Just arrived in from the USA where confidence in energy remains high and the companies from the top down are in very strong positions.

Genel Energy

Genel has announced that payment has been received from the Kurdistan Regional Government (‘KRG’) relating to Tawke PSC sales during September 2022.

Genel’s share of payments for September sales is expected to be as follows:

(all figures $ million)Expected paymentUnder previous mechanism
Tawke (received)16.117.7
Taq Taq2.42.4
Sarta1.41.7
Receivable recovery13.113.1
Total33.034.9

 

Sales for September have been priced by the KRG under a new pricing formula based on the realised sales price for Kurdistan blend crude (‘KBT’) during the delivery month, rather than on dated Brent, which was the basis in the past. KBT is the aggregation of oil transported through the Iraq-Turkey Pipeline and sold at Ceyhan.

The change in pricing formula results in an adverse impact on September realised price per barrel at field level of $11/bbl, with the impact on our working interest per barrel being $2/bbl. This has impacted our proceeds by $1.9 million for sales made in September. Should the new pricing mechanism have been in place across 2022, the impact of the change on realised monthly price per barrel at field level would have ranged between $6/bbl and $13/bbl, with the impact on working interest between $1/bbl and $3/bbl.

The table below summarises the KBT blend price stated by the KRG for the months from September 2022 to January 2023, together with the impact on our working interest $/bbl revenue. The netback figure continues to include adjustments for transportation costs and crude quality, with the quality adjustment now reduced as the crude quality of KBT is lower than Brent.

(all figures $/bbl)Sep 2022Oct 2022Nov 2022Dec 2022
Dated Brent90939281
KBT blend72757263
Impact on field revenue realised price (adjusted for quality to KBT blend)11121310
Impact on Genel revenue per working interest barrel2.22.52.72.2

 

Pending settlement of the above receivable recovery payment, there is no further payment to be received under the KRG payment mechanism for past receivables.

This data gives an idea of what the oil price is net of the aggregation of oil transported through the Iraq-Turkey Pipeline and sold at Ceyhan and shows what the net effect would be given certain circumstances, should this continue to be the case.

IOG

IOG has confirmed that the Blythe H2 well was spudded at 3.20am on Sunday 5th March.

The well is being drilled by the Noble Hans Deul jack-up drilling rig (to be renamed the Shelf Perseverance) under IOG’s contract with Shelf Drilling (UK) Ltd signed in 2020. As with previous IOG development wells, Petrofac is the designated Well Operator.

The H2 well is expected to take approximately three months to drill, complete and hook-up, subject to the usual offshore operational risks to scheduling.

The Company’s plans factor in certain H1 production shut-in periods which are required for full compliance with offshore safety regulations. Under the Blythe platform Safety Case, on Sunday 26th February the H1 well was taken offline to facilitate safe rig move, interfacing and top hole drilling operations. An estimated total of 12 days of planned outages in March will result in lower average production this month. A shorter planned outage will also be required on completion of the H2 well to enable safe hook-up for production.

Rupert Newall, CEO of IOG, commented:

“The Blythe H2 well has the potential to significantly enhance our current production levels, reduce water production into the pipeline and minimise associated opex. It also has fast payback potential and will enable us to boost cash flow from mid-2023.

I would like to thank our team for their outstanding efforts in accelerating this well, securing all 36 permits required and getting the rig moved across to the Blythe platform efficiently and ahead of plan.  This is the first well that has been designed, engineered and planned by our new IOG team working with our key contractors Shelf, Petrofac and ODE. We are very focused on ensuring safe, efficient and successful execution.

In parallel, we are progressing our detailed post-A2 technical evaluation of Southwark and other key assets in the portfolio in order to optimise our plans beyond this well.”

This is an important well for IOG, aren’t they all? But all being well the increase in production that it will bring will be meaningful and whilst all that is happening the Southwark technical evaluation is underway. 

Touchstone Exploration

Touchstone has announced its 2022 year-end reserves.

