CALGARY, Alberta, Jan. 29, 2018 (GLOBE NEWSWIRE) -- TransGlobe Energy Corporation (“TransGlobe” or the “Company”) (TSX:TGL) (NASDAQ:TGA) today announces its 2017 year-end reserves. All dollar values are expressed in United States dollars unless otherwise stated.
EXECUTIVE SUMMARY
- Total proved (“1P”) gross reserves of 27.6 million barrels oil equivalent (“MMboe”) (YE 2016: 29.9 MMboe) representing a 2.3 MMboe or 8% decrease from year-end 2016 primarily due to production of ~5.7 MMboe during the year, partially offset by ~3.4 MMboe of positive net revisions.
- Total proved plus probable (“2P”) gross reserves of 45.9 MMboe (YE 2016: 50.0 MMboe) decreased 8% from year-end 2016 primarily due to production of ~5.7 MMboe, partially offset by ~1.6 MMboe of positive net revisions.
- 2P reserves were comprised of 58% Egypt (medium/heavy oil) and 42% Canada (15% conventional natural gas, 13% natural gas liquids and 14% light oil).
- Replaced 62% and 30% of 2017 production (~5.7 MMboe) on a respective 1P and 2P gross reserve basis.
Egypt
- Positive technical revisions attributed to Egypt of 1.2 MMbbls of gross 2P reserves, primarily due to improved performance.
- An additional 1.0 MMbbls of gross 2P reserves attributed to NW Gharib discoveries.
- Successful NW Gharib well drilled in late Q4 to be included in the 2018 reserve evaluation.
Canada
- Positive extension additions attributed to Canada of 2.6 MMboe of gross 2P reserves, primarily due to the addition of undeveloped Cardium oil locations.
- Negative technical revisions attributed to Canada of 3.1 MMboe of gross 2P reserves, primarily attributed to undeveloped Mannville gas locations deemed uneconomic at current natural gas price forecasts.
- Total proved plus probable plus possible (“3P”) gross reserves of 62.5 MMboe represented a 5% reduction (2016: 65.9 MMboe).
- Present value of future net revenues of $336 MM after tax (2P reserves discounted at 10%, forecast pricing), essentially flat from year-end 2016.
- Canadian present value of future net revenues in USD (2P reserves discounted at 10%, forecast pricing after tax) increased 53% year over year to $119 MM despite lower commodity price forecasts and a reduction in undeveloped gas reserves. The 53% increase was primarily due to lower operating costs, lower future development capital and Cardium reserve additions during 2017.
- Egyptian present value of future net revenues in USD (2P reserves discounted at 10%, forecast pricing after tax) decreased 17% year over year to $216 MM primarily due to lower reserves and a lower commodity price forecast.
RESERVES
The Company’s 2017 and 2016 year-end reserves were prepared by GLJ Petroleum Consultants (“GLJ”) and DeGolyer and MacNaughton Canada Limited (“Degolyer”) respectively, as independent qualified reserves evaluators, in accordance with National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook.
GLJ were engaged to prepare the 2017 year-end reserves following the closure of Degolyer’s Calgary office. The Company’s selection of GLJ was based upon its domestic and extensive international experience. GLJ has worked with over 100 separate organizations encompassing petroleum assets in more than 50 countries.
The following is a summary of GLJ’s evaluation for the year ended December 31, 2017 dated January 9, 2018 (the “GLJ Report”). The recovery and reserve estimates of crude oil, natural gas liquids (“NGLs”) and conventional natural gas reserves provided in this news release are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and conventional natural gas reserves may be greater than, or less than, the estimates provided herein. All 2017 year end reserves presented are based on GLJ’s forecast pricing, effective January 1, 2018.
The following tables may not total due to rounding.
