AXP DELIVERS SIGNIFICANT INCREASE IN RESERVES

LEXINGTON, Ky., Sept. 29, 2022 /PRNewswire/ -- AXP Energy Limited (ASX: AXP, OTC US: AUNXF), ('AXP', 'Company') is pleased to provide an updated estimate of its Reserves and Contingent Resources as at 1 July 2022 (the 'Evaluation Date'). The Reserves and Contingent Resources ('R&R') below are net to AXP and its subsidiaries. The Company last reported on its R&R estimate for evaluation date 1 October 2021 in an announcement dated 26 November 2021.

Refer to Appendix 1 for a glossary of terms, the conversion rates used for gas and NGLs to oil equivalent and other important information related to this update.

  • The increase in the Company's 2P Reserves was 14% over only 9 months;

  • 2P Reserves are comprised of 29.7 billion cubic feet of natural gas, 1.14 million barrels of oil and 1.18 million barrels of NGLs;

  • Importantly, the vast majority of AXP's Proved reserves are in the Producing and Developed category;

  • The maturation of AXP's Field Development Plan ('FDP') since the last evaluation date has contributed significantly to the increase in 2P Reserves;

  • Ongoing work to further enhance and refine the FDP, aimed at optimising its significant well inventory and gas behind pipe remains a key focus for the Company;

  • The 2C Contingent Resources of 211.95 million barrels of oil equivalent (MMboe) remains unchanged;

  • AXP is pleased to note a 3C Contingent Resource of 237 Bcf of gas in the Appalachian Basin where its main gas producing leases are situated.

Reserves

Proved reserves (1P) have increased by 2% which is attributable to multiple workover and pipeline projects, primarily focussed on oil production, completed throughout the year; as well as extended economic life due to increases in base product pricing.  Further enhancements to the Company's FDP have resulted in an 89% increase in Probable Reserves, resulting in an aggregate 2P Reserves increase of 14% since 1 October 2021.

AXP's Chief Executive Officer Tim Hart commented: "This update in our Reserves & Resources estimate clearly demonstrates that our leases hold considerable value and also possess outstanding upside. The value is reflected in the vast majority of Reserves being in the Proven and Developed category, giving us production certainty for many years to come, and the upside is evident from the large contingent gas resource that sits within our extensive Appalachian Basin leases. This clearly illustrates AXP's considerable unlocked value.

"We are particularly pleased to see Reserves & Resources increase so significantly in a short period of 9 months and this demonstrates that our workovers and larger field development activities are resulting in material additions to our underlying value. As this work is ongoing, we expect our Reserves to continue building. We look forward to sharing updates on operational progress in the coming weeks."

RESERVE CATEGORY
1 July 2022

OIL
[Mbbl]

GAS
[MMcf]

NGL
[Mbbl]

TOTAL
[Mboe]

Proved Developed (PDP & PDNP)

937

21,244

1,127

5,605

Proved Undeveloped (PUD)

20

138

-

43

Total Proved (1P)

957

21,382

1,127

5,647

Probable

179

8,325

55

1,621

Total Proved + Probable (2P)

1,136

29,707

1,182

7,269

Possible

879

10,359

534

3,140

Total Proved + Probable + Possible (3P)

2,015

40,066

1,715

10,408

Appalachian Basin Projects have been prioritized according to midstream partnerships where security and movement of the gas is the most reliable. These projects have included remedial and restorative production efforts to pipelines, workovers, production equipment optimization and well swabbing.

Illinois Basin projects were focused on completions of DUC's, workover projects, production equipment optimization and improvements at water processing facilities.

DJ Basin Projects have been concentrated on completion of the power generation solution for crypto mining along with various workovers and hot-oil operations to improve production rates.

Significantly, the vast majority of AXP's Proved (1P) reserves are in both the Producing and Developed category.  Within the 2P category, a further 7.7 Bcf of natural gas has been assessed for the Appalachian Basin and 0.6 Bcf for the Illinois Basin.  10.4 Bcf of Possible natural gas was assessed, bringing the 3P category up to 40.1 Bcf.  Refer to Appendix 2 for further details.

The above totals represent an aggregation of the assessed Reserves for the Company's 3 producing areas. A more detailed breakdown of the above, segmented by both basin and development status, is provided in Appendix 2.

Contingent Resources

CONTINGENT RESOURCE CATEGORY

OIL
[MMbbl]

GAS
[Bcf]

NGL
[MMbbl]

TOTAL
[MMboe]

Low Estimate (1C)

46.82

507.16

2.28

149.02

Mid Estimate (2C)

68.32

713.99

3.70

211.95

High Estimate (3C)

96.55

1,041.92

9.25

306.27

There was no change in AXP's 2C Contingent Resources from 1 October 2021 through 1 July 2022 with the aggregate assessment remaining at 211.95 million barrels of oil equivalent (MMboe) as field development was primarily focused on the build of reserves in each of the respective categories.  Notwithstanding, the Company is pleased to note that 237 Bcf of the 1.04 Tcf high estimate (3C) for natural gas was assessed for the Appalachian Basin, where AXP's main gas producing infrastructure is situated.

