CALGARY, Alberta, Dec. 03, 2020 (GLOBE NEWSWIRE) — TransGlobe Energy Corporation (“TransGlobe” or the “Company”) announces it has reached an agreement with the Egyptian General Petroleum Corporation (“EGPC”) to merge the Company’s three existing Eastern Desert concessions (the West Gharib, West Bakr and North West Gharib concessions) into a new modernized concession agreement (the “Merged Concession” or “Agreement”). The Agreement is subject to the usual Egyptian Parliamentary ratification and the satisfaction of other closing conditions. All dollar values are expressed in US dollars unless otherwise stated.
KEY ELEMENTS OF THE MERGED CONCESSION
- The West Gharib, West Bakr, and North West Gharib concessions, including all existing development leases within these concessions, will be merged into the Merged Concession with a new 15-year development term and a 5-year extension option.
- Modernized financial concession terms promote increased investment and implementation of new technology in the mature fields through:
– Improved cost recovery terms to support continued investment in higher-cost mature fields.
– Production sharing terms scaled to oil prices to support TransGlobe’s returns during lower oil prices and government returns during higher oil prices.
– Improved netbacks and increased cash flows are expected to fund new investments in incremental recovery projects.
• Near-term operational netbacks (revenue less royalties, taxes and operating expenses) are estimated to improve by the following ranges relative to Brent pricing assuming current production levels, operating costs and historical differentials to Brent:
|Brent Oil Price ($/bbl)||Netback Increase ($/bbl)|
|$40||~$5 to $7|
|$50||~$7 to $9|
|$60||~$9 to $11|
– Modernized terms are to be applied from the February 2020 effective date of the Merged Concession.
- Incremental, internally estimated, Company Gross risked best estimate Economic Contingent Resource volume of 59.1 million barrels oil (Company Contingent Resources are separate from Company reserves; please see Advisory Regarding Oil and Gas Information later in this release).
- Subject to final ratification, the Company will pay EGPC a signature bonus and an equalization (or modernization) payment in installments. The Company anticipates that the equalization payment and signature bonus will be funded from existing resources and expected improved cash flows.
– The equalization payment compensates EGPC for the improved fiscal terms on the underlying base forecasted production.
– An initial equalization payment of $15 million and signature bonus of $1 million are due on ratification, with five further annual equalization payments of $10 million each being made over five years (beginning February 1, 2022 until February 1, 2026).
- Minimum financial work commitments of $50 million per each five-year period of the primary development term, commencing on the February 1, 2020 effective date. All investments which exceed the five-year minimum $50 million threshold will carry forward to offset against subsequent five-year commitments.
– For context, the Company’s average annual capital expenditures in Egypt over the last five full calendar years has been greater than $30 million per year, and the Company expects to fund these future investments from existing resources and future cash flows.
- Merge the existing Joint Venture Operating Companies’ (Dara Petroleum Company, West Bakr Petroleum Company and North West Gharib Petroleum Company) assets, facilities, and infrastructure into a new Joint Venture Operating Company in order to substantially increase operational efficiencies.
PRESIDENT AND CEO COMMENTS
Randy Neely, President and CEO stated, “After a lengthy and constructive negotiation, I believe we have arrived at an incredible win-win amendment for both TransGlobe and EGPC. The efficiencies gained from the consolidation of our Eastern Desert concessions, along with the improved netbacks and extended term, are expected to provide TransGlobe with the fiscal incentive and time to unlock meaningful additional reserves and production through the application of modern technology and optimization of infrastructure. This will also allow us to move forward with important ESG initiatives to improve our environmental footprint as well as continue to be a major employer in the Ras Gharib region for the foreseeable future.
We intend to continue to manage the finances of the Company with a conservative approach and expect that, under a reasonable range of oil prices, the Company will be able to fund the equalization payments and a continuous capital investment program from existing resources and cash flows. In addition, as soon as practicable, direct returns to our shareholders will be prioritized.
