3 well designs. The well encountered some unpredicted faulting and was drilled with only 50% of that lateral length within the high-grade porosity interval. Although below Generation 3 type curve estimates, the result is representative of a well with an effective lateral length in the high-graded porosity interval of less than 2,600 feet. 

The 18-10 #3 Upper Selma Chalk well achieved approximately 80% of the lateral within the high-grade porosity interval and was completed with a 44-stage stimulation. The Company experienced a mechanical wellbore integrity issue during the completion and plans to perform remedial work on the well and establish production in Q2 or Q3 of this year.

The 18-10 #1 City Bank well was drilled to a lateral length of approximately 5,744 feet with 100% of the lateral drilled in the target interval. The well was successfully stimulated with a 50-stage completion operation and is in early stages of completion flowback currently producing flowback water at 5% of load recovery. Southern does not expect to see peak gas rates until the well has recovered approximately 20% of load fluid based on historically stimulated vertical and Generation 1 horizontal wells in the City Bank reservoir at which time the Company will report on initial production. The Company is encouraged by the early results and looks to add significant net asset value to the reserve books in 2023 as no proven undeveloped or probable locations have been attributed to the City Bank zone to-date.

Gwinville Drilling Efficiencies

As a follow-up to the three well Upper Selma Chalk appraisal program from Q2 2022, which has recovered approximately 55% of upfront capital in less than nine months of production, Southern identified two major technical improvements to be employed on future activity. The re-interpretation of the 3D seismic to provide a higher resolution assessment of the reservoir, coupled with the utilization of a rotary steerable downhole drilling assembly that allows for immediate and more responsive corrections, has resulted in a significant improvement to the lateral length drilled in the high porosity interval and a significant reduction in overall drilling times. Utilizing these changes, Southern has reduced the average time from spud to total depth of these wells from approximately 21 days to between 9-12 days and averaging 80-100% lateral placement in the high-graded porosity interval. The learnings and cost savings achieved early in this program are expected to translate into all future Gwinville drilling.

The Company’s first padsite in the winter program was the 18-10 pad, which has two Upper Selma Chalk laterals and the first City Bank lateral. Next, the rig drilled the 14-06 pad that contained one Upper Selma Chalk lateral, and the first Lower Selma Chalk lateral. The rig has recently finished drilling the 13-13 pad with the second City Bank and Lower Selma Chalk laterals. The drilling rig has been released and the final four laterals will remain as DUCs until natural gas prices are more supportive of capital spending on organic growth. 

Capital Budget Update

In response to the current low natural gas prices and guided by principles focused on full-cycle value creation, Southern plans to moderate the Gwinville organic growth program from the planned capital budget of US$101.0 million announced in November 2022 to approximately US$55.0 million. Under its revised capital plan, Southern will have drilled seven horizontal wells at the Gwinville asset, completed three wells and have four wells remain as DUCs to be brought online in a higher natural gas price environment. These changes to the program at Gwinville will preserve capital, allow Southern the optionality to bring on high volume natural gas production at opportune natural gas prices and retain an inventory of high value development targets.

Year End Reserves Upgrade

Southern is pleased to announce selected highlights of the Company’s year end independent oil and gas reserves evaluation as at December 31, 2022. The NSAI Report was prepared by independent qualified reserves evaluator, Netherland, Sewell and Associates, Inc. (“NSAI”). All currency amounts are in United States dollars (unless otherwise stated) and comparisons refer to December 31, 2021. Financial information contained herein is based on the Company’s unaudited results for the year ended December 31, 2022 and is subject to change. The Company anticipates announcing its fourth quarter and audited year end 2022 financial results and filing an annual information form (“AIF”) for the year ended December 31, 2022, in April 2023.

