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2022

History Matching and Forecasting-2022

April 4, 2022
- This year’s history matching and forecasting selections, made by reviewer Gopi Nalla of DeGolyer and MacNaughton, reflect the importance of accurate and innovative methodology in the approach toward development of unconventional or challenging plays, from tight oil to highly heterogeneous gas fields to coalbed methane.
  
  The authors of paper URTEC 208352 evaluate and compare the performance of rate-normalization and pressure-deconvolution techniques for both synthetic and tight-oil examples. While the synopsis is devoted mostly to the authors’ work in applying these techniques to synthetic cases, much of the complete paper is devoted to tight-oil examples. Ultimately, the authors recommend the pressure-deconvolution approach generally.
  
  In paper SPE 207933, the authors apply an integrated approach of using reservoir pressure/gas compressibility (P/Z) calculations to obtain a field gas initially in place (FGIIP) estimation that is then incorporated into an integrated asset model. The technique is applied to a giant onshore gas field. The authors conclude that the new FGIIP estimation can be applied as a reference to re‑review the static modeling legacy and to narrow static modeling uncertainties, leading to reliable forecasting and more-efficient field development.
  
  An application of the iterative ensemble Kalman smoother to a scenario involving horizontal coalbed-methane wells for a low-permeability field in Australia is the subject of paper URTEC 208291. A forecast study was conducted to validate the history-matched ensemble, with the results showing a good match of 12 months of the new production data not used in history matching, highlighting the robust prediction capabilities of the presented approach.
  
  SPE papers continue to a be a vital resource for industry professionals; arguably, such work is more important than ever as the industry and the world adjusts to new modes of collaboration and realities in both the office and the field. I invite you to read the full text of these papers on OnePetro and to find further recent works that advance the literature of this specialized but critical Tech Focus topic.
  
  This Month’s Technical Papers
  
  Techniques for History-Matching and Forecasting Tight Oil Reservoirs Compared
  
  Material-Balance Method With Static Modeling Helps Generate Reliable Forecasting
  
  Iterative Ensemble Kalman Smoother Applied to History-Matching Coalbed Methane Wells
  
  Recommended Additional Reading
  
  URTEC 208361 Effect of Relative Permeability on Modeling of Shale Oil and Gas Production by Hamid Behmanesh, University of Calgary, et al.
  
  SPE 204835 Successful Case Study of Machine-Learning Application To Streamline and Improve History-Matching Process for Complex Gas-Condensate Reservoirs in Hai Thach Field, Offshore Vietnam by Son Hoang, Bien Dong Petroleum Operating Company, et al.
  
  SPE 207855 Unleashing the Potential of Relative Permeability Using Artificial Intelligence by Abdur Rahman Shah, Schlumberger, et al.
  
  Gopi Nalla, SPE, is a senior reservoir engineer with DeGolyer and MacNaughton. He has 18 years of industry experience and previously worked for 12 years with Chevron and 2 years with Idaho National Laboratory. Nalla holds an MS degree in petroleum engineering from The University of Texas at Austin and a BS degree in chemical engineering from the National Institute of Technology, India. He is a licensed professional engineer in Texas and California and serves on the JPT Editorial Review Board. Nalla also has served as a reviewer for SPE Reservoir Evaluation & Engineering. He can be reached at gnalla@demac.com.
  
  https://jpt.spe.org/history-matching-and-forecasting-2022
DNO Releases 2021 Annual Statement of Reserves and Resources

DNO - February 23, 2022
- Oslo, 21 February 2022 – DNO ASA, the Norwegian oil and gas operator, today announced it exited 2021 with 321 million barrels of oil equivalent (MMboe) of net proven and probable (2P) reserves, notwithstanding production of 34 MMboe during the year. The Company’s 2P reserves life stood at 9.3 years. Combined with contingent (2C) resources of 189 MMboe, DNO’s reserves and resources life stood at 14.8 years.
  
  Of the total, the Company’s Kurdistan portfolio accounted for 267 million barrels of oil (MMbbls) of net 2P reserves compared to 295 MMbbls in 2020, and 71 MMbbls of net 2C resources compared to 27 MMbbls at yearend 2020.
  
  Across its North Sea portfolio at yearend 2021, DNO’s net 2P reserves stood at 54 MMboe compared to 64 MMboe a year earlier. 2C resources totaled 113 MMboe compared to 120 MMboe at yearend 2020.
  
  Effective from 2021, the Company reports its net production, reserves and resources based on the participation interest in all of its licenses. Prior to 2021 and for the licenses governed by Production Sharing Contracts, the Company reported its net figures after royalty and included DNO’s additional share of cost oil covering its advances towards the government carried interest (if any) as well as volumes attributed to the three percent of gross Tawke license production under the August 2017 Receivables Settlement Agreement. The main reason for the change is to improve comparability with peer companies and to show the Company’s share of production before the government take.
  
  International petroleum consultants DeGolyer and MacNaughton carried out an independent assessment of the Tawke and Baeshiqa licenses in Kurdistan. Gaffney, Cline & Associates carried out an independent assessment of DNO’s licenses in Norway and the United Kingdom.
  
  The 2021 Annual Statement of Reserves and Resources, prepared and published today in accordance with Oslo Stock Exchange listing and disclosure requirements (Circular No. 1/2013), is attached and is also available on the Company’s website www.dno.no.
  
  –
  
  For further information, please contact:
  Media: media@dno.no
  Investors: investor.relations@dno.no
  
  –
  
  DNO ASA is a Norwegian oil and gas operator focused on the Middle East and the North Sea. Founded in 1971 and listed on the Oslo Stock Exchange, the Company holds stakes in onshore and offshore licenses at various stages of exploration, development and production in the Kurdistan region of Iraq, Norway, the United Kingdom, Netherlands, Ireland and Yemen.
  
  This information is subject to the disclosure requirements pursuant to section 5-12 of the Norwegian Securities Trading Act.
  
  https://www.yahoo.com/now/dno-releases-2021-annual-statement-060000011.html
DNO logs 321 mmboe of reserves, 34 mmboe output in 2021

DNO - February 23, 2022
- DNO ASA, the Norwegian oil and gas operator, has recorded 321 million barrels of oil equivalent (mmboe) of net proven and probable (2P) reserves in 2021 and production of 34 mmboe during the year.
  
  The company’s 2P reserves life stood at 9.3 years. Combined with contingent (2C) resources of 189 mmboe, DNO’s reserves and resources life stood at 14.8 years.
  
  Of the total, its Kurdistan portfolio accounted for 267 million barrels of oil (mmbbls) of net 2P reserves compared to 295 mmbbls in 2020, and 71 mmbbls of net 2C resources compared to 27 mmbbls at year-end 2020.
  
  Across its North Sea portfolio at year-end 2021, DNO’s net 2P reserves stood at 54 mmboe compared to 64 mmboe a year earlier. 2C resources totalled 113 mmboe compared to 120 mmboe at yearend 2020.
  
  Effective from 2021, the company reports its net production, reserves and resources based on the participation interest in all of its licences.
  
  Prior to 2021 and for the licences governed by Production Sharing Contracts, the company reported its net figures after royalty and included DNO’s additional share of cost oil covering its advances towards the government carried interest (if any) as well as volumes attributed to the three percent of gross Tawke licence production under the August 2017 Receivables Settlement Agreement.
  
  The main reason for the change is to improve comparability with peer companies and to show the company’s share of production before the government take.
  
  International petroleum consultants DeGolyer and MacNaughton carried out an independent assessment of the Tawke and Baeshiqa licences in Kurdistan. Gaffney, Cline & Associates carried out an independent assessment of DNO’s licences in Norway and the UK.– TradeArabia News Service
  
  http://www.tradearabia.com/news/OGN_393290.html

Frontera Announces 2021 Year End Reserves

Frontera Energy Corporation - February 17, 2022

2021 2P RESERVES OF 167 MILLION BOE
WITH NET PRESENT VALUE BEFORE TAX OF $3.0 BILLION

REPLACED 157% NET 1P AND 105% NET 2P RESERVES

ADDED 13.1 MMBOE NET 2P RESERVES

INCREASED NET 2P NATURAL GAS AND ASSOCIATED NATURAL GAS LIQUIDS
RESERVES BY 105% TO 19.1 MMBOE,
FURTHER DIVERSIFYING FRONTERA’S FUTURE PRODUCTION MIX

EXTENDED NET 1P RESERVES LIFE INDEX TO 8.7 YEARS AND 2P TO 13.3 YEARS

CALGARY, AB, Feb. 16, 2022 /PRNewswire/ – Frontera Energy Corporation (TSX: FEC) (“Frontera” or the “Company“) today announced the results of its annual independent reserves assessment conducted by DeGolyer and MacNaughton (“D&M“). All dollar amounts in this news release and the Company’s financial disclosures are in United States dollars, unless otherwise noted. All of the Company’s booked reserves for the year ended December 31, 2021 are located in Colombia and Ecuador.

Orlando Cabrales, Chief Executive Officer, commented:

“Frontera delivered solid reserves results in 2021. The Company replaced 157% of net 1P reserves and 105% of net 2P reserves, and extended our net 1P reserves life index to 8.7 years and our net 2P reserves life index to 13.3 years. We also increased net 2P natural gas and associated natural gas liquids reserves by 105% to 19.1 MMboe, further diversifying Frontera’s future production mix. The net present value (10% discount) on December 31, 2021 of the Company’s 2P reserves increased by 61% to $3.036 billion before tax and $2.248 billion after tax due in part to higher Brent prices year over year and greater operational and development cost stability.”