Table 1: Oil and Gas Reserves - Based on Forecast Prices and Costs1
| Effective December 31, 2017 | Light Crude Oil & Medium Crude Oil | Heavy Oil | Conventional Natural Gas | Natural Gas Liquids | BOE | |||||||||||||||
| Gross | Net2 | Gross | Net2 | Gross | Net2 | Gross | Net2 | Gross | Net2 | |||||||||||
| (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (Bcf) | (Bcf) | (MMbbl) | (MMbbl) | (MMboe) | (MMboe) | |||||||||||
| Proved Developed | ||||||||||||||||||||
| Producing | ||||||||||||||||||||
| Canada | 1.5 | 1.3 | — | — | 16.3 | 13.3 | 2.6 | 1.9 | 6.8 | 5.5 | ||||||||||
| Egypt | 1.7 | 1.1 | 11.0 | 6.1 | — | — | — | — | 12.7 | 7.2 | ||||||||||
| Non Producing | ||||||||||||||||||||
| Canada | 0.1 | — | — | — | 0.3 | 0.2 | — | — | 0.1 | 0.1 | ||||||||||
| Egypt | 0.3 | 0.2 | 1.5 | 0.8 | — | — | — | — | 1.8 | 1.0 | ||||||||||
| Total Proved Developed | 3.6 | 2.7 | 12.5 | 6.9 | 16.6 | 13.6 | 2.6 | 1.9 | 21.4 | 13.7 | ||||||||||
| Proved Undeveloped | ||||||||||||||||||||
| Canada | 2.5 | 2.2 | — | — | 6.4 | 5.7 | 1.0 | 0.8 | 4.5 | 4.1 | ||||||||||
| Egypt | 0.3 | 0.2 | 1.4 | 0.7 | — | — | — | — | 1.6 | 0.8 | ||||||||||
| Total Proved Undeveloped | 2.8 | 2.4 | 1.4 | 0.7 | 6.4 | 5.7 | 1.0 | 0.8 | 6.2 | 4.9 | ||||||||||
| Proved | ||||||||||||||||||||
| Canada | 4.1 | 3.6 | — | — | 22.9 | 19.3 | 3.5 | 2.8 | 11.4 | 9.6 | ||||||||||
| Egypt | 2.3 | 1.5 | 13.9 | 7.5 | — | — | — | — | 16.1 | 9 | ||||||||||
| Total Proved | 6.3 | 5.1 | 13.9 | 7.5 | 22.9 | 19.3 | 3.5 | 2.8 | 27.5 | 18.6 | ||||||||||
| Probable | ||||||||||||||||||||
| Canada | 2.2 | 2.0 | — | — | 17.4 | 15.8 | 2.7 | 2.4 | 7.8 | 7.0 | ||||||||||
| Egypt | 1.5 | 1.0 | 9 | 4.7 | — | — | — | — | 10.5 | 5.7 | ||||||||||
| Total Probable | 3.8 | 3.0 | 9 | 4.7 | 17.4 | 15.8 | 2.7 | 2.4 | 18.3 | 12.7 | ||||||||||
| Proved Plus Probable | ||||||||||||||||||||
| Canada | 6.3 | 5.5 | — | — | 40.3 | 35.1 | 6.2 | 5.1 | 19.3 | 16.5 | ||||||||||
| Egypt | 3.8 | 2.5 | 22.8 | 12.2 | — | — | — | — | 26.6 | 14.7 | ||||||||||
| Total Proved Plus Probable | 10.1 | 8.0 | 22.8 | 12.2 | 40.3 | 35.1 | 6.2 | 5.1 | 45.9 | 31.3 | ||||||||||
| Possible3 | ||||||||||||||||||||
| Canada | 1.4 | 1.1 | — | — | 17.2 | 15.2 | 2.2 | 1.9 | 6.5 | 5.6 | ||||||||||
| Egypt | 1.7 | 1.1 | 8.4 | 4.2 | — | — | — | — | 10.1 | 5.3 | ||||||||||
| Total Possible3 | 3.1 | 2.2 | 8.4 | 4.2 | 17.2 | 15.2 | 2.2 | 1.9 | 16.6 | 10.9 | ||||||||||
| Total Proved Plus Probable Plus Possible3 | 13.2 | 10.3 | 31.2 | 16.5 | 57.5 | 50.3 | 8.5 | 7.0 | 62.5 | 42.1 | ||||||||||
Note:
- The pricing assumptions used in the GLJ report with respect to the net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See “Forecast Prices used in Estimates”.
- Net reserves are the Company’s working interest share after the deduction of royalties. Net reserves in Egypt include the Company’s share of future cost recovery and production sharing oil after the Government’s royalty based interest but before reserves relating to income taxes payable. Under this method, a portion of the reported reserves will increase as oil prices decrease (and vice versa) as the barrels necessary to achieve cost recovery change with prevailing oil prices.
- 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.
2017 Reserve Changes
Reserves at 2017 year-end were lower compared to 2016 year-end primarily due to the production of ~5.7 MMboe, which was partially offset by ~1.6 MMboe (gross 2P reserve basis) of net positive revisions. The 1.6 MMboe of net positive revisions reflected positive technical revisions of ~4.7 MMboe offset by a ~3.1 MMBoe negative revision relating to Canadian undeveloped Mannville gas locations primarily due to lower natural gas price forecasts. The positive technical revisions of ~4.7 MMboe were attributed to; Egypt producing asset performance, Egypt discovery additions related to Northwest Gharib, and the addition of 10 undeveloped Cardium oil locations in Canada.