Highlights:

•        Relative to year-end 2021, and accounting for 2022 production volumes, the NSAI Report states

•       an increase in PDP reserves of 25% to 6.2 MMboe

•       an increase in 1P reserves of 44% to 14.1 MMboe

•       an increase in 2P reserves by 31% to 25.5 MMboe in 2022

•       a reserve life index (“RLI”) of more than 8 years for PDP reserves and 15 years for 2P reserves, based on the 2023 production forecast

•        Successful organic growth and appraisal drilling resulted in strong reserves replacement (relative to 2022 production) in all reserve categories:

•       PDP replacement of 153%

•       1P replacement of 484%

•       2P replacement of 656%

•        At year end 2022, achieved record before-tax NPV10, evaluated using the average forecast pricing of four independent reserve evaluators as at January 1, 2023;

•       PDP: $51.6 million (59% increase on year end 2021)

•       1P: $85.3 million (59% increase on year end 2021)

•       2P: $142.5 million (61% increase on year end 2021) 

•       Additional drilling locations identified at Gwinville, based on 2022 Selma Chalk horizontal drilling success, which are expected to add material levels of production.

2022 Independent Qualified Reserve Evaluation

The following tables highlight the findings of the NSAI Report, which was prepared in accordance with definitions, standards and procedures contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the most recent publication of the Canadian Oil and Gas Evaluation (“COGEH”). All evaluations and summaries of future net revenue are stated prior to the provision for interest, debt service charges or general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs, and estimated future capital expenditures. The NSAI Report was based on the average forecast pricing of the following four independent external reserves evaluators: GLJ Ltd, Sproule Associates Limited, McDaniel & Associates Consultants Ltd and Deloitte LLP. Additional reserves information as required under NI 51-101 will be included in Southern’s AIF, which will be filed on SEDAR in April 2023. The numbers in the tables below may not add due to rounding.

Summary of Reserves Volumes as at December 31, 2022

The Company’s reserve volumes and undiscounted future development capital costs are summarized below as at December 31, 2022:

SUMMARY OF RESERVE VOLUMES (1)

Light and Medium Oil (Mbbls)

Condensate           (Mbbls)

NGL                           (Mbbsl)

Conventional        Natural Gas                          (MMcf)

Total              Mboe

FDC Costs ($M)

Proved Developed Producing

79

203

49

35,281

6,211

–  

Proved Developed Non-Producing

 55

65

5

9,793

1,757

8,136

Proved Undeveloped

–  

369

113

34,010

6,150

71,567

Total Proved

134

637

166

79,084

14,117

79,702

Probable

41

188

13

66,579

11,338

84,832

Total Proved Plus Probable

175

825

178

145,663

25,456

164,533

(1)      Gross working interest reserves before royalty deductions.

The following table outlines the changes in Southern’s reserves and reserve life index as at December 31, 2022 compared to December 31, 2021:

CHANGE IN RESERVES AND RESERVE LIFE INDEX(1,2) 

2022

2021

% Change

Reserves (Mboe)

 

 

 

   Proved Developed Producing

6,211

5,707

25%

   Total Proved

14,117

10,479

44%

   Total Proved Plus Probable

25,456

20,178

31%

PDP as % of 2P

24%

28%

(14%)

1P as % of 2P

55%

52%

7%

Reserve Life Index (years)

   Proved Developed Producing

8.2

8.5

(4%)

   Total Proved

11.5

15.6

(26%)

   Total Proved Plus Probable

15.1

18.1

(17%)

(1)       Percent change includes 2022 actual production of 948.4 Mboe

(2)       The RLI as at December 31, 2022 is calculated as gross working interest reserves divided by the projected annual production forecast in each reserve category for 2023.  See “Disclosure of Oil and Gas Information”

Southern’s total 2P reserves increased by 31% to 25.5 MMboe resulting in a 2P reserve life index of 15.1 years on projected annual 2P production for 2023.  Southern’s 2022 Selma Chalk horizontal well appraisal program helped the Company achieve a 25% increase in PDP reserves to 6.2 MMboe.

Net Present Value of Future Net Revenue as at December 31, 2022

The following table summarizes the net present value, at varying discount rates, of the Company’s reserves (before-tax) as at December 31, 2022.  The reserves value on a $/boe basis, discounted at 10% per year, is also summarized for each category.