2021 Reserves Report Highlights:

For the year ended December 31, 2021, Frontera:

Added 13.1 MMboe of 2P net reserves, slightly increasing the Company’s 2P net reserves to 167.0 MMboe, compared to 166.4 MMboe at December 31, 2020. The Company’s 167 MMboe of net 2P reserves consist of 62% heavy crude oil, 27% light and medium crude oil and 7% conventional natural gas and 4% natural gas liquids.
Achieved a 1P net Reserves Replacement Ratio of 157% and a net 2P Reserve Replacement Ratio of 105%.
Extended 1P reserves life index to 8.7 years compared to 6.4 years at December 31, 2020.
Extended 2P reserves life index to 13.3 years compared to 10.3 years at December 31, 2020.
Added 7.8 MMboe of 3P net reserves, for a total of 217.1 MMboe at December 31, 2021, slightly lower compared to 221.8 MMboe at December 31, 2020.
Achieved a three-year average finding and development (“F&D“) cost of $8.50/boe on a 2P basis ($3.38/boe in 2020) with upstream reserves-based capital expenditures of $187 million ($101 million in 2020), not including changes in future development costs (“FDC”). 1P F&D cost three-year average was $9.80/boe in 2021 compared to $7.38/boe in 2020.
Increased 2P reserves on a gross working interest basis before royalties by 2% to 178.2 MMboe compared to 174.0 MMboe at December 31, 2020. Delivered 3P reserves on a gross working interest basis before royalties of 229.8 MMboe compared to 230.4 MMboe at December 31, 2020.
The Net Present Value (“NPV“) for the net 2P reserves, discounted at 10% before tax, is $3.036 billion at December 31, 2021, compared to $1.888 billion at December 31, 2020. The increase in NPV for the 2P reserves is primarily due to higher commodity prices at December 31, 2020 and improved development and operational cost stability. See the Net Present Value After Tax summary table below for more information.

About The Reserves Evaluation

For the year ended December 31, 2021, the Company’s reserves were evaluated by D&M, in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter) (“COGEH“) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101“) and are based on the Company’s 2021 year-end estimated reserves as evaluated by D&M in their report dated February 9, 2022, with an effective date of December 31, 2021 (the “Reserves Report“). D&M is an independent qualified reserves evaluator as defined in NI 51-101.

Additional reserves information as required under NI 51-101 will be included in the Company’s statement of reserves data and other oil and gas information on Form 51-101F1, which is expected to be filed on SEDAR on March 2, 2022. See “Advisory Note Regarding Oil and Gas Information” section in the “Advisories“, at the end of this news release.

Reserves data related to the El Dificil, Rio Meta and Entrerrios assets acquired by Frontera upon its acquisition of 100% of the common shares of Petroleos Sud Americanos S.A. (“PetroSud“) on December 30, 2021, have been included in the Reserves Report. The Reserves Report also includes results from the Company’s Jandaya-1 exploration well in the Perico block, in Ecuador (Frontera 50% W.I., operator). Numbers in tables may not add due to rounding differences.

2021 Year-End D&M Certified Gross Reserves Volumes⁽¹⁾

Reserves Category	December 31, 2021 MBoe ⁽²⁾	December 31, 2020 MBoe ⁽²⁾	Percentage Change 2021 versus 2020
Proved Developed Producing (PDP)	31,778	27,301	16%
Proved Developed Not Producing (PDNP)	10,461	10,015	4%
Proved Undeveloped (PUD)	76,045	70,685	8%
Total Proved (1P)	118,284	108,001	10%
Probable	59,957	66,017	(9)%
Total Proved Plus Probable (2P)	178,241	174,018	2%
Possible ⁽³⁾	51,559	56,378	(9)%
Total Proved Plus Probable Plus Possible (3P)	229,799	230,396	0%

⁽¹⁾Gross reserves represent Frontera’s W.I. before royalties.

⁽²⁾ See “Boe Conversion” section in the “Advisories”, at the end of this press release.

⁽³⁾ 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.

2021 Year-End D&M Certified Net Reserves Volumes⁽¹⁾

Reserves Category	December 31, 2021 Mboe ⁽²⁾	December 31, 2020 Mboe ⁽²⁾	Percentage Change 2021 versus 2020
Proved Developed Producing (PDP)	29,640	25,955	14%
Proved Developed Not Producing (PDNP)	9,483	9,395	1%
Proved Undeveloped (PUD)	70,224	66,845	5%
Total Proved (1P)	109,346	102,195	7%
Probable	57,670	64,203	(10)%
Total Proved Plus Probable (2P)	167,016	166,399	0%
Possible ⁽³⁾	50,055	55,420	(10)%
Total Proved Plus Probable Plus Possible (3P)	217,071	221,818	(2)%

⁽¹⁾Net reserves represent Frontera’s W.I. after royalties.

⁽²⁾ See “Boe Conversion” section in the “Advisories”, at the end of this press release.

The following tables provide a summary of the Company’s oil and natural gas reserves based on forecast prices and costs effective December 31, 2021, as applied in the Reserves Report. The Company’s net reserves after royalties at December 31, 2021, incorporate all applicable royalties under Colombia and Ecuador fiscal legislations based on forecast pricing and production rates evaluated in the Reserves Report, including any additional participation interest related to the price of oil applicable to certain Colombian and Ecuadorian blocks, as at year-end 2021.

2021 Year-End D&M Certified Reserves Volumes by Product Type and Country⁽⁶⁾

Reserves at December 31, 2021 (MMboe) ⁽¹⁾⁽⁵⁾
Country	Field	Proved (1P)		Probable		Proved plus Probable (2P)		Hydrocarbon Type
Country	Field	Gross	Net	Gross	Net	Gross	Net	Hydrocarbon Type
Colombia	Quifa SW field	48.3	42.2	6.0	5.2	54.3	47.3	Heavy crude oil
	Other heavy oil blocks⁽²⁾	35.1	33.8	22.1	21.7	57.1	55.4	Heavy crude oil
	Light/medium oil blocks⁽³⁾	25.8	24.5	20.1	19.3	46.0	43.8	Light and medium crude oil
	Natural gas blocks⁽⁴⁾	6.5	6.5	5.8	5.8	12.4	12.4	Conventional natural gas
	Natural gas blocks⁽⁴⁾	1.6	1.6	5.1	5.1	6.7	6.7	Natural gas liquids
	Sub-Total	117.4	108.6	59.1	57.0	176.5	165.6	Oil and natural gas
Ecuador	Perico block	0.9	0.8	0.8	0.7	1.8	1.4	Light and medium crude oil
	Total Dec. 31, 2021	118.3	109.3	60.0	57.7	178.2	167.0	Oil and natural gas
	Total Dec. 31, 2020	108.0	102.2	66.0	64.2	174.0	166.4
	Difference	10.3	7.2	(6.1)	(6.5)	4.2	0.6
	2021 Production	13.7	12.5	Total Reserves Incorporated		17.9	13.1

⁽¹⁾ See “Boe Conversion” section in the “Advisories”, at the end of this press release.

⁽²⁾ Includes Cajua and Jaspe fields in Quifa Block and Sabanero and CPE-6 blocks.

⁽³⁾ Includes Cubiro, Cravoviejo, Canaguaro, Guatiquia, Casimena, Corcel, Neiva, Cachicamo and other producing blocks.

⁽⁴⁾ Includes VIM-1, El Difícil and La Creciente Blocks.

⁽⁵⁾ Gross refers to Frontera’s W.I. before royalties. Net refers to Frontera’s W.I. after royalties.

⁽⁶⁾ All of the Company’s booked reserves are located in Colombia and Ecuador.

2021 2P Reserves Reconciliation

	Oil Equivalent Gross 2P Reserves (MMboe)⁽¹⁾⁽²⁾	Oil Equivalent Net 2P Reserves (MMboe)⁽¹⁾⁽²⁾
December 31, 2020	174.0	166.4
Net Additions ⁽³⁾	5.6	5.0
Economic and Technical Revisions	6.1	2.1
Acquisitions/Dispositions	6.1	6.1
Production ⁽⁴⁾	13.7	12.5
December 31, 2021	178.2	167.0

⁽¹⁾ See “Boe Conversion” section in the “Advisories”, at the end of this press release.

⁽²⁾ Gross refers to Frontera’s W.I. before royalties. Net refers to Frontera’s W.I. after royalties.

⁽³⁾ Includes discovery of Jandaya field (Perico Block in Ecuador), extensions and improved recoveries (including improved recoveries of Coralillo and Copa fields (Guatiquia and Cubiro blocks in Colombia).

⁽⁴⁾ Production represents the production for the twelve-month period ended December 31, 2021 for assets with associated reserves. Production associated with exploration and evaluation assets are included in production volumes for financial reporting purposes.

Five Year Crude Oil Price Forecast – D&M Reserves Reports ⁽¹⁾

(US$/bbl)	2022	2023	2024	2025	2026
Brent Oil Price Forecast 2020	52.85	56.04	57.87	59.00	60.15
Brent Oil Price Forecast 2021	75.33	71.46	69.62	71.01	72.44

⁽¹⁾ The Reserves Report and the December 31, 2020 reserves report used the average Brent projected price of three major international independent auditors: GLJ Petroleum Consultants, McDaniel and Associates Consultants and Sproule Consultants. The 2020 price forecast reflects prices used in the Company’s December 31, 2020 reserves report and the 2021 price forecast reflects prices used in the Reserves Report.