This Agreement is a critical first step in achieving our stated goal of becoming a leading independent Middle East/North Africa region cashflow–focused energy producer. The Merged Concession will provide the platform to allow us to increase our efforts on completing complementary mergers and acquisitions to further support this objective.
We appreciate the commitment and vision of the leadership team at EGPC to extending the life of these mature oil fields and we look forward to working closely with them to realize the significant mutual benefits of this Merged Concession. In the immediate future we will begin to plan for increased activities that should in the near to medium term arrest and reverse recent production declines.”
BACKGROUND TO THE AGREEMENT
In 2017, H.E. Eng. Tarek El Molla (Minister of Petroleum & Minerals) announced a Modernization Initiative to try to increase oil production and reserves by 20% from existing oil pools (brownfields). Since that time, TransGlobe and EGPC have been discussing ways in which TransGlobe could increase recoveries and production from its existing producing fields and have worked extensively to evaluate various modernization fiscal structures to provide a framework for continued brownfield investment in TransGlobe’s Eastern Desert concessions.
Encouraged by the Ministry’s Modernization Initiative and positive discussions with EGPC, the Company identified a number of enhanced recovery and infrastructure efficiency projects targeting incremental oil recovery from existing pools in the concessions. Concurrently, the Company initiated detailed static and dynamic reservoir modeling of several of the larger pools to evaluate enhanced recovery strategies. Additional detail regarding these and other Contingent Resources disclosed in this news release are available below under “Advisory Regarding Oil and Gas Information”.
The existing concessions are comprised of 10 development leases, which include a number of development leases approaching the end of their primary terms in the next few years. All of the existing development leases (each with a 20-year primary term) have a 5-year extension available, however future investment under the existing concessions is challenged due to limited remaining tenure on some of the key development leases, and their fiscal terms. These factors, combined with the prevailing lower oil prices and higher operating costs associated with mature oil fields, made future capital investments very challenging. All 10 existing development leases are included in the Merged Concession.
SIGNIFICANT MUTUAL BENEFITS
The modernized fiscal terms and extended investment horizon provide the necessary incentives and fiscal framework to support increased investment to recover additional oil volumes in the mid-term expected Brent oil price environment of $40-$60/bbl.
New investable projects will target a Company Gross risked best estimate incremental 59.1 million barrels of Economic (Development Pending/ On Hold and Development Unclarified) Contingent Resources through drilling, increased operating efficiencies and the application of new technologies over the 20 year term (15 year primary + a 5 year option period). These Contingent Resources are separate from our existing Proved plus Probable reserve base in the eastern desert which were estimated at 26.3 million barrels of oil (23.6 MMbbl heavy oil and 2.7 MMbbl light/medium oil) at 12/31/2019.
Investable projects are expected to arrest the historical production declines (~22% per year) and provide a stable production and cash flow base for the next five+ years with potential to grow and extend the life of existing fields. To date, of the 59.1 million barrels of risked Contingent Resources noted above, the Company has technically matured a Company Gross risked best estimate incremental 20.5 million barrels of Development Pending/ On Hold Contingent Resources from the Arta Nukhul, K-Field, and H-Field pools based on their respective dynamic modelling, the Merged Concession terms, and an estimated future capital investment of ~$125 million. With this announcement, the Company will prioritize the Arta Nukhul, H-Field, and K-Field pools’ resource maturation projects, which are expected to commence as soon as reasonably practicable. See “Advisory Regarding Oil and Gas Information” below for additional details.
Consolidation of the three concessions is expected to generate additional efficiencies through consolidation of the existing joint venture operating companies, optimized utilization of existing infrastructure, and future infrastructure investments.
In addition, the merged workforce of the existing joint venture operating companies provides the Company and EGPC with an opportunity to train, develop, and deploy an integrated workforce with enhanced operating capabilities to develop and operate other brownfields in the future.