NET PRESENT VALUE BEFORE-TAX

0%                   (M$)

10%                 (M$)

20%                 (M$)

Unit Value(1) Before Income Tax, Discounted at 10%/year ($/boe)

Proved Developed Producing

84,730

51,617

38,860

10.61

Proved Developed Non-Producing

              29,510

11,376

6,587

8.42

Proved Undeveloped

73,834

22,343

4,400

4.51

Total Proved

188,074

85,336

49,847

7.64

Probable

180,679

57,191

24,546

6.36

Total Proved Plus Probable

368,753

142,528

74,393

7.07

(1)       Unit values are based on net reserves.  Net reserves are the Company’s working interest reserves after deduction of royalties

Forecast Prices Used in Estimates

The following table outlines the forecasted future prices used by NSAI in its evaluation of the Company’s reserves at December 31, 2022, for the NSAI Report, which are based on a four-consultant average price forecast, as detailed above. The forecast cost and price assumptions assume increases in wellhead selling prices and consider inflation with respect to future operating and capital costs.

FUTURE COMMODITY PRICE FORECAST

WTI Cushing

Oklahoma

$/bbl

NYMEX

Henry Hub

$/MMBtu

2023

80.25

4.93

2024

78.19

4.66

2025

76.10

4.42

2026

76.96

4.50

2027

78.50

4.59

2028

80.07

4.68

2029

81.67

4.78

2030

83.30

4.87

2031

84.96

4.97

2032

86.67

5.08

Thereafter

+ 2.0%/year

+ 2.0%/year

Reserves Reconciliation

The following table sets out the reconciliation of Southern’s gross reserves based on forecast prices and costs by principal product type as at December 31, 2022 relative to December 31, 2021. The majority of 1P and 2P reserves increases, year-on-year, came from recognition of the Gwinville Selma Chalk horizontal locations from infill drilling.

RESERVES(1) RECONCILIATION

PDP (Mboe)

1P (Mboe)

Probable (Mboe)

2P (Mboe)

December 31, 2021

5,707

 10,479

9,699

20,178

Discoveries

–  

 –  

–  

–  

Extensions

–  

–  

–  

–  

Infill Drilling

624  

3,747  

1,281

5,028

Improved Recovery

–  

–  

–  

–  

Technical Revisions(2)

(34)

(30)

259

229

Acquisitions

43  

 55  

1

56

Dispositions

(40)

(40)

(22)  

(62)

Economic Factors

860

856

120

976

Production(3)

(948)

(948)

–  

(948)

December 31, 2022

6,211

14,117

11,338

25,456

(1)      Gross working interest reserves before royalty deductions

(2)      Technical revisions also include reserves associated with changes in operating costs and commodity price offsets

(3)      Produced volumes for the year ended December 31, 2022 are internally estimated

Arrow Exploration

Arrow has announced the results of its 2022 year-end reserves evaluation by Boury Global Energy Consultants Ltd. 

All reserves volume figures stated below are on a Working Interest Gross Reserve basis. Currency amounts are in United States dollars (unless otherwise indicated) and comparisons refer to December 31, 2021.

Highlights

–      Proved (“1P”) reserves:

 Increased by 11% to 3.37 million barrels of oil equivalent (“MMboe“), driven principally through uplift at Tapir (Rio Cravo), Colombia; 

 Net present value before tax, discounted at 10% (“NPV-10”) is $57.9 million ($17.15/boe) for 1P reserves.

–      Proved plus Probable (“2P”) reserves:

 Increased by 4% to 7.69 MMboe; 

 NPV-10 is $127.3 million ($16.56/boe) for 2P reserves.

–      Proved plus Probable plus Possible (“3P”) reserves:

 Increased by 1% to 11.68 MMboe;

 NPV-10 is $205.8 million ($17.57/boe) for 3P reserves.

–      Before tax NPV-10 values have increased 97% for 1P and 51% for 2P, over year-end 2021, due to reserves growth and an increase in the oil price forecast used by BouryGEC at year-end 2022;2022 Proved Developed Producing (“PDP”) reserves increased 27% to 1.31 MMboe supported by the improved performance of the new drilling in the Rio Cravo Field; PDP reserves represent 39% of 1P reserves, reflecting an attractive ratio of base production to low-risk drilling targets; and

–      Before tax NPV-10 per share of US$0.14/share, US$0.39/share, and US$0.63/share for 1P, 2P, and 3P reserve categories, respectively;

–      BouryGEC post tax NPVs impacted by changes in Colombian tax regime in the year but pre other corporate tax shelters (further detail below).