Reserve Life Index (“RLI”)⁽¹⁾

(US$/bbl)	December 31, 2020⁽²⁾	December 31, 2021⁽³⁾
Total Proved (1P)	6.4 years	8.7 years
Total Proved Plus Probable (2P)	10.3 years	13.3 years
Total Proved Plus Probable Plus Possible (3P)	13.8 years	17.3 years

⁽¹⁾ RLI does not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

⁽²⁾ Calculated by dividing the total relevant net reserves category by the 2020 production of 16.1 MMboe.

⁽³⁾ Calculated by dividing the total relevant net reserves category by the 2021 production of 12.5 MMboe.

Net Present Value Before Tax Summary – D&M Reserves Report (2021 Brent Forecast)⁽¹⁾

Reserves Category	December 31, 2020	December 31, 2021	December 31, 2021
$ (000’s), except per share data	NPV10 ($ 000’s)⁽²⁾	NPV10 ($ 000’s)⁽³⁾	NPV10 (C$/share)⁽⁴⁾
Proved Developed Producing (PDP)	367,237	773,686	10.11
Proved Developed Not Producing (PDNP)	153,073	235,503	3.08
Proved Undeveloped	549,355	1,100,986	14.34
Total Proved (1P)	1,114,666	2,110,176	27.56
Probable	773,015	926,177	12.10
Total Proved Plus Probable (2P)	1,887,681	3,036,353	39.66
Possible ⁽⁵⁾	669,312	894,668	11.69
Total Proved Plus Probable Plus Possible (3P)	2,556,993	3,931,021	51.34

⁽¹⁾ See “Advisories” at the end of this press release. The Reserves Report used the average Brent projected price of three major international independent auditors: GLJ Petroleum Consultants, McDaniel and Associates Consultants and Sproule Consultants. The January 1, 2021 price forecast is included in the December 31, 2020 reserves report.

⁽²⁾ Includes FDC as at December 31, 2020, of $808 million for 1P and $1,309 million for 2P.

⁽³⁾ Includes FDC as at December 31, 2021, of $792 million for 1P and $1,269 million for 2P.

⁽⁴⁾ Calculated by dividing the December 31, 2021 NPV10 value by 94,695,694 shares outstanding as at December 31, 2021 and a USD:CAD foreign exchange rate of 1.26:1. Per share valuations do not consider any value attributed to the Company’s material ownership in midstream and infrastructure assets as well as any equity value for its ownership in CGX Energy Inc. (TSXV:OYL).

⁽⁵⁾ Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Net Present Value After Tax Summary – D&M Reserves Report (2021 Brent Forecast)⁽¹⁾⁽²⁾

Reserves Category	December 31, 2020	December 31, 2021	December 31, 2021
$ (000’s), except per share data	NPV10 ($ 000’s)⁽³⁾	NPV10 ($ 000’s)⁽⁴⁾	NPV10 (C$/share)⁽⁵⁾
Proved Developed Producing (PDP)	344,170	608,715	7.95
Proved Developed Not Producing (PDNP)	143,415	187,470	2.45
Proved Undeveloped	556,317	862,350	11.26
Total Proved (1P)	1,043,903	1,658,535	21.66
Probable	522,958	589,523	7.70
Total Proved Plus Probable (2P)	1,566,860	2,248,058	29.36
Possible ⁽⁶⁾	451,961	570,597	7.45
Total Proved Plus Probable Plus Possible (3P)	2,018,822	2,818,655	36.82

⁽¹⁾ See “Advisories” at the end of this press release. The Reserves Report used the average Brent projected price of three major international independent auditors: GLJ Petroleum Consultants, McDaniel and Associates Consultants and Sproule Consultants. The full January 1, 2022 price forecast will be included in the Reserves Report.

⁽²⁾ The tax calculations used in the preparation of the Reserves Report are done at the field level in accordance with standard practice, and do not reflect the actual tax position at the corporate level which may be significantly different.

⁽³⁾ Includes FDC as at December 31, 2020 of $808 million for 1P and $1,309 million for 2P.

⁽⁴⁾ Includes FDC as at December 31, 2021, of $792 million for 1P and $1,269 million for 2P.

⁽⁵⁾ Calculated by dividing the December 31, 2021 NPV10 value by 94,695,694 shares outstanding as at December 31, 2021 and a USD:CAD foreign exchange rate of 1.26:1. Per share valuations do not consider any value attributed to the Company’s material ownership in midstream and infrastructure assets as well as any equity value for its ownership in CGX Energy Inc. (TSXV:OYL).

⁽⁶⁾ Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Calculation of Three-Year Reserve Metrics – Net

	Proved (1P)	Proved Plus Probable (2P)
Capital Expenditures ($ 000’s)⁽¹⁾	577,113	577,113
Reserve Additions (000’s boe)⁽²⁾	58,915	68,149
F&D Costs ($/boe)⁽³⁾	9.8	8.5

⁽¹⁾ Calculated using actual capital expenditures for the period from January 1, 2019 to December 31, 2021.

⁽²⁾ Net reserves additions of the Company in 2019 and 2021 and additions in Colombia in 2020.

⁽³⁾ The aggregate of the exploration and development costs incurred, generally will not reflect total F&D costs related to reserves additions for the period. F&D costs are calculated as capital expenditures divided by reserve additions for F&D Costs ($/boe). The measure “F&D costs” does not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

Future Development Costs (FDC) – Based on Forecast Prices and Costs

Colombia ($ 000’s)	Total Proved (1P)	Total Proved Plus Probable (2P)
2022	114,792	155,971
2023	116,702	191,306
2024	145,831	227,512
2025	98,499	144,668
2026	133,924	154,527
Beyond 2026	182,271	394,791
Total undiscounted	792,020	1,268,774

About Frontera:

Frontera Energy Corporation is a Canadian public company involved in the exploration, development, production, transportation, storage and sale of oil and natural gas in South America, including related investments in both upstream and midstream facilities. The Company has a diversified portfolio of assets with interests in 34 exploration and production blocks in Colombia, Ecuador and Guyana, and pipeline and port facilities in Colombia. Frontera is committed to conducting business safely and in a socially, environmentally and ethically responsible manner.

If you would like to receive news releases via email as soon as they are published, please subscribe here: http://fronteraenergy.mediaroom.com/subscribe.

Advisories:

Cautionary Note Concerning Forward-Looking Information

This news release contains forward-looking information within the meaning of Canadian securities laws. Forward-looking information relates to activities, events or developments that the Company believes, expects or anticipates will or may occur in the future. Forward-looking information in this news release includes, without limitation, statements regarding the Company’s statement of reserves data and other oil and gas information on Form 51-101F1, which is expected to be filed on SEDAR on March 2, 2022, information relating to reserves and resources, including reserves and resources estimates, reserve life index, reserve replacement ratio, price forecasts and future development costs. All information other than historical fact is forward-looking information.

Forward-looking information reflects the current expectations, assumptions and beliefs of the Company based on information currently available to it and considers the Company’s experience and its perception of historical trends, including expectations and assumptions relating to commodity prices and interest and foreign exchange rates; the current and potential adverse impacts of the COVID-19 pandemic, including the status of the pandemic and future waves and any associated policies around current business restrictions; reserves and resources estimates; the performance of assets and equipment; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour, services and infrastructure; and the development and execution of projects.

Although the Company believes that the assumptions inherent in the forward-looking information are reasonable, forward-looking information is not a guarantee of future performance and accordingly undue reliance should not be placed on such information. Forward-looking information is subject to a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to the Company. The actual results of the Company may differ materially from those expressed or implied by the forward-looking information, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: volatility in market prices for oil and natural gas; the duration and spread of the COVID-19 pandemic and its severity, the success of the Company’s program to manage COVID-19; uncertainties associated with estimating and establishing oil and natural gas reserves and resources; liabilities inherent with the exploration, development, exploitation and reclamation of oil and natural gas; uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; increases or changes to transportation costs; expectations regarding the Company’s ability to raise capital and to continually add reserves through acquisition and development; the Company’s ability to access additional financing; the ability of the Company to maintain its credit ratings; the ability of the Company to: meet its financial obligations and minimum commitments, fund capital expenditures and comply with covenants contained in the agreements that govern indebtedness; political developments in the countries where the Company operates; the uncertainties involved in interpreting drilling results and other geological data; geological, technical, drilling and processing problems; timing on receipt of government approvals; fluctuations in foreign exchange or interest rates and stock market volatility. The Company’s annual information form dated March 3, 2021, its annual management’s discussion and analysis for the year ended December 31, 2020, and other documents it files from time to time with securities regulatory authorities describe the risks, uncertainties, material assumptions and other factors that could influence actual results and such factors are incorporated herein by reference. Copies of these documents are available without charge by referring to the company’s profile on SEDAR at www.sedar.com. All forward-looking information speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking information, whether as a result of new information, future events or results or otherwise.

Non-Standardized Measures

This news release includes non-standardized measures. Readers are cautioned that these measures, such as reserve life index, reserves replacement ratio, NPV per share and F&D costs, should not be construed as alternative measures of financial performance. Such measures have been included to provide readers with additional means to evaluate the Company’s performance but these non-standardized measures are not reliable indicators of the Company’s future performance and therefore must not be relied upon unduly. The Company’s method of calculating these measures may differ from other companies and, accordingly, they may not be comparable to similar measures used by other companies. Readers are cautioned that the information provided or derived by these measures should not be relied upon for investment purposes.

