CALGARY, ALBERTA--(Marketwired - April 6, 2016) - Tanager (TSX VENTURE:TAN) is pleased to present its first annual reserves report following recompletion of its first oil well at Joffre, Alberta in 2015.
Highlights
| • | Proved plus probable reserves of: | ||
| • | Oil and NGLs | 603 Mboe | |
| • | Natural Gas | 3,609 MMcf (602 Mboe) | |
| • | Total Proved plus Probable | 1,205 Mboe | |
| • | Proved plus Probable Net Asset Value of $0.16/share | ||
Tanager Energy Inc.'s (the Company) oil and gas reserves were evaluated by Deloitte LLP (Deloitte), effective December 31, 2015. Deloitte was engaged by the Company to evaluate proved and proved plus probable reserves: no valuation of possible reserves or resources was undertaken. The Deloitte evaluation was prepared in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook").
All of the Company's oil and gas reserves are located ten miles northeast of Red Deer, Alberta in sections 22 and 23, township 39, range 26 W4M.
Reserves Summary
| Barrels of Oil | ||||
| Oil | Natural Gas | Natural Gas Liquids | Equivalent | |
| (Mbbl) | (MMCF) | (Mbbl) | (Mboe) | |
| Proved | ||||
| Developed Producing | 14.2 | 38.5 | 1.2 | 21.8 |
| Developed, Non-Producing | 142.1 | 689.2 | 23.9 | 280.9 |
| Undeveloped | 33.9 | 372.7 | 25.5 | 111.5 |
| Total Proved | 190.2 | 1,100.4 | 40.5 | 414.2 |
| Probable | 269.5 | 2,508.7 | 102.6 | 790.2 |
| Total Proved plus Probable | 459.7 | 3,609.1 | 143.1 | 1,204.4 |
Notes
- The tables summarize the data contained in the Deloitte report and as a result may contain slightly different numbers due to rounding.
- The reserves reported above are after deductions of royalties payable to others
- It should not be assumed that the discounted net present value of future net revenue attributable to the Company's reserves estimated by Deloitte represents the fair market value of those reserves.
- The recovery and reserve estimates of the Company's oil NGL and natural gas reserves provided herein are estimates only and there is nor guarantee that the estimated reserves will be recover. Actual reserves may be greater than or less that the estimates provided herein.
Net Asset Value
| NPV 5%(M$) | $/share | NPV 10%(M$) | $/share | |||||
| Proved | ||||||||
| Developed Producing | -21.0 | 0.000 | 32.6 | 0.001 | ||||
| Developed, Non-Producing | 2,465.6 | 0.045 | 1,721.9 | 0.031 | ||||
| Undeveloped | 1,285.4 | 0.023 | 937.8 | 0.017 | ||||
| Total Proved | 3730.0 | 0.067 | 2692.3 | 0.049 | ||||
| Probable | 10,150.0 | 0.183 | 6,972.2 | 0.126 | ||||
| Total Proved plus Probable | 13,880.0 | 0.251 | 9,664.5 | 0.174 | ||||
| Net Debt | (983.0 | ) | (0.018 | ) | (983.0 | ) | (0.018 | ) |
| Net Asset Value | 12897.0 | 0.233 | 8681.5 | 0.157 |
Notes
- The net asset value of future net revenue is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs other income and future capital expenditures.
- Basic shares outstanding of 55.41 million.
- Financial information is based on the Company's preliminary estimate of 2015 year-end results and is therefore subject to change.
Summary of Pricing and Inflation Rate Assumptions - Forecast Prices and Costs
Forecast oil and gas prices are laid out in the Deloitte Price Forecast December 31, 2015 Table. All prices are stated in Canadian dollars unless otherwise indicated. Adjustments for oil differential and gas heating values are applied to these prices, as appropriate for each entity. Capital and operating costs are inflated.
| Year | Exchange Rate (CAD/USD) |
WTI Cushing Oklahoma 40 API (USD/bbl) |
Edmonton City Gate (CAD/bbl) |
Pentanes Plus And Condensate (CAD/bbl) |
Natural Gas AECO (CAD/mmbtu) |
| 2016 | 0.740 | 42.00 | 55.86 | 51.35 | 2.45 |
| 2017 | 0.770 | 48.25 | 64.00 | 57.65 | 2.85 |
| 2018 | 0.800 | 57.20 | 68.39 | 66.35 | 3.10 |
| 2019 | 0.800 | 66.35 | 73.75 | 77.65 | 3.45 |
| 2020 | 0.800 | 75.75 | 78.79 | 89.30 | 3.75 |
| 2021 | 0.800 | 82.80 | 82.35 | 98.00 | 4.15 |
| 2022 | 0.800 | 90.10 | 88.24 | 107.00 | 4.40 |
| 2023 | 0.800 | 91.90 | 94.12 | 109.15 | 4.65 |
| 2024 | 0.800 | 93.75 | 96.48 | 111.30 | 5.00 |
| 2025 | 0.800 | 95.60 | 98.41 | 113.55 | 5.15 |
| 2026+ | 0.800 | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr |
Additional information relating to reserves data
Undeveloped reserves
Proved undeveloped and proved plus probable undeveloped reserves have been assigned to a location producing from the Leduc Formation with an on-stream date of August 2018. The reserves for the location C5 - LC/00-23-039-26W4/A, are based on the offset producing well, C1 - 02/05-23-039-26W4/0.