Our independent reserves evaluation was prepared by GLJ Ltd. (GLJ) with an effective date of December 31, 2022 (the Reserves Report). Highlights of our total proved developed producing (“PDP”), total proved (“1P”), total proved plus probable (“2P”) and total proved plus probable plus possible (“3P”) reserves from the Reserves Report are provided below. All finding and development (“F&D”) costs below include changes in future development capital (“FDC”). Unless otherwise stated, all financial amounts referenced herein are stated in United States dollars. Financial information contained herein is based on the Company’s unaudited results for the year ended December 31, 2022 and is subject to change. Readers are further cautioned to read the applicable advisories contained herein.

Touchstone’s 2022 year-end reserves reflect the sustainability of our low decline asset base, as our 2022 capital program focused on exploration activities on our Ortoire property, where we completed construction of the Coho natural gas facility and continued construction operations of the Cascadura natural gas and liquids facility. Touchstone did not drill any development or exploration wells in the 2022 year.

In 2022 we achieved initial production from our Coho-1 well, which produced net volumes of 5.7 MMcf/d (approximately 955 boe/d) in the fourth quarter of 2022 contributing to average quarterly production volumes of 2,229 boe/d and average 2022 annual production volumes of 1,581 boe/d.

2022 Year-end Reserves Report Highlights

·      Relative to year-end 2021 and after 2022 production, we increased PDP gross reserves by 33% to 4,843 Mboe, decreased 1P gross reserves by 0.7% to 38,463 Mboe, decreased 2P gross reserves by 0.6% to 75,074 Mboe and decreased 3P gross reserves by 0.6% to 120,594 Mboe in 2022.

·      PDP reserves replaced 2022 annual production by 308%, reflecting forecasted Coho-1 natural gas volumes that were brought online in 2022.

·      Our net present value of future net revenues discounted at 10% (“NPV10”) on a before tax PDP basis increased by 21% to $62.6 million, increased by 12% to $530.3 million on a 1P basis, increased by 13% to $993.7 million on a 2P basis, and increased by 12% to $1.47 billion on a 3P basis from the prior year.

·      Realized after tax PDP NPV10 of $51.8 million representing an increase of 45% from the prior year, after tax 1P NPV10 increased by 22% from year-end 2021 to $256.6 million, after tax 2P NPV10 increased by 24% from the prior year to $450.6 million and after tax 3P NPV10 increased by 22% from 2021 to $654.9 million.

·      Limited development operations and a focus on investing in our natural gas facilities led to a 1P recycle ratio of 0.6 times and a 2P recycle ratio of 0.2 times.

·      We continue to maintain a long producing reserve life index (“RLI”) of 5.8 years PDP and 13.1 years 1P reflecting the low decline nature of our asset base.

2022 Year-end Reserves Report Summary

Touchstone’s year-end crude oil, natural gas and NGL reserves in Trinidad were evaluated by independent reserves evaluator, GLJ, in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserves information as required under NI 51-101 will be included in the Company’s Annual Information Form, which will be filed on SEDAR on or before March 31, 2023.

The reserve estimates set forth below are based upon GLJ’s Reserves Report dated March 3, 2023 with an effective date of December 31, 2022. The Reserves Report uses the average price forecasts of the three leading Canadian oil and gas evaluation consultants (GLJ, McDaniel & Associates Consultants Ltd. and Sproule Associates Ltd. (collectively, the “Consultants”)). All values in this announcement are based on the three Consultants’ average forecast pricing and GLJ’s estimates of future operating and capital costs as of December 31, 2022. Please refer to “Advisories: Reserves Advisories” for further information. In certain tables set forth below, the columns may not add due to rounding.

2022 Reserves Summary by Category

 

 

PDP

1P

2P

3P

Total gross reserves(1) (Mboe)

4,843

38,463

75,074

120,594

Reserve additions (reductions)(2) (Mboe)

1,769

306

101

(164)

NPV10 before income tax(3) ($000’s)

62,561

530,264

993,714

1,473,380

NPV10 after income tax(3) ($000’s)

51,770

256,623

450,624

654,913

Notes:

(1)    Gross reserves are the Company’s working interest share before deduction of royalties.