The Merged Concession is expected to provide further incentive for the transfer of technologies, through horizontal drilling with multi-staged completions, routinely employed in our Canadian operations, possible tertiary recovery techniques, and also the opportunity to pursue a number of infrastructure investments to increase operating efficiencies.
In accordance with the Company’s ESG initiatives, the Company has identified several infrastructure investment projects such as displacing diesel power generation in the field with reliable power from the national power grid which are expected to increase efficiencies, reduce operating costs, and significantly reduce GHG emissions. The national power grid has been expanded throughout the merged area, including connection to the substantial, new renewable wind power projects in the region.
Significant additional benefits are expected to accrue to Egypt, the Red Sea Governorate and the city of Ras Gharib through additional investments, operating costs, and the associated employment of the local workforce necessary to extend the life of the existing fields.
TransGlobe Energy has posted a Merged Concession presentation to our website (www.trans-globe.com) and will be hosting a webcast and conference call to discuss the announcement further. Details of the webcast will be provided in a separate announcement.
TransGlobe Energy Corporation is a cashflow-focused oil and gas exploration and development company whose current activities are concentrated in the Arab Republic of Egypt and Canada. TransGlobe’s common shares trade on the Toronto Stock Exchange and the AIM market of the London Stock Exchange under the symbol TGL and on the NASDAQ Exchange under the symbol TGA.
For further information, please contact:
|TransGlobe Energy Corporation
Randy Neely, President and CEO
Eddie Ok, CFO
|+1 403 264 9888
|Tailwinds Associates (Investor Relations)
|+1 403 618 8035
|FTI Consulting (Financial PR)
|+44(0) 20 3727 1000
|Canaccord Genuity (Nomad & Joint-Broker)
|+44(0) 20 7523 8000|
|Shore Capital (Joint Broker)
|+44(0) 20 7408 409|
Advisory Regarding Oil and Gas Information
TransGlobe completed an internal evaluation of the Contingent Resources (the “Contingent Resource Evaluation”) attributed to the pools included in the Company’s existing 10 development leases based on the new terms and conditions of the Merged Concession (the “Evaluated Areas”) which remains subject to ratification and satisfaction of certain other closing conditions. TransGlobe’s wholly-owned subsidiaries have a 100% working interest in the existing development leases and related concession agreements covering the Evaluated Areas and would maintain that level of interest upon ratification of the Merged Concession. The Evaluated Areas are located onshore in Egypt’s Eastern Desert. The Contingent Resources Evaluation is effective September 30, 2020 and has been prepared by a member of TransGlobe’s management who is a qualified reserves evaluator in accordance with the procedures and standards contained in the Canadian Oil and Gas Evaluation (“COGE”) Handbook.
Contingent Resources should not be confused with reserves. Readers should review the definitions and notes set forth below. Actual resources may be greater than or less than the estimates provided herein. There is uncertainty that it will be commercially viable to produce any portion of the resources.
Gross Contingent Resources are the Company’s working interest share before the deduction of royalties. Net Contingent Resources in Egypt include the Company’s share of future cost recovery and production sharing oil, and Contingent Resources relating to income taxes. Under this method, a portion of the reported Contingent Resources will increase as oil prices decrease and vice versa as the barrels necessary to achieve cost recovery change with prevailing oil prices.
Summary of Risked Best Estimate Contingent Resources for the Evaluated Areas as of September 30, 2020
|Best Estimate Risked Contingent Resources (1)|
|Project Maturity Sub-Class||Heavy crude oil|
|Gross (MMbbl)||Net (MMbbl)|
|Development Pending / On Hold||20.5||13.4|
|Total Economic Contingent Resources||59.1||36.2|
|Development Not Viable||2.1||1.3|
(1) Refer to “Resource Definitions” below for detailed definitions of Contingent Resources.
