YANGARRA RESOURCES LTD. Operations Update
In 2019 Yangarra achieved several key milestones, including the construction of a 100% owned gas plant, the doubling of capacity on one of its existing gas plants, the addition of a new core area and additional ESG initiatives that will benefit Yangarra shareholders from 2020 onwards as the Company transitions to free cash flow generation.
Yangarra originally planned to drill & complete 24 wells in 2019; however, budget was re-directed to infrastructure to accommodate Chedderville opportunities and as a result elected to drill & complete 17 wells in 2019.
Despite the limited drilling program, Yangarra's yearly average production was 12,550 boe/d (33% growth from an average of 9,425 boe/d in 2018) with fourth quarter production expected to average 12,500 boe/d. The average production is lower than guidance due to the reduced drilling & completions program. The infrastructure capital spend in the first quarter of 2019 resulted in lower operating costs and the reduced costs are reflected in the Company's independent reserves report as prepared by
The Company recognized in late Q4 that industry was rapidly mobilizing in
As highlighted by recent well results, Yangarra plans to focus the 2020 program primarily on higher IRR wells in the Chedderville area and will continue to implement the Company's refined completions strategy that had positive results in late 2019.
Yangarra's land position in Chedderville has increased from 9.5 sections,
Updated Corporate Presentation
An updated corporate presentation is available on the Company website: www.yangarra.ca.
Reserve Report Highlights:
All reserves information contained in this press release is based on the 2019 Reserve Report. Unless specifically indicated, all financial and operational information in this press release is based on estimates and is unaudited and accordingly, such financial information is subject to change based on the results of the Company's year-end audit.
Proved Developed Producing ("PDP") Reserves
- 25.5 million boe (9% increase from 2018)
- Net present value before tax discounted at 10% ("NPV10") of
$414 million (5% increase from 2018), including abandonment capital for all producing and non-producing wells - Finding and development costs ("F&D") of
$18.10 /boe, resulting in a PDP recycle ratio of 1.24 times; 2019 F&D costs were impacted by the significant facilities spending in the first quarter. This allowed Yangarra to both reduce its corporate operating costs on its existing plays and allowed Yangarra to maintain its low-cost structure throughout the new Chedderville area - PDP net asset value per fully diluted common share ("NAV per FD Share") of
$2.63 - PDP additions replaced 146% of 2019 production
- PDP reserve additions were impacted by the testing of 15 tons per stage on completions during 2019, upon evaluation Yangarra discovered the old program of 20 tons per stage provided significantly better results and those improvements are reflected in the 1P and 2P bookings
Proved Non-Producing ("PNP") Reserves
- 2.2 million boe
- NPV10 of
$40 million - The majority of the PNP value consists of the three wells that were drilled before year-end. All these wells are now producing
- PDP + PNP NAV per FD Share of
$3.08
Total Proved reserves ("1P")
- 85.6 million boe (13% increase from 2018)
- NPV10 of
$1.1 billion (no change from 2018) - The Deloitte price forecast was 10-15% lower in the later years for all products for the 2019 report versus 2018
- 1P future development costs of
$429 million - F&D costs of
$10.74 /boe resulting in a recycle ratio of 2.08 times - 1P NAV per FD Share of
$10.66 - 1P Reserve Life Index ("RLI") based on fourth quarter 2019 production of 18.8 years
- 1P additions replaced 320% of 2019 production
Proved plus probable reserves ("2P")
- 145.6 million boe (15% increase from 2018)
- NPV10 of
$1.7 billion (no change from 2018) - 2P Future development costs of
$650 million - The Deloitte price forecast was 10-15% lower in the later years for all products for the 2019 report versus 2018
- Finding and development costs of
$6.86 /boe resulting in a recycle ratio of 3.26 times - 2P NAV per FD Share of
$17.05 - RLI of 31.9 years
- 2P additions replaced 522% of 2019 production
Oil and Gas Reserves
The following tables summarize certain information contained in the 2019 Reserve Report. The 2019 Reserve Report encompasses 100% of Yangarra's oil and gas properties and was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") by Deloitte.
