Operations

Reserves

December 31, 2019 Statement of Reserves

The following disclosure is based on an independent reserves evaluation, effective 31 December 2019, prepared by Lloyd's Register ("LR") for Africa Oil in accordance with Canadian National Instrument 51-101 – Standards for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook").

Africa Oil’s statement of reserves is based on the Company’s 50% ownership interest in Prime Oil & Gas B.V. (“Prime”). The primary assets of Prime are an indirect 8% interest in Oil Mining Lease (“OML”) 127 and an indirect 16% interest in OML 130; both are deepwater Nigeria concessions. OML 127 is operated by the affiliates of Chevron Corporation (“Chevron”) and contains the producing Agbami field. OML 130 is operated by affiliates of TOTAL S.A. (“TOTAL”) and contains the producing Akpo and Egina fields.

The reserves and changes to reserves summarised in the following table pertain to 50% of Prime’s net entitlement reserves1:

Net Entitlement Reserves2 CategoryYear-End 2018
(MMboe)3
2019 Production
(MMboe)4
Pro Forma Year-End 2019 (Mmboe)5Year-End 2019
(MMboe)
6
Difference in Year-End 2019 and Pro Forma Estimates (MMboe)
Proved Reserves (1P)62.712.649.252.3+ 3.1
Proved + Probable Reserves (2P)94.780.685.1+ 4.5

Notes:

  1. Please refer to the oil and gas advisory on the next page for important information.
  2. Net entitlement reserves are calculated using the economic interest methodology and include cost recovery oil, tax oil and profit oil and are different from working interest reserves that are calculated based on project volumes multiplied by Prime’s effective working interest.
  3. Estimates for the three producing fields (Agbami, Akpo and Egina) only.
  4. Entitlement production from Agbami, Akpo and Egina.
  5. Pro forma end of 2019 reserves estimates were announced in the Company’s press release of 14 January 2020 (‘Africa Oil Announces the Closing of the Acquisition of Producing Assets in Deepwater Nigeria’) and provided in the interim whilst LR completed its year-end 2019 report. 
  6. Estimates account for 2019 net entitlement production from the three producing fields (Agbami, Akpo and Egina) plus technical revisions for the three fields and the addition of the undeveloped field, Preowei, to the reserves base.
  7. Cash flow from operations net to the Company's 50% shareholding in Prime. Any dividends received by Africa Oil from Prime's operating cash flows will be subject to Prime's capital investment (2020 estimate of $55 million net to the 50% shareholding) and financing cashflows, including payments of Prime's Reserve Based Lending ("RBL") principal amortization and interest payments, currently estimated to be approximately $315 million and $50 million respectively in 2020, net to Africa Oil's 50% shareholding in Prime. The 50% shareholding in Prime will be accounted for using the equity method and it will be presented as an investment in the Consolidated Balance Sheet.  Africa Oil’s 50% share of Prime’s net profit or loss will be shown in the Consolidated Statements of Net Loss and Comprehensive Loss. Any dividends received by Africa Oil from Prime will be recorded as a Cash flow from Investing Activities. The guidance presented here is for information only.

Advisory Regarding Oil and Gas Information

The terms boe (barrel of oil equivalent) and MMboe (millions of barrels of oil equivalent) are used throughout this press release. Such terms may be misleading, particularly if used in isolation. Year-end 2019 reserves estimates are based on a conversion ratio of five thousand and eight hundred cubic feet per barrel (5.85 Mcf: 1bbl), whereas year-end 2018 estimates and pro forma 2019 reserves estimates presented in this press release and previous press releases are based on a conversion ratio of six thousand cubic feet per barrel (6 Mcf: 1bbl). The change in the conversion ratio used is in order to align Africa Oil’s methodology to that used by Prime Oil & Gas B.V. LR’s year-end 2019 1P and 2P reserves estimates, based on the previous conversion factor (6 Mcf: 1bbl), are 52.2 MMboe and 84.9 MMboe, respectively, representing a difference of less than one percent (1%). The conversion ratio of five thousand and eight hundred cubic feet per barrel (5.85 Mcf:1 bbl) of natural gas to barrels of oil equivalent and the conversion ratio of 1 barrel per five thousand and eight hundred cubic feet (1 bbl:5.85 Mcf) of barrels of oil to natural gas equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 5.85:1, utilizing a conversion on a 5.85:1 basis may be misleading as an indication of value.

LR’s report was prepared prior to the recent drop in oil prices using Brent oil price forecast of ($/bbl): 2020 - 63.5; 2021 – 65.0; 2022 – 67.0; 2023 – 69.0; 2024 – 70.4; 2025 – 72.9; 2026 – 74.3; and 2027 – 75.9. There is no assurance that the forecast prices will be attained and variances could be material. The recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

The reserves estimates presented in this press release with respect to the Acquisition have been evaluated by Lloyd's Register in accordance with NI 51-101 and the COGE Handbook, are effective December 31, 2019. The reserves presented herein have been categorized accordance with the reserves and resource definitions as set out in the COGE Handbook. The estimates of reserves in this press release may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

Reserves are estimated remaining quantities of petroleum anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates and may be sub-classified based on development and production status. Proved Reserves are those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. Probable Reserves are those additional quantities of petroleum that are less certain to be recovered than Proved Reserves, but which, together with Proved Reserves, are as likely as not to be recovered. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.