(2)    Reserve additions exclude period production. See “Advisories: Oil and Gas Metrics”.

(3)    Based on the three Consultants’ average December 31, 2022 forecast prices and costs. See Forecast prices and costs.

Year-Over-Year Reserves Data

 

December 31, 2022

December 31, 2021(1)

% Change

PDP gross reserves(2) (Mboe)

4,843

3,648

33

1P gross reserves(2) (Mboe)

38,463

38,731

(1)

2P gross reserves(2) (Mboe)

75,074

75,547

(1)

3P gross reserves(2) (Mboe)

120,594

121,332

(1)

PDP NPV10 before income tax(3) ($000’s)

62,561

51,737

21

1P NPV10 before income tax(3) ($000’s)

530,264

474,922

12

2P NPV10 before income tax(3) ($000’s)

993,714

881,753

13

3P NPV10 before income tax(3) ($000’s)

1,473,380

1,313,006

12

PDP NPV10 after income tax(3) ($000’s)

51,770

35,781

45

1P NPV10 after income tax(3) ($000’s)

256,623

210,036

22

2P NPV10 after income tax(3) ($000’s)

450,624

363,068

24

3P NPV10 after income tax(3) ($000’s)

654,913

535,613

22

Notes:

(1)    Prior year reserve estimates per GLJ’s independent reserves evaluation dated March 4, 2022 with an effective date of December 31, 2021.

(2)    Gross reserves are the Company’s working interest share before deduction of royalties.

(3)    Based on the three Consultants’ average December 31, 2022 forecast prices and costs. See Forecast prices and costs.

Summary of Crude Oil and Natural Gas Reserves by Product Type

 

Company Gross(1) Reserves

Light and Medium Crude Oil (Mbbl)

Heavy Crude Oil

(Mbbl)

Conventional Natural Gas (MMcf)

Natural Gas Liquids (Mbbl)(2)

Total Oil Equivalent (Mboe)

 

Proved

Developed Producing

3,470

258

6,690

4,843

Developed Non-Producing

1,529

210

86,146

2,198

18,294

Undeveloped

4,979

53,841

1,373

15,326

Total 1P

9,977

468

146,677

3,571

38,463

Probable

8,711

416

144,850

3,342

36,611

Total 2P

18,688

884

291,527

6,913

75,074

 

 

 

 

 

Possible

5,902

332

205,894

4,972

45,520

24,590

1,216

497,421

11,885

120,594

Company Net(3) Reserves

Light and Medium Crude Oil (Mbbl)

Heavy Crude Oil

(Mbbl)

Conventional Natural Gas (MMcf)

Natural Gas Liquids (Mbbl)(2)

Total Oil Equivalent (Mboe)

 

Proved

Developed Producing

2,091

230

5,854

3,296

Developed Non-Producing

965

187

75,378

1,923

15,638

Undeveloped

3,658

47,111

1,202

12,712

Total 1P

6,714

417

128,343

3,125

31,646

Probable

6,540

370

126,744

2,925

30,959

Total 2P

13,254

787

255,086

6,049

62,605

 

 

 

 

 

Possible

4,342

295

180,157

4,350

39,013

17,596

1,082

435,243

10,399

101,618

 

Notes:

(1)    Gross reserves are the Company’s working interest share before deduction of royalties.

(2)    NGLs are comprised of 100% condensate.

(3)    Net reserves are the Company’s working interest share after the deduction of royalty obligations.