Egypt
In Egypt, the Company replaced 57% of 2017 production (~4.7 MMbbl) on a 1P gross reserve basis and 47% of 2017 production on a 2P gross reserve basis. The Company drilled one well in Northwest Gharib which resulted in a reserve addition. One additional NW Gharib well was drilled late in the fourth quarter, after the cutoff date for the 2017 evaluation, and will be included in the 2018 reserve evaluation. It was placed on production December 27th at an initial production rate of ~600 Bopd. One additional Arta Red Bed and one additional K-South development well were drilled representing undeveloped reserve conversions. Subsequent to December 31, 2017, one Arta Red Bed development well was drilled and rig released, representing a conversion of undeveloped reserves.
Egypt 2017 production was offset by the positive performance technical revisions in the West Gharib, West Bakr and Northwest Gharib concessions. In addition, the Company filed for and received its second, third, and fourth development leases in the Northwest Gharib concession during the year. Production from development leases 2 and 3 commenced prior to year-end 2017 and represented discovery reserve additions.
Canada
In Canada, the Company replaced 85% of 2017 production (~1 MMboe) on a 1P gross reserve basis and did not replace production on a 2P gross reserve basis. The Company drilled three Cardium formation oil wells (horizontal wells completed with multi-stage fracture stimulation) in the Harmattan area, of which two represented undeveloped reserve conversions, and one a new reserve addition.
Positive technical revisions were primarily attributed to the addition of 10 new undeveloped Cardium oil locations in the Harmattan area. The positive additions were largely offset by the negative technical revisions associated with undrilled natural gas in the Lone Pine/Harmattan areas. Negative technical revisions of 3.1 MMBoe were primarily attributed to undeveloped Mannville gas locations removed from the Company’s reserves which were deemed uneconomic due to a lower gas price forecast and reduced ultimate recovery assignments per well.
Conventional natural gas reserves represent approximately 15% on a boe basis of the Company’s total 2P reserve assignment as of December 31, 2017.
Estimated Future Net Revenues
The estimated future net revenues for the years December 31, 2017 and 2016 presented below in millions of U.S. dollars ($MM), are calculated using GLJ’s and DeGolyer’s price forecasts at December 31, 2017 and December 31, 2016 respectively. The 1% decrease in 2P future net revenues, notwithstanding an 8% reduction in gross 2P reserves, is primarily due to lower future development costs in Canada, a reduction in operating costs in both Egypt and Canada at year-end 2017 and offset by lower evaluator crude oil and natural gas price forecasts relative to year-end 2016.
All evaluations and reviews of future net revenues are stated prior to any provision 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. It should not be assumed that the estimated future net revenues shown below are representative of the fair market value of the Company’s properties. There is no assurance that such price and cost assumptions will be attained, and variances could be material. The recovery and reserve estimates of crude oil, NGL and natural gas reserves provided herein are estimates only, and there is no guarantee that the estimated reserves will be recovered.
All dollar amounts set forth in the tables below are in USD.
Table 2: Present Value of Future Net Reserves, After Tax ($MM) Independent Evaluator’s Price Forecast
| Present Value by Category | December 31, 2017 Discounted at | December 31, 2016 Discounted at | ||||||||||||||||||||||||||||
| — | % | 5 | % | 10 | % | 15 | % | 20 | % | — | % | 5 | % | 10 | % | 15 | % | 20 | % | |||||||||||
| Proved | $354 | $278 | $230 | $197 | $173 | $326 | $256 | $213 | $183 | $161 | ||||||||||||||||||||
| Proved plus Probable | $587 | $427 | $336 | $278 | $238 | $579 | $427 | $338 | $280 | $238 | ||||||||||||||||||||
| Proved plus Probable plus Possible | $792 | $548 | $420 | $343 | $291 | $822 | $566 | $433 | $350 | $293 | ||||||||||||||||||||
The following tables provide a breakdown of future net revenue by component and production group as at December 31, 2017 using forecast prices and costs.