Work programs being undertaken in the current fiscal year regarding current 2P development projects will solidify the need to revisit the Contingent category in subsequent annual R&R reports to adjust these cases accordingly.  The ongoing projects are within reservoirs that are present in the vast majority of the acreage position across the Appalachian and Illinois basins.

The above totals represent an aggregation of the assessed Contingent Resources for the AXP's 3 producing areas. A detailed breakdown by producing area is provided in Appendix 2.

Qualified Petroleum Reserves and Resources Evaluator Statement

The above petroleum reserve and resource information is based on and fairly represents information and supporting documentation prepared under the supervision of Mr. Russell Hamilton (Vice President and General Manager of AXP Energy, Inc - US) by independent experts Wright & Company, Inc, Brentwood, Tennessee ('Wright').

Mr. Hamilton is a licensed professional geologist in the state of Tennessee (license number 5624) and has been employed by AXP Energy, Inc, Kentucky, since 2005 including in the position of Senior Geologist. Mr Hamilton has also held positions at the Kentucky State Department of Mines and Minerals (Oil & Gas Conservation) as an Oil & Gas Inspector and Hinkle Environmental as an Environmental Scientist and Project Geologist. He holds a Bachelor of Geology from the Eastern Kentucky University, Richmond, Kentucky and has over 20 years' experience in the Appalachian and Illinois Basins' hydrocarbon geology.

Wright's founder and President, Mr D. Randall Wright is a qualified Reserves Estimator as set forth in the Society of Petroleum Engineers ('SPE') "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" (2019). This qualification is based on more than 48 years of practical experience in the estimation and evaluation of petroleum reserves with Texaco, Inc., First City National Bank of Houston, Sipes, Williamson & Associates, Inc., Williamson Petroleum Consultants, Inc., and now Wright & Company, Inc, which he founded in 1988. Mr. Wright has a Master of Science degree in Mechanical Engineering from Tennessee Technological University. He is a registered Professional Engineer in the state of Texas (TBPE #43291), granted in 1978, a member of the Society of Petroleum Engineers (SPE), and a member of the Order of the Engineer.

Notes on Calculation of Reserves & Contingent Resources

The information prepared by Wright was prepared in accordance with the definitions and guidelines of the Petroleum Resources Management System, revised June 2018 ('SPE-PRMS 2018'), issued by the SPE and sponsored by (among others) the SPE, the World Petroleum Council ('WPC'), the American Association of Petroleum Geologists ('AAPG') and the Society of Petroleum Evaluation Engineers ('SPEE').

The estimates of reserves and resources contained in the independent experts' reports were determined by accepted industry methods as determined by the SPE-PRMS 2018, the Guidelines for Application of the Petroleum Resources Management System (SPE revision 2011) and the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE revision 2019). The independent experts also reviewed certain properties that may have contingent or prospective resources as defined by the SPE-PRMS 2018.

Reserves and Contingent Resources reports are prepared using deterministic and probabilistic methods. The Reserves and Contingent Resources estimate methodologies incorporate a range of uncertainty relating to each of the key reservoir input parameters to predict the likely range of outcomes.

Under the SPE-PRMS 2018, Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the Evaluation Date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.

Categorization of Reserves according to the level of certainty associated with them is prescribed as follows:

Proved or 1P Reserves are those quantities of Petroleum that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable from known reservoirs and under defined technical and commercial conditions.

1P Reserves are further categorised by their development status, namely:

  • Proved Developed Producing (PDP) reserves are generally defined as estimated remaining quantities of oil and gas anticipated to be economically producible, as of a given date, by application of development projects to known accumulations under existing economic and operating conditions;

  • Proved Developed Non-Producing (PDNP) are proven resources that can be expected to be recovered through existing wells and existing equipment and operating methods;

  • Proved Undeveloped (PUD) reserves are proven reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion.

Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P).

Possible Reserves are those additional reserves that analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P).

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, by the application of development project(s) not currently considered to be commercial owing to one or more contingencies. Contingent Resources have an associated chance of development. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality.

Contingent Resources are further categorized in accordance with the range of uncertainty associated with the estimates and should be subclassified based on project maturity and/or economic status and have denotations such as 1C (low risk), 2C (same technical confidence as probable reserves but not commercially matured to reserves), and 3C (same technical confidence as possible reserves, but not commercially matured to reserves).

AXP has identified several potential upside projects that target deeper horizons known to be productive, but have not been exploited at this time. These were assessed and the estimate gross reserves potential and assigned to the 1C, 2C, or 3C category based on available data, risk of development, and geologic control.

Project and field totals are aggregated by arithmetic summation by category. Aggregated 1P and 1C estimates may be conservative, and aggregated 3P and 3C estimates may be optimistic due to the effects of arithmetic summation.

This announcement has been authorised by the Board of AXP Energy Limited.