Summary of Net Present Values of Future Net Revenues(1)

Net Present Values Before Income Taxes ($000’s)

Undiscounted

Discounted at 5%

Discounted at 10%

Discounted at 15%

Discounted at 20%

 

Proved

Developed Producing

84,121

71,897

62,561

55,515

50,081

Developed Non-Producing

373,318

303,750

256,815

222,221

195,600

Undeveloped

349,815

268,045

210,888

169,542

138,744

Total 1P

807,254

643,692

530,264

447,278

384,425

Probable

929,042

634,858

463,450

354,683

281,289

Total 2P

1,736,296

1,278,550

993,714

810,961

665,714

Possible

1,162,845

706,880

479,666

350,833

270,402

2,899,141

1,985,430

1,473,380

1,152,794

936,116

 

 

 

 

 

Net Present Values After Income Taxes(2) ($000’s)

Undiscounted

Discounted at 5%

Discounted at 10%

Discounted at 15%

Discounted at 20%

 

Proved

Developed Producing

59,691

56,612

51,770

47,274

43,432

Developed Non-Producing

159,207

134,649

117,278

104,014

93,519

Undeveloped

153,285

114,778

87,576

67,879

53,270

Total 1P

372,183

306,039

256,623

219,166

190,222

Probable

383,287

265,306

194,000

148,011

116,700

Total 2P

755,470

571,344

450,624

367,177

306,922

 

 

 

 

 

Possible

474,034

296,499

204,289

150,949

117,211

Total 3P

1,229,504

867,843

654,913

518,126

424,133

 

Notes:

(1)    Based on the three Consultants’ average December 31, 2022 forecast prices and costs. See Forecast prices and costs.

(2)    The after-tax net present values prepared by GLJ in the evaluation of the Company’s crude oil and natural gas assets presented herein are calculated by considering current Trinidad tax regulations and are based on the Company’s estimated tax pools and non-capital losses as of December 31, 2022. The values reflect the expected income tax burden on the assets on a consolidated basis. Values do not represent an estimate of the value at the business entity level or consider tax planning, which may be significantly different. See “Advisories: Unaudited Financial Information”.

Reconciliation of Gross Reserves by Product Type

The following table sets forth a reconciliation of the Company’s total gross proved, gross probable and total gross proved plus probable reserves as of December 31, 2022 by product type against such reserves as at December 31, 2021 based on forecast prices and cost assumptions.

 

Reserves Category and Factors

Light and Medium Crude Oil (Mbbl)

Heavy Crude Oil

(Mbbl)

Conventional Natural Gas (MMcf)

Natural Gas Liquids (Mbbl)(1)

Total Oil Equivalent (Mboe)

 

 

 

 

 

 

Total Proved

December 31, 2021(2)

10,174

471

147,093

3,571

38,731

Extensions and improved recovery(3)

94

94

Technical revisions(4)

169

23

111

211

Production

(460)

(27)

(527)

(574)

December 31, 2022

9,977

468

146,677

3,571

38,463

 

Total Probable

December 31, 2021(2)

8,908

458

144,642

3,342

36,815

Technical revisions(4)

(201)

(42)

208

(208)

Economic factors(5)

3

3

December 31, 2022

8,711

416

144,850

3,342

36,611

 

Total Proved plus Probable

December 31, 2021(2)

19,082

929

291,735

6,914

75,547

Extensions and improved recovery(3)

94

94

Technical revisions(4)

(31)

(18)

320

4

Economic factors(5)

3

3

Production

(460)

(27)

(527)

(574)

December 31, 2022

18,688

884

291,527

6,913

75,074

Notes:

(1)    NGLs are comprised of 100 percent condensate.

(2)    Prior year reserve estimates per GLJ’s independent reserves evaluation dated March 4, 2022 with an effective date of December 31, 2021.

(3)    Reserve amounts for Infill Drilling, Extensions and Improved Recovery are combined and reported as “Extensions and Improved Recovery”.

(4)    Technical revisions factor includes all changes in reserves due to well performance and previously booked wells which were drilled in the year.

(5)    Economic factors are the change in reserves exclusively due to changes in pricing.

In comparison to December 31, 2021 on a proved plus probable reserve basis, 2022 light and medium crude oil reserves declined 394 Mbbl. Improved recovery attributed to well recompletions was offset by 2022 annual production. 2022 proved plus probable heavy crude oil reserves decreased by 45 Mbbl from the prior year due to downward technical revisions of 18 Mbbl associated with reduced well performance at our Fyzabad block, combined with 27 Mbbl of production. Proved plus probable conventional natural gas reserves decreased by 208 MMcf relative to December 31, 2021, as an increase from reduced surface loss estimates related to Coho was offset by 2022 production.