Table 3: Present Value of Future Net Revenue - Based on Forecast Prices and Costs1
| Before Deducting Future Income Taxes2 Discounted At | After Deducting Future Income Taxes2 Discounted At | |||||||||||||||||||||||||||||
| Effective December 31, 2017 (MM$) | —% | 5% | 10% | 15% | 20% | —% | 5% | 10% | 15% | 20% | ||||||||||||||||||||
| Proved Developed | ||||||||||||||||||||||||||||||
| Producing | ||||||||||||||||||||||||||||||
| Canada | 96.9 | 74.9 | 60.8 | 51.1 | 44.2 | 96.9 | 74.9 | 60.8 | 51.1 | 44.2 | ||||||||||||||||||||
| Egypt | 145.1 | 128.7 | 116.3 | 106.7 | 99 | 145.1 | 128.7 | 116.3 | 106.7 | 99.0 | ||||||||||||||||||||
| Non Producing | ||||||||||||||||||||||||||||||
| Canada | 2.3 | 1.8 | 1.5 | 1.2 | 1.0 | 2.3 | 1.8 | 1.5 | 1.2 | 1.0 | ||||||||||||||||||||
| Egypt | 14.8 | 12.9 | 11.4 | 10.1 | 9.0 | 14.8 | 12.9 | 11.4 | 10.1 | 9.0 | ||||||||||||||||||||
| Total Proved Developed | 259 | 218.3 | 190 | 169.1 | 153.3 | 259 | 218.4 | 190 | 169.1 | 153.3 | ||||||||||||||||||||
| Proved Undeveloped | ||||||||||||||||||||||||||||||
| Canada | 91.6 | 52.7 | 31.8 | 19.6 | 12.0 | 78.5 | 46.3 | 28.4 | 17.8 | 11.0 | ||||||||||||||||||||
| Egypt | 16.1 | 13.6 | 11.6 | 10.0 | 8.7 | 16.1 | 13.6 | 11.6 | 10.0 | 8.7 | ||||||||||||||||||||
| Total Proved Undeveloped | 107.7 | 66.3 | 43.4 | 29.6 | 20.7 | 94.6 | 59.9 | 40.1 | 27.8 | 19.7 | ||||||||||||||||||||
| Proved | ||||||||||||||||||||||||||||||
| Canada | 190.8 | 129.4 | 94.0 | 71.9 | 57.3 | 177.7 | 123.0 | 90.7 | 70.1 | 56.3 | ||||||||||||||||||||
| Egypt | 175.9 | 155.2 | 139.3 | 126.8 | 116.7 | 175.9 | 155.2 | 139.3 | 126.8 | 116.7 | ||||||||||||||||||||
| Total Proved | 366.7 | 284.6 | 233.3 | 198.8 | 174 | 353.6 | 278.2 | 230 | 197 | 173 | ||||||||||||||||||||
| Probable | ||||||||||||||||||||||||||||||
| Canada | 154.2 | 73.4 | 39.6 | 23.4 | 14.8 | 112.5 | 53.4 | 28.7 | 17.0 | 10.8 | ||||||||||||||||||||
| Egypt | 121.1 | 94.9 | 76.9 | 64.1 | 54.5 | 121.1 | 94.9 | 76.9 | 64.1 | 54.5 | ||||||||||||||||||||
| Total Probable | 275.2 | 168.3 | 116.5 | 87.5 | 69.4 | 233.6 | 148.3 | 105.6 | 81 | 65.3 | ||||||||||||||||||||
| Proved Plus Probable | ||||||||||||||||||||||||||||||
| Canada | 344.9 | 202.8 | 133.5 | 95.3 | 72.1 | 290.2 | 176.5 | 119.4 | 87.1 | 67.0 | ||||||||||||||||||||
| Egypt | 297 | 250.1 | 216.3 | 190.9 | 171.3 | 297 | 250.1 | 216.3 | 190.9 | 171.3 | ||||||||||||||||||||
| Total Proved Plus Probable | 641.9 | 452.9 | 349.8 | 286.2 | 243.4 | 587.2 | 426.5 | 335.7 | 278 | 238.3 | ||||||||||||||||||||
| Possible | ||||||||||||||||||||||||||||||
| Canada | 135.3 | 58.3 | 31.0 | 19.0 | 12.9 | 98.7 | 42.5 | 22.6 | 14.0 | 9.6 | ||||||||||||||||||||
| Egypt | 106.0 | 79.0 | 62.1 | 50.7 | 42.7 | 106.0 | 79.0 | 62.1 | 50.7 | 42.7 | ||||||||||||||||||||
| Total Possible | 241.3 | 137.3 | 93.1 | 69.7 | 55.6 | 204.7 | 121.5 | 84.7 | 64.7 | 52.3 | ||||||||||||||||||||
| Total Proved Plus Probable Plus Possible | 883.3 | 590.2 | 442.9 | 356 | 299.0 | 791.9 | 548.0 | 420.3 | 342.7 | 290.6 | ||||||||||||||||||||
Note:
- The pricing assumptions used in the GLJ report with respect to the net present values of future net revenue (forecast) as well as inflation rates used for operating and capital costs are set forth herein. See “Forecast Prices used in Estimates”.
- In Egypt, under the terms of the PSC’s, income tax is current and assessed on all production sharing oil; therefore all Egypt future net revenues are after income tax.