CEO Commentary

Marshall Abbott, CEO of Arrow, commented:

“Arrow delivered an increase in volumes and pre-tax values across 1P, 2P and 3P reserves in 2022. We are pleased with the results of the BouryGEC reserves evaluation, which reinforces the significant value of our Colombian and Canadian assets.

The BouryGEC 2022 report of course does not account for the current drilling campaign at Rio Cravo Este, where, given the encouraging results to date, we might expect further reclassifications and increase in reserves.  Additionally, with the imminent drilling of the Carrizales Norte wells, we would expect to continue growing reserves in the near future.

These very decent reserve numbers are made better by the fact that they are after a very good production number in the period they are calculated and show just how well the drilling programme in 2H 2022 went and it should be noted that the current highly successful well results are not included in these numbers. 

With this in mind this highly successful campaign is shortly to be concluded and succeeded by the drilling at Carrizales Norte which should add yet more to these figures. Accordingly I remain, as does the company, positive that the 3/- b/d target is well within reach.

No surprise then that my target price remains at 50p and accordingly the shares are incredibly good value at these knockdown levels. The long term outlook for Arrow is indeed extremely positive, the company has a very strong balance sheet, growth in production and resources and the discount to cash alone should be ringing bells with potential investors, the shares are cheap on any metric. 

2022 Year-End Reserves Summary

Management has presented below a summary of Arrow’s reserves as at December 31, 2022, on a working interest gross reserves basis, which have been taken from and reconcile directly to the reserves report prepared by BouryGEC, an independent qualified reserves evaluator.  The figures in the following tables have been prepared in accordance with the standards contained in the most recent publication of the Canadian Oil and Gas Evaluation Handbook and the reserve definitions contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). In addition to the summary information disclosed in this announcement, more detailed information will be included in Arrow’s annual reserves evaluation for the year ended December 31, 2022 to be filed on SEDAR (www.sedar.com) and posted on Arrow’s website (www.arrowexploration.ca).

After tax values have been calculated without taking into account the tax shelter created by capital spending on projects that do not have reserve values associated with them, such as the Tapir 3D seismic project, drilling at Carazales Norte and annual G&A. Spending on these projects will provide tax shelter and result in a reduction of tax for future.

Brent Crude Oil Price and AECO Gas Price Forecasts in BouryGEC Reserves Evaluation

Year-End Forecast:

2023

2024

2025

2026

2027

2028

2029

Brent (US$/bbl) – Dec. 31, 2022

$85.00

$82.80

$80.50

$82.00

$84.20

$85.88

$87.60

AECO-C Spot (C$/MMbtu)

C$4.83

C$4.50

C$4.31

C$4.42

C$4.53

C$4.64

C$4.61

Year-End Working Interest Gross Reserves – Breakdown by Category and Country (Mboe)

 

2022

2021

Change

% Change

Proved developed producing

1,319

1037

282

27%

 – Colombia assets (core)

664

287

 – Colombia assets (non-core)

178

117

 – Canada assets

475

633

Proved developed non-producing

26

362

(336)

(93%)

 – Colombia assets (core)

0

63

 – Colombia assets (non-core)

26

42

 – Canada assets

0

258

Proved undeveloped

2,032

1,649

383

23%

 – Colombia assets (core)

453

88

 – Colombia assets (non-core)

1,579

1,561

 – Canada assets

0

0

Total Proved

3,376

3,048

329

11%

Probable

4,314

4,373

(59)

(1%)

 – Colombia assets (core)

1,003

1,232

 – Colombia assets (non-core)

2,765

2,446

 – Canada assets

546

694

Total Proved plus Probable

7,691

7,421

270

4%

Possible

3,989

4,119

(130)

(3%)

 – Colombia assets (core)

2,224

1,933

 – Colombia assets (non-core)

1,513

1,828

 – Canada assets

252

359

Total Proved plus Probable & Possible

11,679

11,540

140

1%

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

(1)      “Core” assets include Arrow’s share of reserves in the Tapir Block, the Santa Isabel Block (Oso Pardo), and Mateguafa. Arrow’s 50% interest in the Tapir Block is contingent on the assignment by Ecopetrol SA of such interest to Arrow.