Advisory Note Regarding Oil and Gas Information

The reserves information contained in this press release has been prepared in accordance with NI 51-101 but only presents a portion of the disclosure required thereunder. Complete reserves disclosure required in accordance with NI 51-101 will be available on SEDAR at www.sedar.com on or around March 2, 2022. Actual oil and natural gas reserves and future production may be greater than or less than the estimates provided in this news release. There is no assurance that forecast prices and costs assumed in the Reserves Report, and presented in this news release, will be attained and variances from such forecast prices and costs could be material. The estimated future net revenue from the production of the disclosed oil and natural gas reserves in this news release does not represent the fair market value of these reserves.

The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary.

The Company’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. All evaluations and reviews of future net revenue are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The tax calculations used in the preparation of the Reserves Report are done at the field level in accordance with standard practice, and do not reflect the actual tax position at the corporate level which may be significantly different.

Boe Conversion

The term “boe” is used in this news release. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of cubic feet to barrels is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In this news release, boe has been expressed using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy. In addition, as the value ratio between oil and natural gas based on current market values is significantly different from the energy equivalency of 5.7:1, utilizing a conversion of 5.7:1 may be misleading as an indication of value.

Definitions:

1P	Proved reserves
2P	Proved plus probable reserves
3P	Proved plus probable plus Possible reserves
bbl(s)	Barrel(s) of oil
boe	Refer to “Boe Conversion” disclosure above
boe/d	Barrel of oil equivalent per day
Gross Production	Refers to means working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Company
Mboe	Thousand barrels of oil equivalent
MMboe	Million barrels of oil equivalent
Mcf	Thousand cubic feet
Net Production	Refers to working interest (operating or non-operating) share after deduction of royalty obligations, plus the Company’s royalty interests in production or reserves
W.I.	Working interest

“Proved Developed Producing Reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been in production, and the date of resumption of production must be known with reasonable certainty.
“Proved Developed Non-Producing Reserves” are those reserves that either have not been on production or have previously been on production but are shut-in and the date of resumption of production is unknown.
“Proved Undeveloped Reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.
“Proved” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
“Probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
“Possible” reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
“Reserves Life Index” (RLI) is calculated as the net reserves in the referenced category divided by the net production of the last year. It is a measure of how long the booked reserves will last if the production rate is maintained and no additional reserves are added.
“Reserves Replacement Ratio” is calculated as the net reserves added in the referenced category divided by the net production of the last year. It is a measure of the capacity to replace the production.
“F&D costs” are calculated as capital expenditures divided by reserve additions for F&D Costs ($/boe). This measure does not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

https://www.prnewswire.com/news-releases/frontera-announces-2021-year-end-reserves-301484389.html

The Ecopetrol Group achieved a Reserve-Replacement Ratio of 200% in 2021, the highest in the last 12 years

Ecopetrol S.A. - February 9, 2022

BOGOTA, Colombia, Feb. 7, 2022 /PRNewswire/ — Ecopetrol S.A. (BVC: ECOPETROL, NYSE: EC) announced today its consolidated proven oil, condensate, and natural gas reserves (1P reserves, according to the standard international denomination), which include the results of Ecopetrol S.A. and its subsidiaries, as of December 31, 2021.

Reserves were estimated based on the United States Securities and Exchange Commission (SEC) standards and methodology. 99.5% of the reserves were certified by four independent specialized firms (Ryder Scott Company, DeGolyer and MacNaughton, Gaffney, Cline & Associates, and Sproule International Limited).

The SEC-defined price used for the 2021 valuation of reserves was USD 69.2 per barrel of Brent versus USD 43.4 per barrel of Brent in 2020.

At the end of 2021, the net proven reserves of the Ecopetrol Group were 2,002 MBOE. The Reserve-Replacement Ratio was 200% and the average reserve life was equivalent to 8.7 years.

In 2021, the Ecopetrol Group incorporated 462 MBOE of proven reserves and the total accumulated production was 231 MBOE. Of the total balance of reserves, 72% are liquid reserves, with an average life of 8.2 years, while the remaining 28% are gas reserves, with an average life of 10.4 years.

Of the 462 MBOE incorporated, 61% (282 MBOE) was primarily a result of performance within development fields, optimal and timely maturity of new projects, and greater capacity to execute and implement enhanced recovery expansion projects in fields such as Chichimene, Castilla, and Akacias, among others. The remaining volumes correspond primarily to the favorable effect of the recovery of international oil prices during 2021.

As a result of Ecopetrol’s sale of Savia Peru effective as of January 2021, a disincorporation of said company’s reserves was carried out for 3.5 MBOE.

83% of the proven reserves are owned by Ecopetrol S.A., while the other Ecopetrol Group companies contributed with 17% of the 2,002 MBOE, mainly due to the operation of Ecopetrol Permian and Ecopetrol America in the United States.

The 13% increase achieved in reserves in 2021 demonstrates the strength of the Ecopetrol Group’s hydrocarbon portfolio, which supports the company’s sustainable growth path within its energy transition strategy.

Ecopetrol Group’s Proved Reserves 2021

Proven Reserves 1P	MBOE
Proven Reserves as of Dec 31, 2020	1,770
Revisions	315
Mineral Purchases	0
Enhanced Recovery	139
Extensions y Discoveries	12
Mineral Sales	-3.5
Production	-231
Proven Reserves as of Dec 31, 2021	2,002

Ecopetrol is the largest company in Colombia and one of the main integrated energy companies in the American continent, with more than 17,000 employees. In Colombia, it is responsible for more than 60% of the hydrocarbon production of most transportation, logistics, and hydrocarbon refining systems, and it holds leading positions in the petrochemicals and gas distribution segments. With the acquisition of 51.4% of ISA’s shares, the company participates in energy transmission, the management of real-time systems (XM), and the Barranquilla – Cartagena coastal highway concession. At the international level, Ecopetrol has a stake in strategic basins in the American continent, with Drilling and Exploration operations in the United States (Permian basin and the Gulf of Mexico), Brazil, and Mexico, and, through ISA and its subsidiaries, Ecopetrol holds leading positions in the power transmission business in Brazil, Chile, Peru, and Bolivia, road concessions in Chile, and the telecommunications sector. This press release contains business prospect statements, operating and financial result estimates, and statements related to Ecopetrol’s growth prospects. These are all projections and, as such, they are based solely on the expectations of the managers regarding the future of the company and their continued access to capital to finance the company’s business plan. The realization of said estimates in the future depends on the behavior of market conditions, regulations, competition, the performance of the Colombian economy and the industry, among other factors, and are consequently subject to change without prior notice.

This release contains statements that may be considered forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended. All forward-looking statements, whether made in this release or in future filings or press releases or orally, address matters that involve risks and uncertainties, including in respect of the Company’s prospects for growth and its ongoing access to capital to fund the Company’s business plan, among others. Consequently, changes in the following factors, among others, could cause actual results to differ materially from those included in the forward-looking statements: market prices of oil & gas, our exploration, and production activities, market conditions, applicable regulations, the exchange rate, the Company’s competitiveness and the performance of Colombia’s economy and industry, to mention a few. We do not intend and do not assume any obligation to update these forward-looking statements.

For more information, please contact:

Head of Capital Markets
Tatiana Uribe Benninghoff
Email: investors@ecopetrol.com.co

Head of Corporate Communications
Mauricio Téllez
Email: mauricio.tellez@ecopetrol.com.co

^[1] Million Barrels of Oil Equivalent

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SOURCE Ecopetrol S.A.

https://www.yahoo.com/now/ecopetrol-group-achieved-replacement-ratio-230700038.html

GeoPark Announces Consolidated 2021 Certified 2P Reserves of 159 Million BOE With Net Present Value (After Tax) of $2.3 Billion

GeoPark - February 1, 2022

BOGOTA, Colombia–(BUSINESS WIRE)–GeoPark Limited (“GeoPark” or the “Company”) (NYSE: GPRK), a leading independent Latin American oil and gas explorer, operator and consolidator, today announced its independent oil and gas reserves assessment, certified by DeGolyer and MacNaughton (D&M), under PRMS methodology, as of December 31, 2021.

All reserves included in this release refer to GeoPark working interest reserves before royalties paid in kind, except when specified. All figures are expressed in US Dollars. Definitions of terms are provided in the Glossary on page 12.