Table 4: Future Net Revenue by Production Group Based on Forecast Prices and Costs1
| Effective December 31, 2017 | Before Income Taxes | Unit Value1, 2 | ||
| (MM$) | (Disc. at 10% Per Year)1, 2 | Disc. @10% ($/boe) | ||
| Proved Developed Producing | ||||
| Light Crude Oil & Medium Crude Oil (including Solution Gas) | 61.0 | 16.03 | ||
| Heavy Oil | 99.4 | 16.29 | ||
| Conventional Natural Gas | 4.3 | 4.11 | ||
| Natural Gas Liquids | 12.5 | 7.30 | ||
| Total Proved Developed Producing | 177.1 | 14.00 | ||
| Proved | ||||
| Light Crude Oil & Medium Crude Oil (including Solution Gas) | 100.1 | 12.05 | ||
| Heavy Oil | 116.6 | 15.44 | ||
| Conventional Natural Gas | 4.3 | 3.97 | ||
| Natural Gas Liquids | 12.4 | 7.41 | ||
| Total Proved | 233.3 | 12.54 | ||
| Proved Plus Probable | ||||
| Light Crude Oil & Medium Crude Oil (including Solution Gas) | 148.1 | 11.4 | ||
| Heavy Oil | 180.4 | 14.73 | ||
| Conventional Natural Gas | 4.4 | 1.66 | ||
| Natural Gas Liquids | 16.8 | 5.01 | ||
| Total Probable Plus Probable | 349.8 | 11.19 | ||
| Proved Plus Probable Plus Possible | ||||
| Light Crude Oil & Medium Crude Oil (including Solution Gas) | 186.9 | 11.45 | ||
| Heavy Oil | 228.0 | 13.86 | ||
| Conventional Natural Gas | 3.3 | 0.79 | ||
| Natural Gas Liquids | 24.6 | 4.81 | ||
| Total Proved Plus Probable Plus Possible | 442.9 | 10.51 | ||
Notes
- The unit values are based on net reserves volumes before income tax (BFIT)
- In Egypt, under the terms of the PSC’s, income tax is current and assessed on all production sharing oil; therefore all Egypt future net revenues are after income tax.
Pricing used in the forecast price estimates are set forth in the tables below.
Table 5: Forecast Prices used in Estimates effective January 1, 2018
| Light Crude Oil and Medium Crude Oil | Conventional Natural Gas | Natural Gas Liquids - Edmonton | Inflation Rate | Exchange Rate | |||||||||||||||||||||||||
| Year | WTI Cushing Oklahoma (USD/bbl) | Edmonton Par Price 40oAPI (CAD/bbl) | Brent (USD/bbl) | AECO Gas Price (CAD/ MMBtu) | Ethane (CAD/bbl) | Propane (CAD/ bbl) | Butane (CAD/ bbl) | Pentane (CAD/ bbl) | % Per Year | (USD/ CAD) | |||||||||||||||||||
| 2018 | 59.00 | 70.25 | 65.50 | 2.20 | 6.75 | 40.4 | 53.74 | 76.42 | 2 | 0.79 | |||||||||||||||||||
| 2019 | 59.00 | 70.25 | 63.50 | 2.54 | 7.95 | 36.53 | 49.18 | 74.68 | 2 | 0.79 | |||||||||||||||||||
| 2020 | 60.00 | 70.31 | 63.00 | 2.88 | 9.12 | 35.93 | 49.22 | 74.38 | 2 | 0.80 | |||||||||||||||||||
| 2021 | 63.00 | 72.84 | 66.00 | 3.24 | 10.34 | 36.06 | 50.99 | 77.16 | 2 | 0.81 | |||||||||||||||||||
| 2022 | 66.00 | 75.61 | 69.00 | 3.47 | 11.14 | 36.29 | 52.93 | 79.88 | 2 | 0.82 | |||||||||||||||||||
| 2023 | 69.00 | 78.31 | 72.00 | 3.58 | 11.51 | 37.59 | 54.82 | 82.53 | 2 | 0.83 | |||||||||||||||||||
| 2024 | 72.00 | 81.93 | 75.00 | 3.66 | 11.76 | 39.33 | 57.35 | 86.14 | 2 | 0.83 | |||||||||||||||||||
| 2025 | 75.00 | 85.54 | 78.00 | 3.73 | 12.02 | 41.06 | 59.88 | 89.76 | 2 | 0.83 | |||||||||||||||||||
| 2026 | 77.33 | 88.35 | 80.33 | 3.80 | 12.27 | 42.41 | 61.84 | 92.57 | 2 | 0.83 | |||||||||||||||||||
| 2027 | 78.88 | 90.22 | 81.88 | 3.88 | 12.53 | 43.3 | 63.15 | 94.43 | 2 | 0.83 | |||||||||||||||||||
| 2028+ | Escalate oil, gas and product prices at 2.0% per year thereafter | 2 | 0.83 | ||||||||||||||||||||||||||
The following table summarizes GLJ’s and DeGolyer’s reference price forecast used to estimate future net revenues for Egypt effective December 31, 2017 and December 31, 2016 respectively.