END

FURTHER INFORMATION

Tim Hart Chief Executive Officer: +1 (303) 999-5420
Sam Jarvis, Non-Executive Director: 0418 165 686

ABOUT AXP ENERGY LIMITED

AXP ENERGY Limited (ASX: AXP) is an oil & gas production and development company with operations in Colorado, Illinois, Kentucky, Tennessee and Virginia. AXP's focus is to aggressively grow daily production by improving current asset performance and opportunistically acquiring onshore USA oil & gas assets with the following characteristics: producing conventional oil & gas wells; production that can be enhanced through low-cost field operations and workovers; leases which are held by production and which do not require ongoing drilling commitments; and economies of scale which can be achieved by acquiring and carrying out similar enhancement strategies on contiguous or nearby fields with similar characteristics.

DISCLAIMER

This announcement contains or may contain "forward looking statements" within the meaning of Section 27A of the Securities Act of1933 and Section 21B of the Securities Exchange Act of 1934. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, goals, assumptions or future events or performance are not statements of historical fact and may be "forward looking statements." Forward looking statements are based on expectations, estimates and projections at the time the statements are made that involve a number of risks and uncertainties which could cause actual results or events to differ materially from those presently anticipated. Forward looking statements in this action may be identified through the use of words such as "expects", "will," "anticipates," "estimates," "believes," or statements indicating certain actions "may," "could," or "might" occur. Hydrocarbon production rates fluctuate over time due to reservoir pressures, depletion, down time for maintenance and other factors. The Company does not represent that quoted hydrocarbon production rates will continue indefinitely.

APPENDIX 1 – GLOSSARY AND OTHER INFORMATION

TERM

DEFINITION

bbl

Barrel of oil

Bcf

Billion standard cubic feet of gas

boe

Barrel of oil equivalent

Mbbl

Thousand barrels of oil

MMbbl

Million barrels of oil

Mboe

Thousand barrels of oil equivalent

MMboe

Million barrels of oil equivalent

MMcf

Million standard cubic feet of gas

For Reserves: Natural gas is converted to barrel of oil equivalent (boe) using a conversion factor of 6 Bcf to 1 MMboe.

For Contingent Resources: Natural gas is converted to barrel of oil equivalent (boe) using a conversion factor of 6 Bcf to 1 MMboe for Appalachian and Illinois Basin gas; and using a conversion factor of 5 Bcf to 1 MMboe for DJ Basin gas.

APPENDIX 2 – RESERVES DETAIL BY BASIN

RESERVE CATEGORY
1 JULY 2022

OIL
[MBBL]

GAS
[MMcf]

NGL
[MBBL]

TOTAL
[MBOE]

Proved





Proved Developed Producing (PDP)




Appalachian Basin

533

20,219

1,086

4,989

Illinois Basin

280

188


312

Denver-Julesburg Basin

57

-


57

Total PDP

870

20,407


5,357

Proved Developed Non-Producing (PDNP)




Appalachian Basin

33

727

40

195

Illinois Basin

31

2

-

32

Denver-Julesburg Basin

2

108

-

21

Total PDNP

67

838

40

247

Proved Undeveloped (PUD)





Appalachian Basin

-

-

-

-

Illinois Basin

20

138

-

43

Denver-Julesburg Basin

-

-

-

-

Total PUD

20

138

-

43

Total Proved (1P)

957

21,382

1,127

5,647

Probable





Appalachian Basin

71

7,687

55

1,407

Illinois Basin

108

638

-

214

Denver-Julesburg Basin

-

-

-

-

Proved + Probable (2P)

1,136

29,707

1,182

7,269

Possible





Appalachian Basin

301

9,959

534

2,495

Illinois Basin

578

400

-

645

Denver-Julesburg Basin

-

-

-

-

Proved + Probable + Possible (3P)

2,015

40,066

1,715

10,408

APPENDIX 3 – CONTINGENT RESOURCES BY BASIN

CONTINGENT RESOURCE CATEGORY
1 JULY 2022

OIL
[MMBBL]

GAS
[Bcf]

NGL
[MMBBL]

TOTAL
[MMBOE]

Low Estimate





Appalachian Basin

0.12

45.49

2.28

9.98

Illinois Basin

0.20

-

-

0.20

Denver-Julesburg Basin

46.50

461.67

-

138.83

Total 1C

46.82

507.16

2.28

149.02

Mid Estimate





Appalachian Basin

0.63

86.06

3.70

18.67

Illinois Basin

0.36

-

-

0.36

Denver-Julesburg Basin

67.34

627.93

-

192.93

Total 2C

68.32

713.99

3.70

211.95

High Estimate





Appalachian Basin

1.28

237.36

9.25

50.09

Illinois Basin

0.46

-

-

0.46

Denver-Julesburg Basin

94.81

804.56

-

255.72

Total 3C

96.55

1,041.92

9.25

306.27

 

Cision
Cision

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SOURCE AXP Energy