The estimated cost to bring on commercial production from the Development Pending / On Hold Contingent Resources is approximately $125 million (discounted at 10 percent is approximately $81.2 million), and the expected timeline to bring these resources onto production ranges from one to three years depending on the Evaluated Area. TransGlobe’s Development Pending / On Hold Contingent Resources represent development projects within the Evaluated Areas for which specific development plans have been made. These resources are expected to be recovered using the same conventional development technology that TransGlobe has already proven to be effective in the Evaluated Areas, supplemented by some horizontal well drilling and multi-stage stimulation that the Company has successfully deployed in Canada.
Contingent Resources Chance of Commerciality
The Evaluated Areas with Contingent Resources were risked for the chance of commerciality (“CoC”), which is defined as follows:
|CoC = chance of development (“CoDev”) × chance of discovery (“CoD”)|
|wherein CoD for Contingent Resources is equal to one for all Contingent Resources.|
The chance of development is the estimated probability that, once discovered, a known accumulation will be commercially developed. Five factors have been considered in determining the CoDev as follows:
|CoDev = Ps (Economic Factor) × Ps (Technology Factor) × Ps (Development Plan Factor) × Ps (Development Timeframe Factor) × Ps (Other Contingency Factor)|
|wherein Ps is the probability of success|
The five factors were assessed for each of the Evaluated Areas. The following factors were assessed for TransGlobe’s Contingent Resources to be sub-classified and considered as Development Pending/ On Hold Contingent Resources, Development Unclarified Contingent Resources or Development Not Viable Contingent Resources:
- Economic Factor: For Development Pending/ On Hold the associated development projects had robust economics (i.e., strong rate of returns), and as such were assigned a factor of 0.9 to 1.0. The remaining Contingent Resources sub-classes have factors ranging from 0.6 to 1.00. The Contingent Resource Evaluation is based on the October 1, 2020 forecast pricing and inflation published by GLJ Petroleum Consultants Ltd., independent petroleum consultants, shown in the following table:
|Year||Brent Reference Price
|2030+||+2.0%/yr thereafter||2.00%/yr thereafter|
(1) Price forecast is GLJ forecast from Oct 1, 2020
(2) Inflation rates for forecasting expenditure prices and costs
- Technology Factor: Much of TransGlobe’s Contingent Resources will be developed utilizing established technology, therefore, a technology factor of 0.8 to 1.0 is utilized for all resource Contingent Resources sub-classes. A lower factor here took into account potential operational risks associated with horizontal, multi-stage stimulated wells.
- Development Plan Factor: Development plans and costs were prepared and are in place. This factor ranges from 0.85 to 0.9 for Development Pending/ On Hold Contingent Resources. For the remaining Contingent Resources sub-classes, the Development Plan Factors range from 0.70 to 0.75 based on the level of detail.
- Development Timeframe Factor: Several core areas within the Evaluated Areas have portions of the Petroleum Initially-in-Place (“PIIP”) volume developed and producing, with proved and probable reserves assigned. Timing for the Contingent Resources portions of these projects will depend on the pace of continued development (including allocation of funds), available throughput capacity in existing facilities, or construction of additional facilities. Development Pending/ On Hold projects have been assigned Development Timeframe Factors of 1.0 reflecting a high level of certainty in timing estimates and intent by TransGlobe to invest in these projects in the near term. For the remaining Contingent Resources sub-classes, the Timeframe Factors assigned range from 0.70 to 0.90.
- Other Contingency Factor: For reserves to be assessed, all contingencies must be eliminated. With respect to Contingent Resources, this factor captures major contingencies, usually beyond the control of TransGlobe, other than those captured by economic status, technology status, project evaluation scenario status and the development timeframe. The Other Contingency Factor has been assessed as 1.0 for all Contingent Resources sub-classes.
These factors may be inter-related, and care has been taken to ensure that risks are appropriately accounted for. The following table summarizes the Chance of Commerciality applied to Contingent Resources based on the factors assessed.