Table 6: Reconciliation of Brent Price Forecast
| Brent Forecast Pricing (USD/bbl) | 2018 | 2019 | 2020 | 2021 | 2022 | |||||
| Year-end 2017 | 65.50 | 63.50 | 63.00 | 66.00 | 69.00 | |||||
| Year-end 2016 | 60.36 | 64.66 | 70.18 | 73.75 | 73.75 |
Table 7: Reconciliations of Changes in Reserves
The following tables detail reconciliation of the changes in TransGlobe’s gross light and medium crude oil, heavy oil, associated and non-associated (combined) conventional natural gas and NGL reserves as at December 31, 2017 compared to such reserves as at December 31, 2016.
| TOTAL COMPANY | Light Crude Oil & Medium Crude Oil | Heavy Oil | Conventional Natural Gas | |||||||||||||||
| Factors | Proved (MMbbl) | Probable (MMbbl) | Proved + Probable (MMbbl) | Proved (MMbbl) | Probable (MMbbl) | Proved + Probable (MMbbl) | Proved (Bcf) | Probable (Bcf) | Proved + Probable (Bcf) | |||||||||
| At December 31, 2016 | 6.2 | 3.5 | 9.7 | 15.6 | 9.1 | 24.7 | 24.1 | 21.8 | 45.9 | |||||||||
| Discoveries | — | — | — | 0.4 | 0.6 | 1.0 | — | — | — | |||||||||
| Extensions & Improved Recovery | 0.8 | 0.6 | 1.4 | — | — | — | 1.9 | 1.5 | 3.4 | |||||||||
| Technical Revisions | — | (0.4 | ) | (0.4 | ) | 2.1 | (0.7 | ) | 1.5 | (0.5 | ) | (5.9 | ) | (6.4 | ) | |||
| Acquisitions | — | 0.1 | 0.1 | — | — | — | — | 0.2 | 0.2 | |||||||||
| Dispositions | — | — | — | — | — | — | — | — | — | |||||||||
| Economic Factors | — | — | (0.3 | ) | — | (0.1 | ) | (0.1 | ) | (0.2 | ) | (0.2 | ) | (0.5 | ) | |||
| Production | (0.7 | ) | — | (0.7 | ) | (4.3 | ) | — | (4.3 | ) | (2.4 | ) | — | (2.4 | ) | |||
| At December 31, 2017 | 6.3 | 3.8 | 10.1 | 13.9 | 8.9 | 22.8 | 22.9 | 17.4 | 40.3 | |||||||||
| Natural Gas Liquids | BOE | |||||||||||
| Factors | Proved (MMbbl) | Probable (MMbbl) | Proved + Probable (MMbbl) | Proved (MMboe) | Probable (MMboe) | Proved + Probable (MMboe) | ||||||
| At December 31, 2016 | 4.1 | 3.8 | 7.9 | 29.9 | 20.1 | 50 | ||||||
| Discoveries | — | — | — | 0.4 | 0.6 | 1.0 | ||||||
| Extensions & Improved Recovery | 0.3 | 0.3 | 0.6 | 1.4 | 1.1 | 2.6 | ||||||
| Technical Revisions | (0.4 | ) | (1.4 | ) | (1.8 | ) | 1.6 | (3.4 | ) | (1.8 | ) | |
| Acquisitions | — | — | — | — | 0.2 | 0.2 | ||||||
| Dispositions | — | — | — | — | — | — | ||||||
| Economic Factors | — | — | (0.1 | ) | (0.2 | ) | (0.1 | ) | (0.3 | ) | ||
| Production | 0.4 | — | 0.4 | (5.7 | ) | — | (5.7 | ) | ||||
| At December 31, 2017 | 3.5 | 2.7 | 6.2 | 27.5 | 18.3 | 45.9 | ||||||
| CANADA | Light Crude Oil & Medium Crude Oil | Heavy Oil | Conventional Natural Gas | |||||||||||||||
| Factors | Proved (MMbbl) | Probable (MMbbl) | Proved + Probable (MMbbl) | Proved (MMbbl) | Probable (MMbbl) | Proved + Probable (MMbbl) | Proved (Bcf) | Probable (Bcf) | Proved + Probable (Bcf) | |||||||||
| At December 31, 2016 | 3.6 | 1.7 | 5.2 | — | — | — | 24.1 | 21.9 | 45.9 | |||||||||
| Discoveries | — | — | — | — | — | — | — | — | — | |||||||||
| Extensions & Improved Recovery | 0.8 | 0.6 | 1.4 | — | — | — | 1.9 | 1.5 | 3.4 | |||||||||
| Technical Revisions | (0.1 | ) | (0.1 | ) | (0.2 | ) | — | — | — | (0.5 | ) | (5.9 | ) | (6.4 | ) | |||
| Acquisitions | — | 0.1 | 0.1 | — | — | — | — | 0.2 | 0.2 | |||||||||
| Dispositions | — | — | — | — | — | — | — | — | — | |||||||||
| Economic Factors | — | — | — | — | — | — | (0.2 | ) | (0.2 | ) | (0.5 | ) | ||||||
| Production | (0.2 | ) | — | (0.2 | ) | — | — | — | (2.4 | ) | — | (2.4 | ) | |||||