(2)      “Non-core” assets include the Ombu Block (which includes the Capella Field)

(3)      “Canada” assets include Fir and Pepper

Year-End Net Present Value at 10% – Before Tax ($ Thousands)

Category

2022

2021

% Change

Proved

  Developed Producing

32,092

11,406

181%

  Non-Producing

357

2,112

(83%)

  Undeveloped

25,458

15,889

60%

Total Proved

57,906

29,407

97%

  Probable

69,440

54,738

27%

Total Proved plus Probable

127,346

84,146

51%

  Possible

78,471

49,842

57%

Total Proved plus Probable & Possible

205,817

133,987

54%

 Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Year-End Net Present Value at 10% – After Tax ($ Thousands)

Category

2022

2021

% Change

Proved

  Developed Producing

19,509

11,170

75%

  Non-Producing

269

2,112

(87%)

  Undeveloped

9,092

11,705

(22%)

Total Proved

28,871

24,987

16%

  Probable

28,618

33,886

(16%)

Total Proved plus Probable

57,489

58,873

(2%)

  Possible

32,033

29,959

7%

Total Proved plus Probable & Possible

89,522

88,832

1%

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Year-End Net Present Value at 10% – After Tax ($ millions) – Sensitivity Cases

In the context of the Brent crude oil and AECO gas prices prevailing at the time of the publication of this press release, when compared generally to the Brent crude oil and AECO gas price forecasts used in the BouryGEC Reserves Evaluation for the year ended December 31, 2022, Arrow is also providing readers with the following sensitivity analysis as to the net present value of its reserves.

Type of Sensitivity

Total Proved (US$MM)

Total Proved plus Probable (US$MM)

Total Proved plus Probable & Possible (US$MM)

BouryGEC Forecast Price Case

28.9

57.5

89.5

WTI Premium of US$10/bbl

36.5

72.7

111.2

AECO Premium of C$0.30/MMBtu

29.2

58.2

90.3

 Readers are cautioned that there is no certainty that the forecast price of crude oil or natural gas will increase as calculated by changes to the Dec. 31, 2022 BouryGEC price deck used in the Reserves Evaluation report.

Forecast Revenues and Costs – Undiscounted ($ millions)

Category

Revenue (3)

Royalties

Operating Cost (2)

DC

Abandonment & Reclamation

BT Future Net Revenue (1)

Income Taxes

AT Future Net Revenue (1)

Total Proved

159.5

15.3

34.2

32.4

4.3

73.3

34.7

38.6

Total Proved plus Probable

354.0

33.3

62.9

67.4

6.9

183.6

93.2

90.4

Total Proved plus Probable & Possible

591.2

63.2

105.7

82.1

8.2

332.0

174.3

157.7

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

(1)      BT = Before Taxes and AT = After Taxes

(2)      Operating Cost less processing and other income

(3)      Revenue includes Petrolco Income

2021 Year-End Working Interest Gross Reserves Reconciliation (Mboe)

Total Proved

Total Proved plus Probable

Total Proved plus Probable & Possible

31-Dec-21

3,049

7,421

11,541

Technical Revisions

745

395

503

Economic Factors

58

352

112

Production

(476)

(476)

(476)

31-Dec-22

3,376

7,692

11,680

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Coro Energy

Coro has announced that it has entered into a revised Heads of Terms with the shareholders of KIMY Trading and Service JSC, following its due diligence process, in respect of the potential 3.25 megawatts acquisition, announced on 25 November 2022.

As announced on 25 November 2022, the Company entered into a period of exclusivity on a 100% interest in a leased rooftop solar portfolio in Vietnam across four locations close to Saigon with an aggregate generating capacity of 3.25 megawatts currently held by KIMY. The Portfolio has been operational for two years and benefits from an existing power purchase agreement with a remaining eighteen-year term, with the power off-taker being state owned Electricity Vietnam (EVN).