2021 Year-End D&M Certified Oil and Gas Reserves and Highlights:

Building on GeoPark’s core base in the Llanos 34 (GeoPark operated, 45% WI) and CPO-5 (GeoPark non-operated, 30% WI) blocks, the Company reports:

Colombia Reserves

PD Reserves: Proven developed (PD) reserves in Colombia of 49.9 mmboe, with a PD reserve life index (RLI) of 4.4 years
1P Reserves: Proven (1P) reserves in Colombia of 82.2 mmboe, with a 1P RLI of 7.2 years. Net present value after tax discounted at 10% (NPV10 after tax) of 1P reserves of $1.3 billion
2P Reserves: Proven and probable (2P) reserves in Colombia of 135.8 mmboe, with a 2P RLI of 11.9 years. NPV10 after tax of 2P reserves of $2.0 billion
3P Reserves: Proven, probable and possible (3P) reserves in Colombia of 211.0 mmboe, with a 3P RLI of 18.5 years. NPV10 after tax of 3P reserves of $2.9 billion
Development Capital: Future development capital to develop 1P, 2P and 3P reserves in Colombia of $1.9 per barrel, $1.7 per barrel and $1.6 per barrel, respectively
Llanos 34 Block: Low risk development and new field extensions with reserve upside potential to be tested in 2022
- Net PD reserve additions of 12.0 mmbbl (a 131% PD reserve replacement)
- Net 2P reserve additions of 7.3 mmbbl (a 78% 2P reserve replacement)
- Net 3P reserve additions of 9.5 mmbbl (a 100% 3P reserve replacement)
- 1P RLI of 7.9 years, 2P RLI of 11.5 years and 3P RLI of 16.0 years
- Average gross production in 2021 was 55,971 bopd with an exit rate above 60,000 bopd
CPO-5 Block¹: Continued strong reservoir performance in the Indico oil field
- Net 1P reserves of 5.1 mmbbl, Net 2P reserves of 20.0 mmbbl and Net 3P reserves of 48.8 mmbbl (1P RLI of 3.6 years, 2P RLI of 14.7 years and 3P RLI of 36.1 years)
- The 2021 drilling campaign initiated in December 2021 with the spud of the Indico 4 development well
- The operator, ONGC Videsh, is accelerating drilling activities in 2022 targeting to drill 7-8 gross wells (1-2 development wells and 6-7 exploration wells) with two contracted drilling rigs

Consolidated Reserves²

PD Reserves: PD reserves of 58.1 mmboe, with a PD RLI of 4.2 years
1P Reserves: 1P reserves of 91.6 mmboe, with a 1P RLI of 6.7 years. NPV10 after tax of 1P reserves of $1.4 billion
2P Reserves: 2P reserves of 159.2 mmboe, with a 2P RLI of 11.6 years. NPV10 after tax of 2P reserves of $2.3 billion
3P Reserves: 3P reserves of 248.3 mmboe, with a 2P RLI of 18.1 years. NPV10 after tax of 3P reserves of $3.4 billion
Future Development Capital: Future development capital to develop 1P, 2P and 3P reserves of $2.0 per barrel, $2.3 per barrel and $2.2 per barrel, respectively
Portfolio Management: Divestment of non-core Aguada Baguales, El Porvenir and Puesto Touquet (GeoPark operated, 100% WI) blocks in Argentina and of the Manati gas field (GeoPark non-operated, 10% WI) in Brazil are currently underway, representing 100% of GeoPark’s reserves in Argentina and Brazil
- Excluding reserves from Argentina and Brazil, GeoPark’s consolidated reserves would amount to 53.7 mmboe, 86.6 mmboe, 153.1 mmboe and 241.4 mmboe of PD, 1P, 2P and 3P reserves, respectively

Net Present Value and Value Per Share

GeoPark’s 2P NPV10 after tax of $2.3 billion
GeoPark’s net debt-adjusted 2P NPV10 after tax of $28.9 per share ($24.0 per share corresponding to Colombia)

____________

¹ GeoPark non-operated, 30% WI, ONGC Videsh operated, 70% WI.

² Consolidated figures include reserves in the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina and in the Manati gas field in Brazil that are being divested. The Argentina transaction is expected to close in late January or early February 2022, whereas the Brazil transaction is still subject to several conditions that should be met before March 31, 2022 and that have not been met as of the date of this release.

2022 Work Program: Superior Free Cash Flow³ Plus Multiple Catalysts to Grow Production and Test High Potential Prospects

Self-funded 2022 capital expenditures program of $160-180 million to drill 40-48 gross wells, including an extensive exploration drilling program of 15-20 gross wells that targets high-potential, short-cycle and near-field projects adjacent to the Llanos 34 block plus other exploration targets in Colombia and Ecuador

At $65-70/bbl Brent the program would generate $90-140 million free cash flow, or 11-18% free cash flow yields
At $75-80/bbl Brent the program would generate $170-210 million free cash flow, or 21-26% free cash flow yields
At $80-85/bbl Brent the program would generate $210-250 million free cash flow, or 26-32% free cash flow yields
GeoPark intends to use free cash flow for continued deleveraging, incremental shareholder returns through cash dividends and share buybacks, and other corporate purposes, subject to prevailing oil price conditions in 2022

Recent Events (Not included in the 2021 Year-End D&M Certification)

Perico Block (GeoPark non-operated, 50% WI): In January 2022, GeoPark announced its first discovery in Ecuador after drilling and testing the Jandaya 1 exploration well. Initial production tests had a rate of 750 bopd of 28 degrees API and 0.8 mmcfpd, for a combined 890 boepd. Production is already tied-in and being delivered. The second exploration well, Tui 1, has spudded and is expected to reach TD in late February 2022
CPO-5 Block: The Indico 4 development well was spudded in December 2021 and tested in January 2022. Initial tests showed a production rate of 3,840 bopd (on a restricted 32/64 inch choke) of light oil (35 degrees API) with an estimated payback of approximately 2 months⁴. Oil production is already tied-in and being delivered. Rig down activities are currently underway and the operator is expecting to spud the Indico 5 development well in February 2022

James F. Park, Chief Executive Officer of GeoPark, said: “Thanks and congratulations to our team for these strong 2021 results – in a year with little exploration investment. Once again, we were able to continue developing and adding reserves in our core and big cash-generating Llanos 34 block where we replaced 131% of Proven Developed, 79% of 2P and 100% of 3P reserves. Our large profitable reserve base in Colombia provides us with a steady growth fairway and large inventory of low-risk, low-cost development drilling projects to continue generating and growing production and cash flow. On top of this secure foundation, we have just kicked off our 2022 work program with an extensive drilling campaign of 40-48 wells, including 15-20 low-cost exploration wells on our high-impact proven acreage that can quickly be converted to production and cash flow, as demonstrated by our recent discovery in Ecuador and the new development well in the CPO-5 block.”

____________

³ Please refer to section “2022 Free Cash Flow Calculation and Sensitivities to Different Brent Oil Prices” included in this press release.

⁴ Assuming $75-80/bbl Brent.

2020 Year-End to 2021 Year-End D&M Certified Reserves Evolution

Colombia (mmboe)	PD	1P	2P	3P
2020 Year-End Reserves	48.0	95.2	141.0	216.4
2021 Production	-11.4	-11.4	-11.4	-11.4
Net Change⁵	13.3	-1.7	6.2	6.0
2021 Year-End Reserves	49.9	82.2	135.8	211.0
2021 Reserve Life (years)	4.4	7.2	11.9	18.5
2020 Reserve Life (years)	3.9	7.8	11.6	17.8

Total (mmboe)	PD	1P	2P	3P
2020 Year-End Reserves	58.5	109.3	174.7	270.9
2021 Production	-13.7	-13.7	-13.7	-13.7
Net Change⁵	13.3	-4.0	-1.8	-8.9
2021 Year-End Reserves	58.1	91.6	159.2	248.3
2021 Reserve Life (years)	4.2	6.7	11.6	18.1
2020 Reserve Life (years)	4.0	7.4	11.9	18.4

Net Present Value per Share by Country

The table below presents GeoPark’s 2P NPV per share, by country, as of December 31, 2021.

2021 Net Present Value per Share	Colombia	Chile	Brazil	Argentina	Total⁶
2P Reserves (mmboe)	135.8	17.3	2.6	3.5	159.2
2P NPV10 after tax 2021 ($ mm)	2,019	223	51	20	2,313
Shares Outstanding (mm)	60.2	60.2	60.2	60.2	60.2
($/share)	33.5	3.7	0.8	0.3	38.4

The table below illustrates the details of the net debt adjusted 2P NPV10 after tax per share:

2021 Net Debt Adjusted 2P NPV10 After Tax per Share	Colombia	Total
2P NPV10 after tax ($ mm)	2,019	2,313
Shares Outstanding (mm)	60.2	60.2
Subtotal ($/share)	33.5	38.4
Net Debt^a/Share ($/share)	-9.5	-9.5
Net Debt Adjusted 2P NPV10 After Tax per Share ($/share)	24.0	28.9

____________

⁵ Includes extensions, improved recoveries, discoveries, technical revisions and economic factors.

⁶ Consolidated figures include reserves in the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina and in the Manati gas field in Brazil that are being divested. The Argentina transaction is expected to close in late January or early February 2022, whereas the Brazil transaction is still subject to several conditions that should be met before March 31, 2022 and that have not been met as of the date of this release.

(a) Net debt adjusted 2P NPV10 after tax per share is shown on a consolidated basis. Net debt considers financial debt of $674 million less $100 million of cash & cash equivalents (both figures unaudited and as of December 31, 2021).

Future Development Capital – D&M Report (Undiscounted)

The tables below present D&M’s best estimate of future development capital (undiscounted) and the unit value per boe by category of certified reserves as of December 31, 2021:

Colombia	PD	1P	2P	3P
Future Development Capital ($ mm)	23.1	154.8	225.7	333.4
Reserves (mmboe)	49.9	82.2	135.8	211.0
Future Development Capital ($/boe)	0.5	1.9	1.7	1.6

Total	PD	1P	2P	3P
Future Development Capital ($ mm)	23.1	187.4	361.9	541.7
Reserves (mmboe)	58.1	91.6	159.2	248.3
Future Development Capital ($/boe)	0.4	2.0	2.3	2.2

2021 Year-End Reserves Summary

Following oil and gas production of 13.7 mmboe in 2021, D&M certified 2P reserves of 159.2 mmboe (90% oil and 10% gas) as of December 31, 2021. By country, the 2P reserves were 85% in Colombia, 11% in Chile, 2% in Brazil and 2% in Argentina.