| At December 31, 2017 | 4.1 | 2.3 | 6.3 | — | — | — | 22.9 | 17.5 | 40.3 | |||||||||
| Natural Gas Liquids | BOE | |||||||||||||||||
| Factors | Proved (MMbbl) | Probable (MMbbl) | Proved + Probable (MMbbl) | Proved (MMboe) | Probable (MMboe) | Proved + Probable (MMboe) | ||||||||||||
| At December 31, 2016 | 4.1 | 3.8 | 7.9 | 11.7 | 9.1 | 20.7 | ||||||||||||
| Discoveries | — | — | — | — | — | — | ||||||||||||
| Extensions & Improved Recovery | 0.3 | 0.3 | 0.6 | 1.4 | 1.1 | 2.6 | ||||||||||||
| Technical Revisions | (0.4) | (1.4) | (1.8) | (0.6) | (2.5) | (3.1) | ||||||||||||
| Acquisitions | — | — | — | — | 0.2 | 0.2 | ||||||||||||
| Dispositions | — | — | — | — | — | — | ||||||||||||
| Economic Factors | — | — | (0.1) | (0.1) | (0.1) | (0.2) | ||||||||||||
| Production | (0.4) | — | (0.4) | (1.0) | — | (1.0) | ||||||||||||
| At December 31, 2017 | 3.5 | 2.7 | 6.2 | 11.4 | 7.8 | 19.3 | ||||||||||||
| EGYPT | Light Crude Oil & Medium Crude Oil | Heavy Oil | Conventional Natural Gas | |||||||||||||||
| Factors | Proved (MMbbl) | Probable (MMbbl) | Proved + Probable (MMbbl) | Proved (MMbbl) | Probable (MMbbl) | Proved + Probable (MMbbl) | Proved (Bcf) | Probable (Bcf) | Proved + Probable (Bcf) | |||||||||
| At December 31, 2016 | 2.7 | 1.8 | 4.5 | 15.6 | 9.1 | 24.7 | — | — | — | |||||||||
| Discoveries | — | — | — | 0.4 | 0.6 | 1.0 | — | — | — | |||||||||
| Extensions & Improved Recovery | — | — | — | — | — | — | — | — | — | |||||||||
| Technical Revisions | 0.1 | (0.3 | ) | (0.2 | ) | 2.1 | (0.7 | ) | 1.5 | — | — | — | ||||||
| Acquisitions | — | — | — | — | — | — | — | — | — | |||||||||
| Dispositions | — | — | — | — | — | — | — | — | — | |||||||||
| Economic Factors | (0.1 | ) | — | — | — | (0.1 | ) | (0.1 | ) | — | — | — | ||||||
| Production | (0.5 | ) | — | (0.5 | ) | (4.3 | ) | — | (4.3 | ) | — | — | — | |||||
| At December 31, 2017 | 2.2 | 1.5 | 3.8 | 13.9 | 9.0 | 22.8 | — | — | — | |||||||||
| Natural Gas Liquids | BOE | |||||||||||
| Factors | Proved (MMbbl) | Probable (MMbbl) | Proved + Probable (MMbbl) | Proved (MMboe) | Probable (MMboe) | Proved + Probable (MMboe) | ||||||
| At December 31, 2016 | — | — | — | 18.3 | 11.0 | 29.3 | ||||||
| Discoveries | — | — | — | 0.4 | 0.6 | 1.0 | ||||||
| Extensions & Improved Recovery | — | — | — | — | — | — | ||||||
| Technical Revisions | — | — | — | 2.2 | (1 | ) | 1.2 | |||||
| Acquisitions | — | — | — | — | — | — | ||||||
| Dispositions | — | — | — | — | — | — | ||||||
| Economic Factors | — | — | — | (0.1 | ) | (0.1 | ) | (0.1 | ) | |||
| Production | — | — | — | (4.7 | ) | — | (4.7 | ) | ||||
| At December 31, 2017 | — | — | — | 16.1 | 10.5 | 26.6 | ||||||
All evaluations and reviews of future net revenues are stated prior to any provision 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. It should not be assumed that the estimated future net revenues shown below are representative of the fair market value of the Company’s properties. There is no assurance that such price and cost assumptions will be attained, and variances could be material. The recovery and reserve estimates of crude oil, NGL and natural gas reserves provided herein are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.
TransGlobe Energy Corporation is a Calgary-based, growth-oriented 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 under the symbol TGL and on the NASDAQ Exchange under the symbol TGA.