Future Development Costs

The following table provides information regarding the development costs deducted in the estimation of the Company’s future net revenue using forecast prices and costs as included in the Reserves Report.

Year ($000’s)

PDP

1P

2P

3P

2023

190

23,648

26,938

26,938

2024

31,810

45,006

45,006

2025

8,841

38,067

38,067

2026

11,232

15,885

15,885

2027

11,213

15,470

15,470

Thereafter

Total undiscounted

190

86,744

141,366

141,366

Total discounted at 10% per year

181

72,435

116,145

116,145

The following table sets forth the changes in undiscounted future development costs included in the Reserves Report against such costs in our December 31, 2021 reserves report prepared by GLJ dated March 4, 2022.

($000’s unless otherwise stated)

PDP

1P

2P

3P

(Decrease) / increase in forecasted capital costs

(110)

3,450

5,685

5,685

Increase in forecasted wells

4,757

4,720

4,720

Decrease in forecasted facility and pipeline costs

(1,477)

(2,613)

(2,613)

Total (decrease) / increase in FDC from 2021

(110)

6,730

7,792

7,792

Total (decrease) / increase in FDC from 2021 (%)

(37)

8

6

6

Forecast Pricing and Costs

Forecast pricing and costs are prices and costs that are generally acceptable, in the opinion of GLJ, as being a reasonable outlook of the future as of the evaluation effective date. The forecast cost assumptions consider inflation with respect to future operating and capital costs. The following table sets forth the benchmark reference prices and inflation rates reflected in the Reserves Data as of December 31, 2022. These price assumptions were provided to the Company by GLJ and represented the average price forecast of the three Consultants as of the date of the Reserves Report.

Consultants Average Price Forecast

Forecast Year

Brent Spot Crude Oil(1)

($/bbl)

Henry Hub Natural Gas(1)

($/MMBtu)

Inflation Rate

(% per year)

2023

84.67

4.74

0.0

2024

82.69

4.50

2.3

2025

81.03

4.31

2.0

2026

81.39

4.40

2.0

2027

82.65

4.49

2.0

2028

84.29

4.58

2.0

2029

85.98

4.67

2.0

2030

87.70

4.76

2.0

2031

89.46

4.86

2.0

2032

91.25

4.95

2.0

Thereafter

+2.0% / year

+2.0% / year

2.0

 

Note:

(1)    This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer. Product sales prices will reflect these reference prices with further adjustments for specific marketing arrangements, quality differentials and transportation to point of sale.

Capital Program Efficiency

 

2022

2022 – 2020 Total

1P

2P

1P

2P

Estimated capital expenditures(1),(4) ($000’s)

11,330

11,330

57,763

57,763

Change in FDC ($000’s)

6,730

7,792

41,369

69,685

F&D costs(2),(4) ($000’s)

18,060

19,122

99,132

127,448

Reserve additions(2),(3) (Mboe)

306

101

28,193

54,588

F&D costs per boe(2),(4) ($/boe)

59.02

189.33

3.52

2.33

 

 

 

 

 

Estimated operating netback(1),(4) ($/boe)

33.42

33.42

25.16

25.16

 

 

 

 

 

Recycle ratio(2),(4)

0.6x

0.2x

7.2x

10.8x

 

Notes:

(1)    Financial information is based on the Company’s preliminary 2022 unaudited financial statements and is therefore subject to change. See “Advisories: Unaudited Financial Information”.

(2)    See “Advisories: Reserves Advisory” and “Advisories: Oil and Gas Metrics”.

(3)    Based on gross reserves, which are the Company’s working interest share before deduction of royalties.

(4)    Non-GAAP financial measure. See “Advisories: Non-GAAP Financial Measures “.

 

I can add nothing else, this very good report is just the start and I am confident that Touchstone is going to be a substantially bigger company as they explore, develop and market their fine portfolio of hydrocarbon assets.