Exhibit 99.1

SUPPLEMENTAL INFORMATION ON CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)

The supplemental information below for TransGlobe Energy Corporation (“TransGlobe”) is presented in accordance with certain provisions of ASC Topic 932 – Extractive Activities- Oil and Natural Gas as required by Rule 3-05(f) of Regulation S-X. The geographic areas reported are in Egypt and Alberta, Canada.

Estimated Quantities of Proved Reserves

The estimation of net recoverable quantities of crude oil, natural gas and natural gas liquids is a highly technical process that is based upon several underlying assumptions that are subject to change.

TransGlobe maintains a policy of not booking proved reserves on discoveries until such time as a development plan has been prepared for the discovery indicating that the development well will be drilled within five years from the date of its initial booking. Additionally, the development plan is required to have the approval of the joint venture owners in the discovery. The December 31, 2021 reserves reflect the effect of the merged Concession Agreement signed January 19, 2022.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Crude Oil, Natural Gas and NGL Reserves

The information that follows has been developed pursuant to procedures prescribed under GAAP and uses reserve and production data estimated by independent petroleum consultants. The information may be useful for certain comparison purposes but should not be solely relied upon in evaluating its or TransGlobe’s performance.

In accordance with the guidelines of the Securities and Exchange Commission (“SEC”), the estimates of future net cash flow from the properties and the present value thereof are made using crude oil and natural gas contract prices using a twelve month average of beginning of month prices and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The future cash flows are also based on costs in existence at the dates of the projections. Future production costs do not include overhead charges allowed under joint operating agreements or headquarters general and administrative overhead expenses. However, all future costs related to future property abandonment when the wells become uneconomic to produce are included in future development costs for purposes of calculating the standardized measure of discounted net cash flows

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in standardized measure of discounted future net cash flows as follows:

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company’s control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and natural gas liquids that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil, natural gas and natural gas liquids that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil, natural gas and natural gas liquids sales prices may all differ from those assumed in these estimates. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated crude oil, natural gas and natural gas liquids reserves attributable to the properties. The information set forth in the foregoing tables includes revisions for certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in product prices.

In accordance with the current guidelines of the SEC, estimates of future net cash flow from the properties and the present value thereof are made using an unweighted, arithmetic average of the first-day-of-the-month price for each of the 12 months of the year adjusted for quality, transportation fees and market differentials. Such prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For 2021, the average of such were $60.79 per Bbl for crude oil, $2.65 per MMcf for natural Gas and $30.42 per Bbl for NGL’s. For 2020, the average of such were $33.70 per Bbl for crude oil, $1.53 per MMcf for natural Gas and $13.90 per Bbl for NGL’s.

Egypt

At December 31, 2021, TransGlobe held interests in four production sharing concessions: West Gharib, West Bakr, North West Gharib and South Ghazalat. In December 2021, TransGlobe announced that the proposal to merge the West Gharib, West Bakr and North West Gharib concessions had been ratified by Egypt's Parliament and signed into law by President El-Sisi. On January 19, 2022, the West Gharib, West Bakr and North West Gharib concessions were merged into the Merged Concession Agreement. This agreement extended the primary term of the merged agreement and amended its fiscal terms. As of December 2022, TransGlobe's interests are spread across two regions: the Eastern Desert, which contains the Merged Concession, and the Western Desert, which contains the South Ghazalat concession.

The following tables summarize TransGlobe's international PSC terms for the first tranche(s) of production for each block. The two contracts have different terms for production levels above the first tranche, which are unique to each contract. The Egyptian government's share of production increases and the contractor's share of production decreases as the production volumes go to the next production tranche. TransGlobe is the operator of, and has a 100% working interest in, all PSCs. TransGlobe's oil entitlement is the sum of cost oil, profit oil and excess cost oil (if any). Taxes are captured in the Egyptian government's net entitlement oil due (and therefore there is no additional burden to TransGlobe).

Eastern Desert – Gulf of Suez Basin, Egypt

*Merged concession profit oil is set on a scale according to average Brent price and production:

Western Desert – Western Desert Basin, Egypt

*South Ghazalat concession production sharing oil table

Canada

In Canada, TransGlobe owns production and working interests in certain facilities in the Cardium light oil and Mannville liquids-rich gas assets in the Harmattan area of west central Alberta. Each province has legislation and regulations in place to govern Crown royalties and establish the royalty rates that producers must pay in respect of the production of Crown resources. The royalty regime in a given province is in addition to applicable federal and provincial taxes and is a significant factor in the profitability of oil sands projects and natural gas and NGL production.

Alberta

Under the Modernized Framework, producers initially pay a flat royalty of 5% on production revenue from each producing well until payout, which is the point at which cumulative gross revenues from the well equals the applicable drilling and completion cost allowance. After payout, producers pay an increased royalty of up to 40% that will vary depending on the nature of the resource and market prices. Once the rate of production from a well is too low to sustain the full royalty burden, its royalty rate is gradually adjusted downward as production declines, eventually reaching a floor of 5%.

Freehold royalties and taxes

Royalty rates for the production of privately owned oil and natural gas are negotiated between the producer and the resource owner.

The Government of Alberta levies annual freehold mineral taxes for production from freehold mineral lands. On average, the tax levied in Alberta is 4% of revenues reported from freehold mineral title properties and is payable by the registered owner of the mineral rights.