Summary of Chance of Commerciality of Best Estimate Contingent Resources for the Evaluated Areas as of September 30, 2020:
|Chance of Commerciality and Best Estimate Contingent Resources [(1)(2)]|
|Chance of Commerciality||Best estimate unrisked||Best estimate risked|
|Heavy Crude Oil (MMbbl)|
|Development Pending/ On Hold Contingent Resources||85||%||24.0||20.5|
|Development Unclarified Contingent Resources||60||%||65.1||38.6|
|Total Economic Contingent Resources||–||89.1||59.1|
|Development Not Viable Contingent Resources||26||%||8.0||2.1|
(1) All volumes listed in the table are Company Gross.
(2) Refer to “Resource Definitions” below for detailed definitions of Contingent Resources
Risks and Significant Positive and Negative Factors
Continuous development through multi-year development programs and significant levels of future capital expenditures are required in order for Contingent Resources to be recovered in the future. The principal risks that would inhibit the recovery of additional resources relate to the potential for variations in the quality of the Evaluated Areas formation where minimal well data currently exists, access to the capital which would be required to develop the resources, low crude oil prices that would curtail the economics of development, the future performance of wells, regulatory approvals, access to the required services at the appropriate cost, access to market and the effectiveness of stimulation technology and applications.
Furthermore, it should be understood that Contingent Resources estimates reflect data as of the date of the Contingent Resources Evaluation. Although only best estimates are reported, it should be understood that there is a significant degree of uncertainty in these estimates. Additional data may justify upward or downward revisions to the estimates, which in turn would impact the Contingent Resources estimates.
In the Evaluated Areas, the primary contingencies that prevent the Contingent Resources from being classified as reserves are the development of firm plans, including timing, infrastructure, and the commitment of capital, and, in some cases, the verification of commercial production rates. As continued delineation occurs, and plans are firmed up, some Contingent Resources are expected to be re-classified to reserves.
Projects have been defined to develop the resources in the Evaluated Areas for the Development Pending/ On Hold Contingent Resources at the evaluation date. Such projects, in the case of the Evaluated Areas, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints, TransGlobe’s policy of orderly development on a staged basis, TransGlobe’s short-term and long-term view of crude oil prices, and the results of development activities in the area.
The following are excerpts from the definitions of resources and reserves, contained in Section 5 of the COGE Handbook, which is referenced by the Canadian Securities Administrators in “National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities”.
(a) Fundamental Resource Definitions
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as Contingent Resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status.
(b) Uncertainty Categories for Resource Estimates
The range of uncertainty of estimated recoverable volumes may be represented by either deterministic scenarios or by a probability distribution. Resources should be provided as low, best, and high estimates as follows:
Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 per cent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 per cent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 per cent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
This approach to describing uncertainty may be applied to reserves, Contingent Resources and prospective resources. There may be significant risk that sub-commercial and undiscovered accumulations will not achieve commercial production. However, it is useful to consider and identify the range of potentially recoverable quantities independently of such risk.
(c) Discovered and Commercial Status and Risks Associated with Resource Estimates Discovery Status
Total petroleum initially-in-place is first subdivided based on the discovery status of a petroleum accumulation. Discovered PIIP, production, reserves, and Contingent Resources are associated with known accumulations. Recognition as a known accumulation requires that the accumulation be penetrated by a well and have evidence of the existence of petroleum. The COGE Handbook Consolidated 3rd Edition, Section 184.108.40.206.1.2, provides additional clarification regarding drilling and testing requirements relating to recognition of known accumulations. On the other hand, Prospective resources is undiscovered PIIP which is associated with accumulations yet to be discovered.