Following due diligence and site visits, legal work on the final transaction documents is now underway. The Company has renegotiated some elements of the Heads of Terms with the vendor to reflect some works that will be needed post completion and has now signed a revised Heads of Terms, which extends the exclusivity.  The total acquisition price remains circa US$1.7 million (US$548/MW) albeit with revised consideration scheduling as follows:

·    At completion:

 Assumption by Coro (via acquisition of KIMY) of US$950,000 of existing specialist renewables debt with a Vietnamese bank;

 US$130k cash payable, of which US$30k is ring fenced to secure certain required local fire safety certifications;

 US$0.25 million payable in new ordinary shares in the Company, locked in for 18 months from completion;

·    A further US$80,000 cash and US$80,000 of new ordinary shares in the Company, payable after 2 months on demonstration that the local certification is in place with no curtailment

·    A further US$0.25 million in cash in six equal monthly instalments from completion.

Further protections in respect of the outstanding documentation will be incorporated into the final transaction documents albeit it is understood that achieving the documentation is purely an administrative process.

Little to add here, certainly not enough for explanatory comment from the company, a better deal than previously expected and pushes forward the move into South East Asia.

Predator Oil & Gas

Predator has announced the following update to the fund raising announced on 17 March 2023. 

On that date the Company  announced that it had conditionally placed 15,500,000 new ordinary shares of no par value in the Company and 20,863,636 existing ordinary shares of no par value in the Company transferred by a director of the Company, Paul Griffiths, at a placing price of 5.5 pence each to raise £2,000,000 for completion on 3 April 2023. The Company now confirms that the number of New Shares issued will be 14,174,056 whilst the number of Loan Shares to be transferred by Paul Griffiths will be 22,189,580. 

The total funds raised by the Placing remains at £2,000,000, which is conditional on the New Shares being admitted to listing on the Official List and to trading on the London Stock Exchange’s main market for listed securities on or around 3 April  2023.

Stock Lending Agreement

The Loan Shares will be documented in a single stock lending agreement between Paul Griffiths and the Company.

Under the unsecured Stock Lending Agreement between the Company and Paul Griffiths the return of 22,189,580 shares loaned to the Company are intended to be issued to Mr Griffiths when the Company has additional headroom and at an appropriate time, subject to the Company’s dealing policy. When repayment is due the Company will make the necessary listing and admission hearing applications to have those new ordinary shares admitted to trading.

Interest shall accrue on the Loan at a rate of 4%  above SONIA of the principal sum lent of £1,220,427, being the market value of 22,189,580 shares at the Placing Price. The default rate of interest under the Stock Lending Agreement for any sum which is not repaid when due is 12% per annum.

Related Party Transaction

Paul Griffiths is a director of the Company. The Stock Lending Agreement is therefore considered to be a related party transaction.

Lonny Baumgardner, Alistar Jury and Carl Kindinger, being the independent directors for the purposes of the Related Party Transaction consider that the terms and conditions of the Stock Lending Agreement are fair and reasonable insofar as the shareholders of the Company are concerned.

An application will be made to the FCA and to the London Stock Exchange Admission in respect of those 14,174,056 New Shares.  It is expected that Admission will become effective, and that dealings in such shares are expected to commence, at 8.00 a.m. on 3 April 2023.

The rights attaching to the New Shares will be uniform in all respects and will rank pari passu, and form a single class for all purposes with, the existing issued shares of no par value in the Company.

No surprises here, I have already written about the raise for Predator and for Mr Griffiths’ excitement for drilling in Morocco.

And finally…

In the final round of Euro qualifying Scotland pulled the result of the week out of the bag beating Spain 2-0. Wales also won beating Latvia 1-0.

Author @mgrahamwood

Disclaimer & Declaration of Interest
The information, investment views and recommendations in this article are provided for general information purposes only. Nothing in this article should be construed as a solicitation to buy or sell any financial product relating to any companies under discussion or to engage in or refrain from doing so or engaging in any other transaction. Any opinions or comments are made to the best of the knowledge and belief of the writer but no responsibility is accepted for actions based on such opinions or comments. The writer may or may not hold investments in the companies under discussion


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