Significant factors or uncertainties
The process of estimating reserves is complex. It requires significant judgment and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, commodity prices and economic conditions. The Corporation's reserves are evaluated by Deloitte, an independent engineering firm.
Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, commodity prices, economic conditions and governmental restrictions. Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. The Company's actual production, revenues, taxes, development and operating expenditures with respect to its reserves may vary from such estimates, and such variances could be material. Reserve estimates are subject to change with such factors as, updated production data, well performance and operational issues, ongoing development activities, price forecasts, and other economic conditions.
Geology
Leduc
The Late Devonian Leduc formation is represented by large barrier reef and smaller pinnacle reef bioherms which grew on the Cooking Lake platform carbonates. Trending northeast to southwest, the limestones and dolostones of the Leduc/Cooking Lake Formations were deposited on the bathymetric highs of the Late Devonian seas. Hydrocarbons are trapped by lateral stratigraphic pinch out of these dolomitic carbonates into deeper water shale sediments.
Horseshoe Canyon/Bearpaw
The Horseshoe Canyon Formation is part of the Upper Cretaceous Edmonton group which lies unconformably on top of the Belly River Group and is overlain by the tertiary Scollard Formation. Sediments of the Horseshoe Canyon were deposited in a complex coastal environment with shore face sands, tidal channel sands, distributary sands and large back barrier peat bog swamps. The result of such an environment is a stratigraphic section of approximately 100 to 400 m thick with the lower to middle Horseshoe Canyon containing multiple prospective coal seams and sandstones.
Basal Belly River/Pakowki
The Upper Cretaceous Basal Belly River/Pakowki Formations represent a marginal marine fluvial/deltaic environment that deposited clastic sediments in series of north-south trending bar sands. Reservoirs are developed in sandstone lobes, and to a lesser extent, channel sands, as river systems supplied sediments to the prograding delta. Gas pools that are developed in deltaic lobe sandstones trapped stratigraphically as the reservoir sands grade laterally into siltstone and shale.
Upper Mannville
The Early Cretaceous Upper Mannville Group consists of sandstones, siltstones, shales and coals deposited in a fluvial environment in which shorelines and sediments were moving northward. Sandstones of the Upper Mannville contain a significant amount of volcanic and feldspathic material. Hydrocarbons are trapped stratigraphically within porous sandstones that are truncated by tight, lithic Upper Mannville channels in an updip position or as the sandstones pinch-out or grade laterally into the surrounding siltstones and shales.
Gross and net oil and gas wells
| Oil | Gas | Non-producing | Total | ||||||
| Country/Province | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |
| Canada | |||||||||
| Alberta | 1.0 | 0.5 | 0.0 | 0.0 | 5.0 | 2.4 | 6.0 | 2.9 | |
| Total | 1.0 | 0.5 | 0.0 | 0.0 | 5.0 | 2.4 | 6.0 | 2.9 | |
Properties with no attributed reserves
Proved developed producing reserves have been assigned to the B1 - D0/15-22-039-26W4/0 oil well. The well was re-activated and came on production in January 2015. The well has produced sporadically since January averaging seven to ten days of production per month. Tanager plans on installing pumping equipment on the well in early 2016 to enhance performance. The production forecasts have taken into account this workover and reflects the increase of reserves in the total proved and proved plus probable cases.
The B2 - 00/10-22-039-26W4/0, B3 - 02/10-22-039-26W4/0, and B4 - 00/14-22-039-26W4/2 oil wells are scheduled to be re-activated in 2016. Proved reserves are assigned to these wells as the wells have demonstrated production over a number of years. The production forecasts are based on historical decline before the wells watered out and accounts for the fact that there will be lower drawdowns to minimize water coning.
Within the Project C, the horizontal well C1 - 02/05-23-039-26W4/0 which was suspended since December 2008, is to be whipstocked in a southeast direction in the Leduc Formation and is estimated to start production July 2017. Proved reserves are assigned as this well has demonstrated production over a number of years. The well appeared to water out in 2008. Production decline is based on historical decline at this well before watering out and accounts for the fact that there will be lower drawdowns to minimize water coning. Higher production rates are expected since the whipstocked well is to be completed higher in the Leduc Formation.