Commercial status differentiates reserves from Contingent Resources. The following outlines the criteria that should be considered in determining commerciality:
- economic viability of the related development project;
- a reasonable expectation that there will be a market for the expected sales quantities of production required to justify development;
- evidence that the necessary production and transportation facilities are available or can be made available;
- evidence that legal, contractual, environmental, governmental, and other social and economic concerns will allow for the actual implementation of the recovery project being evaluated;
- a reasonable expectation that all required internal and external approvals will be forthcoming. Evidence of this may include items such as signed contracts, budget approvals, and approvals for expenditures, etc.;
- evidence to support a reasonable timetable for development. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While five years is recommended as a maximum time frame for classification of a project as commercial, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons or to meet contractual or strategic objectives.
Commercial Risk Applicable to Resource Estimates
Estimates of recoverable quantities are stated in terms of the sales products derived from a development program, assuming commercial development. It must be recognized that reserves and Contingent Resources involve different risks associated with achieving commerciality. The likelihood that a project will achieve commerciality is referred to as the “chance of commerciality.” The chance of commerciality varies in different categories of recoverable resources as follows:
Reserves: To be classified as reserves, estimated recoverable quantities must be associated with a project(s) that has demonstrated commercial viability. Under the fiscal conditions applied in the estimation of reserves, the chance of commerciality is effectively 100 percent.
Contingent Resources: Not all technically feasible development plans will be commercial. The commercial viability of a development project is dependent on the forecast of fiscal conditions over the life of the project. For Contingent Resources the risk component relating to the likelihood that an accumulation will be commercially developed is referred to as the “chance of development.” For Contingent Resources the chance of commerciality is equal to the chance of development.
(d) Recovery Technology Status
Established Technology: A recovery method that has been proven to be successful in commercial applications in the subject reservoir and is a prerequisite for assigning reserves.
Technology under Development: A recovery process that has been determined to be technically viable via field test and is being field tested further to determine its economic viability in the subject reservoir. Contingent Resources may be assigned if the project provides information that is sufficient and of a quality to meet the requirements for this resource class.
Experimental Technology: A technology that is being field tested to determine the technical viability of applying a recovery process to unrecoverable discovered PIIP in a subject reservoir. It cannot be used to assign any class of recoverable resources (i.e., reserves and Contingent Resources).
(e) Economic Status of Resource Estimates
By definition, reserves are commercially (and hence economically) recoverable. A portion of Contingent Resources may also be associated with projects that are economically viable but have not yet satisfied all requirements of commerciality. Accordingly, it may be a desirable option to subclassify Contingent Resources by economic status:
Economic Contingent Resources are those Contingent Resources that are currently economically recoverable. The Contingent Resources sub-classes included are Development Pending Contingent Resources, Development on Hold Contingent Resources, and Development Unclarified Contingent Resources.
Sub-Economic Contingent Resources are those Contingent Resources that are not currently economically recoverable. The Contingent Resources sub-class included is Development Not Viable.
Where evaluations are incomplete such that it is premature to identify the economic viability of a project, it is acceptable to note that project economic status is “undetermined” (i.e., “Contingent Resources – economic status undetermined”).
In examining economic viability, the same fiscal conditions should be applied as in the estimation of reserves, i.e., specified economic conditions, which are generally accepted as being reasonable (refer to the COGE Handbook Consolidated 3rd Edition, Section 220.127.116.11.1.3).
(f) Project Maturity Sub-Classes for Contingent Resources
Development Pending: Where resolution of the final conditions for development is being actively pursued (high chance of development).
Development on Hold: Where there is a reasonable chance of development but there are major non-technical contingencies to be resolved that are usually beyond the control of the operator.
Development Unclarified: When the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties.
Development Not Viable: Contingent Resource that is not viable in the conditions prevailing at the effective date of the evaluation, and where no further data acquisition or evaluation is currently planned and hence there is a low chance of development.
Historic Financial Information regarding the Assets
The three concessions associated with the Merged Concession generated ~$16 million of earnings in 2019 (which excludes allocated finance expenses and losses on financial instruments).