Reserves Summary by Country and Category

Country	Reserves Category	December 2021 (mmboe)	% Oil	December 2020 (mmboe)	% Change
Colombia	PD	49.9	100%	48.0	4%
	1P	82.2	100%	95.2	-14%
	2P	135.8	100%	141.0	-4%
	3P	211.0	100%	216.4	-2%
Chile	PD	3.8	23%	5.1	-25%
	1P	4.4	32%	7.3	-40%
	2P	17.3	30%	25.5	-32%
	3P	30.4	31%	44.2	-31%
Brazil	PD	2.5	2%	2.5	0%
	1P	2.5	2%	2.5	0%
	2P	2.6	2%	2.6	0%
	3P	2.8	2%	3.0	0%
Argentina	PD	2.0	60%	3.0	-33%
	1P	2.6	67%	4.3	-40%
	2P	3.5	63%	5.5	-36%
	3P	4.1	61%	7.3	-44%
Total⁷	PD	58.1	89%	58.5	-1%
(D&M Certified)	1P	91.6	93%	109.3	-16%
	2P	159.2	90%	174.7	-9%
	3P	248.3	90%	270.9	-8%

____________

⁷ Consolidated figures include reserves in the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina and in the Manati gas field in Brazil that are being divested. The Argentina transaction is expected to close in late January or early February 2022, whereas the Brazil transaction is still subject to several conditions that should be met before March 31, 2022 and that have not been met as of the date of this release.

Analysis by Country

Colombia

Llanos 34 block

The Llanos 34 block represented 89%, 78% and 70% of GeoPark 1P, 2P and 3P D&M certified reserves in Colombia, respectively.

GeoPark’s drilling plan in 2021 in its core Llanos 34 block was mainly focused on low risk development projects that resulted in net PD reserve additions with a reserve replacement of 131%, and to a lesser extent on successful field extensions that added 2P and 3P reserves and opened new development and appraisal drilling opportunities to be tested in 2022.

GeoPark’s 2P D&M certified reserves in the Llanos 34 block in Colombia totaled 105.8 mmbbl in 2021 compared to 107.7 mmbbl in 2020, resulting from 9.2 mmbbl production that was partially offset by 7.3 mmbbl of reserve additions due to field extensions in the Tigui area, with a reserve replacement of 79%.

As of December 31, 2021, the Llanos 34 block included approximately 68⁸ future development drilling locations (2P, gross).

The 1P RLI was 7.9 years, while the 2P RLI was 11.5 years.

Gross original oil in place in the Llanos 34 is estimated to be 0.8-1 billion barrels⁹. Cumulative production since 2012 to 2021 totaled 139 mmbbl gross, representing a recovery of 15% of the original oil in place, whereas the 2P reserves consider an ultimate recovery factor of approximately 40%.

CPO-5 block

The CPO-5 block is located to the southwest and is adjacent to and on trend with the Llanos 34 block. The block has 400-900 mmbbl gross recoverable exploration resources¹⁰, or 120-270 mmbbl net to GeoPark. During 2021, the operator, ONGC, acquired 250 sq km of 3D seismic in the central part of the block that is currently being interpreted and analyzed and which could add incremental exploration resources.

The CPO-5 block represented 6%, 15% and 23%, of GeoPark 1P, 2P and 3P D&M certified reserves in Colombia, respectively.

GeoPark’s 2P D&M certified reserves in CPO-5 totaled 20.0 mmbbl in 2021 compared to 21.2 mmbbl in 2020, reflecting 1.4 mmbbl production, partially offset by positive technical revisions due to strong reservoir performance in the Indico oil field in 2021.

The 1P RLI was 3.8 years, while the 2P RLI was 14.7 years.

The operator suffered delays in the execution of the 2021 drilling campaign in the CPO-5 block which started in mid-December 2021 with the spudding of the Indico 4 development well. The campaign originally included drilling of 5-6 gross wells, including development and exploration projects that were deferred to 2022.

The Indico 4 development well was spudded in December 2021 and initiated production tests in January 2022. The operator drilled and completed Indico 4 well to a total depth of 10,495 feet. Initial production tests show a production rate of 3,840 bopd of 35 degrees API, with a 0.25% water cut. Additional production history is required to determine stabilized flow rates of the well. Rig down activities are currently underway and the operator expects to spud the Indico 5 development well in February 2022.

____________

⁸ D&M best estimate.

⁹ D&M best estimate of 1P-3P gross original oil in place.

¹⁰ Corresponds to GeoPark’s aggregate Mean-P10 unrisked recoverable oil volumes in leads and prospects individually audited by Gaffney & Cline as of December 31, 2020.

The 2022 drilling campaign includes the drilling of 7-8 gross wells, including 1-2 development wells and 6-7 exploration wells. The exploration program targets high potential nearfield projects adjacent to and on trend with the Llanos 34 block. The drilling campaign is being executed with two drilling rigs, with one rig currently active in the block and the second to join in 1H2022.

Total Colombia (including reserves in the Llanos 34, CPO-5, Platanillo and Llanos 32 blocks)

GeoPark’s 2P D&M certified reserves in Colombia totaled 135.8 mmbbl in 2021 compared to 141.0 mmbbl in 2020, resulting from 11.4 mmboe production and negative technical revisions of 1.7 mmboe in the Llanos 32 block, partially offset by reserve additions in the Llanos 34 block and to a lesser extent, positive technical revisions in the CPO-5 and Platanillo blocks due to strong reservoir performance.

As of December 31, 2021, GeoPark blocks in Colombia included approximately 88¹¹ future development drilling locations (2P, gross).

The 1P RLI was 7.2 years, while the 2P RLI was 11.9 years.

Chile

GeoPark’s 2P D&M certified reserves in Chile totaled 17.3 mmboe in 2021 compared to 25.5 mmboe in 2020, with lower reserves resulting from negative revisions due to delayed development plans in smaller fields and oil and gas production of 0.9 mmboe.

The 1P RLI was 5.1 years and the 2P RLI was 19.8 years.

The Fell block represented 100% of GeoPark 2P D&M certified reserves in Chile.

The 2P D&M reserves in Chile were 30% oil and 70% gas.

The 2022 drilling campaign includes drilling of two gas wells in the Jauke/Dicky geological structure, targeting to spud the first well in March 2022.

Brazil

GeoPark’s 2P D&M certified reserves in Brazil totaled 2.5 mmboe compared to 2.6 mmboe in 2020, reflecting production of 0.7 mmboe during 2021 that was partially offset by positive technical revisions of 0.6 mmboe resulting from strong reservoir performance in the Manati gas field.

The 1P RLI was 3.5 years and the 2P RLI was 3.7 years.

The Manati field represented 100% of GeoPark Brazil 2P D&M certified reserves.

The 2P D&M reserves in Brazil were 2% oil and condensate, and 98% gas.

Manati Gas Field Divestment Process Update

In November 2020 GeoPark signed an agreement to sell its 10% non-operated WI in the Manati gas field to Gas Bridge S.A. for a total consideration of R$144.4 million (approximately $26 million at an exchange rate of R$5.5 per dollar), including a fixed payment of R$124.4 million plus an earn-out of R$20.0 million, subject to obtaining certain regulatory approvals.

The transaction is subject to several conditions that should be met before March 31, 2022 and that have not been met as of the date of this release.

____________

¹¹ D&M best estimate.

Argentina

GeoPark’s 2P D&M certified reserves in Argentina decreased to 3.5 mmboe in 2021 compared to 5.5 mmboe in 2020, resulting from delayed development plans, technical revisions and oil and gas production of 0.8 mmboe in 2021.

The 1P RLI was 3.4 years, while the 2P RLI was 4.6 years.

The Aguada Baguales, El Porvenir and Puesto Touquet blocks represented 100% of GeoPark Argentina 2P D&M certified reserves.

The 2P D&M reserves in Argentina were 63% oil and 37% gas.

Argentina Divestment Process Update

In November 2021, GeoPark accepted an offer to divest its non-core Aguada Baguales, El Porvenir and Puesto Touquet blocks for a total consideration of $16 million. The process is currently underway with closing expected in late January or early February 2022.

Net Present Value After Tax Summary

The table below details D&M certified NPV10 after tax as of December 31, 2021 as compared to 2020:

Country	Reserves Category	NPV10 After Tax 2021 ($ mm)	NPV10 After Tax 2020 ($ mm)
Colombia	1P	1,274	1,477
	2P	2,019	2,136
	3P	2,918	3,094
Chile	1P	52	71
	2P	223	291
	3P	409	533
Brazil	1P	46	27
	2P	52	29
	3P	54	32
Argentina	1P	12	28
	2P	20	38
	3P	28	45
Total¹²	1P	1,384	1,603
(D&M Certified)	2P	2,313	2,493
	3P	3,409	3,703

____________

¹² Consolidated figures include the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina and in the Manati gas field in Brazil that are being divested. The Argentina transaction is expected to close in late January or early February 2022, whereas the Brazil transaction is still subject to several conditions that should be met before March 31, 2022 and that have not been met as of the date of this release.