Proved undeveloped and proved plus probable undeveloped reserves have been assigned to a location producing from the Leduc Formation with an on-stream date of August 2018. The reserves for the location C5 - LC/00-23-039-26W4/A, are based on the offset producing well, C1 - 02/05-23-039-26W4/0. The capital for the location is estimated by Deloitte.
Forward contracts
There are no forwards contracts in place.
Tax Horizon
The Company is expected to begin paying income tax in 2019 based on proved plus probable cash flow economics.
Costs incurred
The following table summarizes Company's property acquisition costs, exploration costs and development costs incurred during the financial year ended December 31, 2015:
| Property Acquisitions and Capital Expenditures | ||
| Nature of Cost | Amount ($) |
|
| Property Acquisition Costs | ||
| Proved | 110,000 | |
| Unproved | - | |
| Exploration Costs | - | |
| Development Costs | 314,970 | |
| Total | 424,970 | |
Exploration and development activities
During 2015, the 1D/0-15-22-39-36W4 well was recompleted and place on production as a flowing oil well.
Production estimates
The following table discloses the total working interest volume for 2016 for each product type associated with the first year of the gross proved reserves and gross probable reserves reported in the Deloitte report effective December 31, 2015, based on forecast prices and costs:
Production history
The following table summarizes the share of the Company's average daily production, prices received, royalties paid, production expenses, and operating netbacks for the periods indicated:
| Total Company | |||||
| Q1 2015 | Q2 2015 | Q3 2015 | Q4 2015 | ||
| Volumes | |||||
| light oil + NGLs, bopd | 0 | 8 | 14 | 9 | |
| gas, Mcf/d | 0 | 31 | 62 | 49 | |
| Boe/d | 0 | 13 | 24 | 17 | |
| Light Oil and NGLs | |||||
| averages, $/bbl | |||||
| price | 0.00 | 66.38 | 55.49 | 52.35 | |
| Gas | |||||
| averages, $/Mcf | |||||
| price | 0 | 2.78 | 2.96 | 2.62 | |
| Royalties paid | 0.00 | 4,226.58 | 5,923.59 | 3,665.54 | |
| Operating cost | 0.00 | 26,250.37 | 38,397.44 | 33,919.30 | |
| Netback $/Boe) | 0.00 | -15.74 | 9.13 | -1.56 | |
Future Development Costs
| Undiscounted future costs net (M$) |
Discounted (10%) future costs net (M$) |
|||
| Year | Proved | Proved + probable | Proved | Proved + probable |
| 2016 | 900.0 | 900.0 | 872.17 | 872.17 |
| Total | 900.0 | 900.0 | 872.17 | 872.17 |
Capital expenditures forecast for pumpjack installation in early 2016 to enhance performance, well re-entry and re-activation, whipstock well to bring back on production and also drill, complete and tie-in.
Reserve definitions
Reserves are classified in accordance with the following definitions which meet the standards established by National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities and found in Appendix 1 to Companion Policy 51-101 CP, Part 2 Definition of Reserves.
Reserve categories
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on
- analysis of drilling, geological, geophysical and engineering data;
- the use of established technology; and
- specified economic conditions, which are generally accepted as being reasonable and are disclosed.
Reserves are classified according to the degree of certainty associated with the estimates:
| 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. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. |
Development and production status
Each of the reserves categories (proved, probable and possible) may be divided into developed and undeveloped categories:
| 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 (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing. | ||
| 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 of 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 of production 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 classification (proved, probable, possible) to which they are assigned. | ||
Tanager Energy Inc. is a Lethbridge, Alberta based corporation engaged in the exploration for oil and gas and minerals, with an operations office in Calgary, Alberta. The Corporation's common shares are listed on the TSX Venture Exchange under the trading symbol "TAN".
Reader Advisory
Forward Looking and Cautionary Statements
Certain statements contained in this press release may constitute forward-looking statements. All statements other than statements of historical fact may be forward-looking statements. Forward‐looking statements are necessarily based upon assumptions and judgments with respect to the future. In some cases, forward‐looking statements can be identified by terminology such as "may", "will", "should", "expect", "projects", "plans", "anticipates" and similar expressions. These statements represent management's expectations or beliefs concerning, among other things, future operating results and various components thereof affecting the economic performance of Tanager. Undue reliance should not be placed on these forward‐looking statements which are based upon management's assumptions and are subject to known and unknown risks and uncertainties, including the business risks discussed above, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward‐looking statements. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted. These statements speak only as of the date specified in the statements. The Corporation's actual results could differ materially from those anticipated in the forward looking statements contained throughout this news release as a result of the material risk factors set forth below:
- liabilities inherent in oil and natural gas operations;
- geological, technical, drilling and processing problems; and
- general business and market conditions.
- These factors should not be construed as exhaustive. Unless required by law, the Corporation does not undertake any obligation to publicly update or revise any forward looking statements, whether as a result of new information, future events or otherwise.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.
Contact Information:
President and Chief Executive Officer
403-388-0969
john@tanagerenergy.com