Advisory on Forward-Looking Information and Statements
Certain statements included in this news release constitute forward-looking statements or forward-looking information under applicable securities legislation. Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "may", "will", "would" or similar words suggesting future outcomes or statements regarding an outlook. In particular, forward-looking information and statements contained in this document include, but are not limited to, statements relating to "reserves" which are, by their nature, forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves or resources, as applicable, described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. The recovery and reserve estimates of TransGlobe's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. Many factors could cause TransGlobe's actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, TransGlobe.
In addition to other factors and assumptions which may be identified in this news release, assumptions have been made regarding, among other things, anticipated production volumes; the timing of drilling wells and mobilizing drilling rigs; the number of wells to be drilled; the Company's ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct its business; future capital expenditures to be made by the Company; future sources of funding for the Company's capital programs; geological and engineering estimates in respect of the Company's reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities; current commodity prices and royalty regimes; availability of skilled labour; future exchange rates; the price of oil; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; future operating costs; uninterrupted access to areas of TransGlobe's operations and infrastructure; recoverability of reserves and future production rates; that TransGlobe will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that TransGlobe's conduct and results of operations will be consistent with its expectations; that TransGlobe will have the ability to develop its properties in the manner currently contemplated; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; that the estimates of TransGlobe's reserves and resource volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; and other matters.
Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These risks and uncertainties which may cause actual results to differ materially from the forward-looking statements or information include, among other things, operating and/or drilling costs are higher than anticipated; unforeseen changes in the rate of production from TransGlobe's oil and gas properties; changes in price of crude oil and natural gas; adverse technical factors associated with exploration, development, production or transportation of TransGlobe's crude oil reserves; changes or disruptions in the political or fiscal regimes in TransGlobe's areas of activity; changes in tax, energy or other laws or regulations; changes in significant capital expenditures; delays or disruptions in production due to shortages of skilled manpower equipment or materials; economic fluctuations; competition; lack of availability of qualified personnel; the results of exploration and development drilling and related activities; obtaining required approvals of regulatory authorities; volatility in market prices for oil; fluctuations in foreign exchange or interest rates; environmental risks; ability to access sufficient capital from internal and external sources; failure of counterparties to perform under the terms of their contracts; and other factors beyond the Company's control. Readers are cautioned that the foregoing list of factors is not exhaustive. Please consult TransGlobe’s public filings at www.sedar.com and www.sec.gov/edgar.shtml for further, more detailed information concerning these matters, including additional risks related to TransGlobe's business.
The forward-looking statements or information contained in this news release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward-looking statements or information contained in this news release are expressly qualified by this cautionary statement.
Oil & Gas Information
Certain Defined Terms
"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% probability that the actual remaining quantities recovered will equal or exceed the sum of the estimated proved + probable + possible reserves.
“Gross Reserves” are the Company’s working interest (operating and non-operating) share before deduction of royalties and without including any royalty interests of the Company.
“Net Reserves” are the Company’s working interest share after the deduction of royalties. Net reserves in Egypt include the Company’s share of future cost recovery and production sharing oil after the Government’s royalty based interest but before reserves relating to income taxes payable. Under this method, a portion of the reported reserves will increase as oil prices decrease (and vice versa) as the barrels necessary to achieve cost recovery change with prevailing oil prices.
“Developed” reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.
“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 on production, and the date of resumption or production must be known with reasonable certainty.
“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 is unknown.
“Undeveloped” reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, 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 classifications (proved, probable, possible) to which they are assigned.
This press release discloses estimates of light and medium crude oil and heavy oil. Light crude oil is crude oil with a relative density greater than 31.1 degrees API gravity, medium crude oil is crude oil with a relative density greater than 22.3 degrees API gravity and less than or equal to 31.1 degrees API gravity, and heavy crude oil is crude oil with a relative density greater than 10 degrees API gravity and less than or equal to 22.3 degrees API gravity.
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf: 1 bbl) 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 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
The discounted and undiscounted net present value of future net revenues attributable to the reserves disclosed herein do not represent the fair market value of such reserves. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
This press release contains a number of oil and gas metrics, including the percentage replacement of 2017 production, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods. Replacement of production ratio is defined as the change in period reserves excluding economic and acquisition and divestures factors divided by the period production.
The following abbreviations used in this press release have the meanings set forth below:
bbls barrels
MMbbls million barrels
boe barrels of oil equivalent of natural gas, on the basis of one barrel of oil or NGLs for six thousand cubic feet of natural gas
MMboe million of barrels oil equivalent
NPV net present value of future net revenues mcf thousand cubic feet
Bcf billion cubic feet
NGL Natural Gas Liquids
| For further information, please contact: |
| Investor Relations |
| Telephone: 403.264-9888 |
| Email: investor.relations@trans-globe.com |
| Web site: http://www.trans-globe.com |