Oil Price Forecast

The price assumptions used to estimate the feasibility of PRMS reserves and NPV10 after tax in 2021 and 2020 D&M reports are detailed in the table below:

Brent Oil Price ($/bbl)	2022	2023	2024	2025	2026	2027 and forward
2021 Reserves Report	74.9	66.4	67.7	69.1	70.5	71.9-80.0
2020 Reserves Report	60.0	65.0	67.5	68.8	70.2	71.5-80.4

2022 Free Cash Flow Calculation and Sensitivities to Different Brent Oil Prices

The table below provides sensitivities to different Brent oil prices using the 2022 base work program:

2022 Free Cash Flow	(Base Case) $65-70 per bbl	$75-80 per bbl	$80-85 per bbl
(in $ million)
Operating Netback	$400-450	$480-530	$530-560
Adjusted EBITDA	$350-400	$430-480	$480-510
Cash Taxes	$40-45	$40-45	$40-45
Capital Expenditures	$160-180	$160-180	$160-180
Mandatory Debt Service Payments¹³	$38-42	$38-42	$38-42
Free Cash Flow	$90-140	$170-210	$210-250
Free Cash Flow Yield (in %)	11-18%	21-26%	26-32%

Adjusted EBITDA is defined as profit for the period (determined as if IFRS 16 Leases has not been adopted), before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful exploration efforts, accrual of share-based payment, unrealized result on commodity risk management contracts, geological and geophysical expenses allocated to capitalized projects, and other non-recurring events. Operating Netback is equivalent to Adjusted EBITDA before cash expenses included in Administrative, Geological and Geophysical and Other operating expenses.

Free cash flow is used here as Adjusted EBITDA less income tax paid included in cash flows from operating activities, less capital expenditures included in cash flows used in investing activities, less mandatory interest payments included in cash flows used in financing activities.

Free cash flow yield is calculated as free cash flow divided by GeoPark’s average market capitalization from January 3 to January 29, 2022.

____________

¹³ Excluding potential and voluntary prepayments on existing financial debt.

OTHER NEWS / RECENT EVENTS

Reporting Date for 4Q2021 Results Release, Conference Call and Webcast

GeoPark will report its 4Q2021 and Annual 2021 financial results on Wednesday, March 9, 2022 after the market close.

In conjunction with the 4Q2021 results press release, GeoPark management will host a conference call on March 10, 2022 at 10:00 am (Eastern Standard Time) to discuss the 4Q2021 financial results.

To listen to the call, participants can access the webcast located in the Investor Support section of the Company’s website at www.geo-park.com, or by clicking below:

https://event.on24.com/wcc/r/3575585/D8C22C704081598319ACA0C7BF36387F

Interested parties may participate in the conference call by dialing the numbers provided below:

United States Participants: 844-200-6205
International Participants: +1 929-526-1599
Passcode: 376830

Please allow extra time prior to the call to visit the website and download any streaming media software that might be required to listen to the webcast.

An archive of the webcast replay will be made available in the Investor Support section of the Company’s website at www.geo-park.com after the conclusion of the live call.

GLOSSARY

1P		Proven Reserves
2P		Proven plus Probable Reserves
3P		Proven plus Probable plus Possible Reserves
boe		Barrels of oil equivalent (6,000 cf marketable gas per bbl of oil equivalent)
boepd		Barrels of oil equivalent per day
bopd		Barrels of oil per day
Certified Reserves		Refers to GeoPark working interest reserves before royalties paid in kind, independently evaluated by the petroleum consulting firm, DeGolyer and MacNaughton Corp. (D&M)
EUR		Estimated Ultimate Recovery
F&D Cost		Finding and Development Cost, calculated as the unaudited cash flow from investing activities divided by the applicable net reserves additions before changes in Future Development Capital
mboed		Thousands of Barrels of oil equivalent per day
mmboed		Millions of Barrels of oil equivalent per day
mmbbl		Millions of Barrels of oil
mcfpd		Thousands of standard cubic feet per day
mmcfpd		Millions of standard cubic feet per day
NPV10 After Tax		Net Present Value after tax discounted at 10% rate
PD		Proven Developed Reserves
PUD		Proven Undeveloped Reserves
PRMS		Petroleum Resources Management System
RLI		Reserve Life Index
RRR		Reserve Replacement Ratio
sq km		Square kilometers
WI		Working Interest

NOTICE

Additional information about GeoPark can be found in the “Investor Support” section of the website at www.geo-park.com

The reserve estimates provided in this release are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual reserves may eventually prove to be greater than, or less than, the estimates provided herein. Statements relating to reserves are by their nature forward-looking statements.

Gas quantities estimated herein are reserves to be produced from the reservoirs, available to be delivered to the gas pipeline after field separation prior to compression. Gas reserves estimated herein include fuel gas.

Rounding amounts and percentages: Certain amounts and percentages included in this press release have been rounded for ease of presentation. Percentage figures included in this press release have not in all cases been calculated on the basis of such rounded figures, but on the basis of such amounts prior to rounding. For this reason, certain percentage amounts in this press release may vary from those obtained by performing the same calculations using the figures in the financial statements. In addition, certain other amounts that appear in this press release may not sum due to rounding.

Oil and gas production figures included in this release are stated before the effect of royalties paid in kind, consumption and losses.

All evaluations of future net revenue contained in the D&M Reports are after the deduction of cash royalties, development costs, operating expenses, production and profit taxes, fees, earn out payments, well abandonment costs, and country income taxes from the future gross revenue. It should not be assumed that the estimates of future net revenues presented in the tables represent the fair market value of the reserves. The actual production, revenues, taxes and development, and operating expenditures with respect to the reserves associated with the Company’s properties may vary from the information presented herein, and such variations could be material. In addition, there is no assurance that the forecast price and cost assumptions contained in the D&M Report will be attained, and variances could be material.

CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

This press release contains statements that constitute forward-looking statements. Many of the forward looking statements contained in this press release can be identified by the use of forward-looking words such as ‘‘anticipate,’’ ‘‘believe’’, ‘‘could,’’ ‘‘expect,’’ ‘‘should,’’ ‘‘plan,’’ ‘‘intend,’’ ‘‘will,’’ ‘‘estimate’’ and ‘‘potential,’’ among others.

Forward-looking statements that appear in a number of places in this press release include, but are not limited to, statements regarding the intent, belief or current expectations, regarding various matters including NPV10 after tax and NPV10 after tax/share estimations, our reserves, the divestment process of the Aguada Baguales, El Porvenir and Puesto Touquet blocks and the Manati Gas Field, the estimated future revenues, free cash flows and oil price forecast. Forward-looking statements are based on management’s beliefs and assumptions, and on information currently available to the management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors.

Forward-looking statements speak only as of the date they are made, and the Company does not undertake any obligation to update them in light of new information or future developments or to release publicly any revisions to these statements in order to reflect later events or circumstances, or to reflect the occurrence of unanticipated events. For a discussion of the risks facing the Company which could affect whether these forward-looking statements are realized, see the Company’s filings with the U.S. Securities and Exchange Commission (SEC).

Information about oil and gas reserves: The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proven, probable and possible reserves that meet the SEC’s definitions for such terms. GeoPark uses certain terms in this press release, such as “PRMS Reserves” that SEC guidelines do not permit GeoPark from including in filings with the SEC. As a result, the information in the Company’s SEC filings with respect to reserves will differ significantly from the information in this press release. NPV10 after tax for PRMS 1P, 2P and 3P reserves is not a substitute for the standardized measure of discounted future net cash flows for SEC proved reserves.

Contacts

INVESTORS:
Stacy Steimel
ssteimel@geo-park.com
Shareholder Value Director
T: +562 2242 9600

Miguel Bello
mbello@geo-park.com
Market Access Director
T: +562 2242 9600

Diego Gully
dgully@geo-park.com
Investor Relations Director
T: +5411 4312 9400

MEDIA:
Communications Department
communications@geo-park.com

2021
- Oilstone agreed to purchase three areas of Geopark
  
  November 16, 2021
  - Geopark reported that they accepted an offer for $ 16 million from Oilstone through the hydrocarbon areas of Aguada Baguales, Future and Touquet post. The company continues with its divestment process in the Neuquén basin to concentrate on its assets in Colombia and rationalize its operations in the region, as reported in the third quarter financial statement.
    
    “We have been analyzing these assets for a long time, they have the category of mature field and that is why they are attractive to us,” said Mauricio Russo, CEO of Oilstone, in contact with + e. The procedure to complete this transaction is in the Hydrocarbons Undersecretariat of the Ministry of Energy and Natural Resources of the province of Neuquén, so news is expected in the coming months.
    
    “These areas have fulfilled all their investment commitments. When we take over, we are going to move some pulling and workover equipment that we have in our areas to those wells that are out of production,”said Russo regarding the strategy that Oilstone will take once it takes control of these three areas of conventional hydrocarbons.
    
    Oilstone is already established as a medium-sized company in the conventional oil and gas segment. In September, Neuquén Gas and Oil (GyP) It was disposed of its participation in La Dorsal, so that 100% of the operation is held by this company with ten years of existence. This area involves the Bajo Baguales, Cutral Co Sur, Ranquil Co Norte, Puerto Cortadera, Loma Negra, Neuquén del Medio and Portezuelo Minas deposits.
    
    With a staff of 260 people, the firm plans to incorporate staff and continue with its contractors in these new areas. They currently have twelve 100% concessions and when the Geopark acquisition is completed they will have 15 areas under their orbit. “With this we will be in the order of 500 m3 of crude oil and one million m3 of gas per day. It gives us a size to optimize processes, costs and efficiency,” he said.
    
    Oilstone (3) .jpg
    
    The Aguada Baguales, El Porvenir and Puesto Touquet blocks have an average production of 2,200 barrels of oil equivalent per day (58% crude oil and 42% natural gas), 6% of GeoPark’s consolidated net oil and gas production during the period between January and September of this year. Proven reserves reach 3.7 million barrels of oil equivalent, certified by DeGolyer and MacNaughton in December 2020.
    
    “The sale of these blocks will allow GeoPark to reallocate resources to its core operations in Colombia and continue to streamline its operations,” indicates the news report on the financial statements of the international company. “GeoPark will continue to operate the Aguada Baguales, El Porvenir and Puesto Touquet blocks until the completion of the divestment process,” he adds.
    
    https://oicanadian.com/oilstone-agreed-to-purchase-three-areas-of-geopark/
- Rosneft Tags DeGolyer and MacNaughton To Estimate CO2 Storage, Plan CCS Pilots
  
  November 8, 2021
  - International petroleum consultancy DeGolyer and MacNaughton (D&M) has signed an agreement to evaluate Russian state oil major Rosneft’s CO2 geological storage potential and advise on pilot projects to combine carbon capture and storage (CCS) with enhanced oil recovery (EOR).
    
    Under the agreement signed at the XIV Eurasian Economic Forum in Verona, Italy, last month, D&M will develop its estimates using methodologies including SPE’s CO2 Storage Resources Management System (SRMS) and the International Organization for Standardization (ISO), Rosneft said in a news release.
    
    The forum is an annual gathering of C-suite executives organized by the Italian Conoscere Eurasia Association which seeks to develop business between Italy, the European Union, Russia, and the Eurasian Economic Union whose members include Russia, Belarus, Kazakhstan, Armenia, and Kyrgyzstan.
    
    Rosneft President and CEO Igor Sechin spoke on the opening panel with BP CEO Bernard Looney, Baker Hughes CEO and Chairman Lorenzo Simonelli, and ExxonMobil Senior Vice President Neil Chapman, according to the forum program.
    
    D&M Chairman and CEO John Wallace was scheduled to speak at a later session on “Natural Gas and the Green Economy.”
    
    The agreement with D&M is the latest in a string of cooperation agreements Rosneft has signed with international firms including BP, Baker Hughes, ExxonMobil, and the Japanese Ministry of Economy and Industry related to greenhouse-gas (GHG) emissions and sustainability.
    
    Rosneft claims to have been the first Russian company to present a Carbon Management Plan for 2035 to the Russian government.
    
    In July, Russian President Vladimir Putin signed legislation requiring the country’s largest GHG emitters to report carbon data to a new government agency. The new law makes carbon reporting mandatory as of January 2023 for companies emitting 150,000 tons of carbon or more, and January 2025 for carbon emitters in the 50,000 to 150,000-ton range.
    
    Over the next 15 years, Rosneft’s Carbon Management Plan aims to meet the following targets:
    
    Prevent direct or indirect GHG emission of 20 million tons of CO2 equivalent.
    
    Reduce the emission intensity (volume of emissions per unit of GDP) of GHG from upstream operations by 30%.
    
    Reduce the intensity of methane emissions specifically to below 0.25%.
    
    End all routine flaring of associated gas.
    
    Rosneft said it has already conducted preliminary research that estimated the volume of its potential CO2 storage capability at 240 to 1,000 billion tons, with an average estimate of around 500 billion metric tons.
    
    The oil major also found that by combining CCS with EOR, it could potentially boost incremental production by 8% to 18% with much of the injected CO2 remaining stored in the reservoir, the company reported.
    
    In 2019, Rosneft signed the Methane Guiding Principles in which the largest hydrocarbon producers from around the globe have pledged to reduce methane emissions across the natural gas supply chain while also improving data collection and increasing transparency.
    
    The industry group seeks to ensure that natural gas continues to play a major role in the energy mix by engaging gas producers to voluntarily reduce emissions of methane. Russia’s Gazprom and Novatek have also signed the accord.
    
    To bring the emission intensity of methane to below 0.25% by 2035, Rosneft is already introducing technologies such as unmanned aerial vehicles, laser and thermal image scanning devices, and ultrasonic detectors. Rosneft subsidiaries Samotlorneftegaz and Krasnodarneftegaz now use drones widely to cut transport emissions, the company said.
    
    https://jpt.spe.org/rosneft-tags-degolyer-and-macnaughton-to-estimate-co2-storage-plan-ccs-pilots
- D&M President Serves as the 2021 President of the Society of Petroleum Evaluation Engineers (SPEE)
  
  November 3, 2021
  - Charles Boyette continues his long-term service to the industry by leading the international Society of Petroleum Evaluation Engineers (SPEE), the single worldwide professional organization dedicated the specialized field of petroleum evaluation. Boyette is the 2021 President of SPEE and has served on the Board of Directors and various committees since joining SPEE earlier in his career.
    
    As President of SPEE, Boyette chairs all board meetings, provides leadership in annual society meetings, provides monthly communication to members, maintains organization of various committees, manages chapter relationships, and represents the SPEE to other professional organizations and the general public.
    
    As is customary, Boyette will fill a role as Past President in 2022, with its own requisite responsibilities.
    
    Charles F. Boyette is President of DeGolyer and MacNaughton. He previously served as Executive Vice President of the firm and co-manager for the firm’s Central Europe-Asia Division. He joined D&M in 1982. He graduated from Texas A&M University in 1979 with a bachelor’s degree in civil engineering and earned a master’s degree in business administration from the University of Texas at Dallas in 1991. Boyette is a member of the Society of Petroleum Engineers and he is a registered professional engineer in Texas.
    
    Recognizing that petroleum evaluation engineering is a specialized field, the SPEE is dedicated to the promotion of professional growth of the membership and to the advancement of the profession of Petroleum Evaluation Engineering. The professional activities of SPEE members are guided via by-laws that require the highest ethical standards. Principles of acceptable evaluation engineering practice address the relationships of members with the public, with employers, with clients, with other members, and with SPEE.
- DeGolyer and MacNaughton Releases 75th Edition of the TWENTY-FIRST CENTURY PETROLEUM STATISTICS
  
  November 3, 2021
  - The 75^th Edition of the TWENTY-FIRST CENTURY PETROLEUM STATISTICS^TM is now exclusively available on the www.demac.com website. Bonus material, such as historical data prior to 1960, is also available for viewing there.
    
    The statistical report was initially prepared in 1945 by the office of the Director of Naval Petroleum and Oil Shale Reserves, Navy Department, Washington, D.C. The Director, Commodore W. G. Greenman, United States Navy, requested that DeGolyer and MacNaughton maintain the “handbook” on an annual basis, since demand indicated that there was a practical need for such information. We have been publishing the TWENTY-FIRST CENTURY PETROLEUM STATISTICS^TM ever since as a ready reference for industry colleagues, clients, researchers, libraries, and students.
    
    In the publication of the TWENTY-FIRST CENTURY PETROLEUM STATISTICS^TM, free use was made of information published by the American Petroleum Institute, Oil and Gas Journal, World Oil, the Energy Information Administration (EIA), and other public-domain sources from around the world. These sources are cited herein, and we greatly appreciate that these publications and organizations granted permission for the use of such data.
    
    Note that the 2021 Edition includes data reflective of information through the end of 2019, based on the most recent availability of the referenced data.
    
    We hope this legacy of our founders is of practical use to those in and outside of the petroleum business. We welcome your use of this valuable information with only a short registration entry on the site. Go to “Reference Materials” on the band across the top of the website, click, and select the “Twenty-First Century Petroleum Statistics” line.
- D&M continues to expand its capabilities in the field of Environmental, Social, and Corporate Governance (ESG) support.
  
  June 10, 2021
  - The D&M Greenhouse Gas specialists are providing services to our clients for compliance, social responsibility initiatives, and advanced business practices projects. D&M intends to be a leader in this field by maximizing the synergies of GHG estimation/verification and petroleum reserves/resources estimation, as well as applying the well-known reputation of the firm and the unmatched expertise of its technical staff. With several GHG projects underway, D&M is developing a vision for GHG services that will link to the future of transitional business models in the industry. More information on D&M’s GHG services is available here.
    
    ESG_GHG_29July2021

Current News

More News

2022

History Matching and Forecasting-2022

April 4, 2022

This Month’s Technical Papers

Recommended Additional Reading

DNO Releases 2021 Annual Statement of Reserves and Resources

DNO - February 23, 2022

DNO logs 321 mmboe of reserves, 34 mmboe output in 2021

DNO - February 23, 2022

Frontera Announces 2021 Year End Reserves

Frontera Energy Corporation - February 17, 2022

The Ecopetrol Group achieved a Reserve-Replacement Ratio of 200% in 2021, the highest in the last 12 years

Ecopetrol S.A. - February 9, 2022

GeoPark Announces Consolidated 2021 Certified 2P Reserves of 159 Million BOE With Net Present Value (After Tax) of $2.3 Billion

GeoPark - February 1, 2022

Contacts

2021

Oilstone agreed to purchase three areas of Geopark

November 16, 2021

Rosneft Tags DeGolyer and MacNaughton To Estimate CO2 Storage, Plan CCS Pilots

November 8, 2021

D&M President Serves as the 2021 President of the Society of Petroleum Evaluation Engineers (SPEE)

November 3, 2021

DeGolyer and MacNaughton Releases 75th Edition of the TWENTY-FIRST CENTURY PETROLEUM STATISTICS

November 3, 2021

D&M continues to expand its capabilities in the field of Environmental, Social, and Corporate Governance (ESG) support.

June 10, 2021