Summary of Oil and Gas Reserves (1)(2)
(Company Share Gross volumes based on forecast price and costs)
Reserves Category
| ||||||
Light and Medium Oil (Mbbl) | Natural Gas Liquids (Mbbl) | Natural Gas (MMcf) | Total BOE 2019 (Mboe) | Total BOE 2018 (Mboe) | ||
Proved Developed Producing | 5,344 | 5,477 | 88,183 | 25,518 | 23,412 | |
Proved Developed Non-Producing | 620 | 423 | 6,802 | 2,176 | 1,917 | |
Proved Undeveloped | 13,225 | 12,149 | 195,141 | 57,897 | 50,178 | |
Total Proved | 19,189 | 18,049 | 290,126 | 85,592 | 75,507 | |
Probable | 12,553 | 13,324 | 205,010 | 60,045 | 50,799 | |
Total Proved Plus Probable | 31,741 | 31,373 | 495,136 | 145,637 | 126,305 |
Notes to table: | |
(1) | Total values may not add due to rounding. |
(2) | BOEs are derived by converting gas to oil equivalent in the ratio of six thousand cubic feet of gas to one barrel of oil (6 Mcf:1 bbl). |
Summary of Net Present Values of Future Net Revenue (Before Tax) (1)(4)
(Based on forecast price and costs)
As At | As At | ||||||
Reserves Category | 0.0% | 5.0% | 10.0% | 15.0% | 20.0% | 10.0% | |
Proved Developed Producing | 660,728 | 507,846 | 413,669 | 351,521 | 307,629 | 393,103 | |
Proved Developed Non- | 59,131 | 46,963 | 39,514 | 34,480 | 30,834 | 47,202 | |
Proved Undeveloped | 1,243,947 | 878,215 | 659,274 | 516,407 | 417,228 | 678,893 | |
Total Proved | 1,963,806 | 1,433,024 | 1,112,457 | 902,409 | 755,692 | 1,119,198 | |
Probable | 1,613,536 | 880,489 | 556,057 | 384,367 | 282,467 | 566,699 | |
Total Proved Plus Probable | 3,577,342 | 2,313,513 | 1,668,514 | 1,286,776 | 1,038,159 | 1,685,897 | |
Notes to table: | |
(1) | Total values may not add due to rounding. |
(2) | Forecast pricing used is based on Deloitte published price forecasts effective |
(3) | Forecast pricing used is based on Deloitte published price forecasts effective |
(4) | Cash flows are reduced for future abandonment costs and estimated capital for future development associated with the reserves. |
Reserve Definitions: | |
(a) | "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. |
(b) | "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. |
(c) | "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. |
(d) | "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. |
(e) | "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. |
(f) | "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. |
Reconciliations of Changes in Reserves
The following table sets out a reconciliation of the changes in the Corporation's reserves as at
Light and Medium Oil | Natural Gas Liquids | |||||
Gross | Gross | Gross | Gross | Gross | Gross | |
(Mstb) | (Mstb) | (Mstb) | (Mstb) | (Mstb) | (Mstb) | |
Opening Balance | 19,562.5 | 13,048.1 | 32,610.7 | 15,577.6 | 10,690.6 | 26,268.2 |
Production | -1,448.7 | - | -1,448.7 | -905.5 | - | -905.5 |
Technical Revisions | -1,552.0 | -2,234.4 | -3,786.5 | 1,530.2 | 1,312.5 | 2,842.7 |
Extensions | 2,633.8 | 1,742.3 | 4,376.1 | 1,805.2 | 1,280.6 | 3,085.8 |
Economic Factors | -9.5 | -6.3 | -15.8 | -11.0 | -6.2 | -17.2 |
Closing Balance | 19,186.1 | 12,549.7 | 31,735.8 | 17,996.4 | 13,277.5 | 31,273.9 |
Royalty Interest | 3.0 | 3.0 | 5.0 | 53.0 | 47.0 | 99.0 |
Gas | MBOE | |||||
Gross | Gross | Gross | Gross Proved | Gross Probable | Gross | |
(MMcf) | (MMcf) | (MMcf) | (MBOE) | (MBOE) | (MBOE) | |
Opening Balance | 241,075.3 | 161,356.1 | 402,431.4 | 75,319.3 | 50,631.4 | 125,950.8 |
Production | -14,569.0 | - | -14,569.0 | -4,782.4 | - | -4,782.4 |
Technical Revisions | 33,786.4 | 22,632.0 | 56,418.5 | 5,609.2 | 2,850.1 | 8,459.2 |
Extensions | 29,267.5 | 20,457.2 | 49,724.6 | 9,316.9 | 6,432.5 | 15,749.4 |
Economic Factors | -185.6 | -102.2 | -287.8 | -51.4 | -29.5 | -81.0 |
Closing Balance | 289,374.6 | 204,343.1 | 493,717.7 | 85,411.6 | 59,884.4 | 145,296.0 |
Royalty Interest | 751.0 | 667.0 | 1,419.0 | 180.0 | 161.0 | 341.0 |
Forecast Prices Used in Estimates
The forecast price and market forecasts prepared by Deloitte are based on information available from numerous government agencies, industry publication, oil refineries, natural gas marketers, and industry trends. The prices are Deloitte's best estimate of how the future will look, based on the many uncertainties that exist in both the domestic Canadian and international petroleum industries. Deloitte considers the current monthly trends, the actual and trends for the year to date, and the prior year actual in determining the forecast. The crude oil and natural gas forecasts are based on yearly variable factors weighted to higher percent in current data and reflecting a higher percent to the prior year historical. These forecasts are Deloitte's interpretation of current available information and while they are considered reasonable, changing market conditions or additional information may require alteration from the indicated effective date.
Inflation forecasts and exchange rates, an integral part of the forecast, have also been considered.
Price Inflation Rate | Cost Inflation Rate | Cdn to US Exchange Rate | |
2019 | 1.9% | 1.9% | |
2020 | 0.0% | 0.0% | |
2021 | 2.0% | 2.0% | |
2022 | 2.0% | 2.0% | |
2023 | 2.0% | 2.0% | |
2024 beyond | 2.0% | 2.0% |
Oil, NGL, and natural gas base case prices, utilized by Deloitte in the Deloitte Reserve Report were as follows:
Oil | Natural Gas | Natural Gas Liquids | ||||||
Year | WTI |
|
|
|
| Pentanes + | Butanes | Propane |
($US/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/mcf) | ($Cdn/mcf) | ($Cdn/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | |
Forecast | ||||||||
2020 | ||||||||
2021 | ||||||||
2022 | ||||||||
2023 | ||||||||
2024 | ||||||||
2025 | ||||||||
2026 | ||||||||
2027 | ||||||||
2028 | ||||||||
2029 | ||||||||
Escalation of 2.0% Thereafter | ||||||||
Notes to table: | |
- | All prices are in Canadian dollars except WTI and NYMEX which are in |
- | |
- | Natural Gas Liquid prices are forecasted at |
- | 1 Mcf is equivalent to 1 mmbtu. |
- | |
Finding and Development Costs
Yangarra's F&D costs for 2019, 2018 and the three-year average are presented in the tables below. The costs used in the F&D calculation are the capital costs related to: land acquisition and retention; drilling; completions; tangible well site; tie-ins; and facilities, plus the change in estimated future development costs as per the independent reserve report. Acquisition costs are net of any proceeds from dispositions of properties. Due to the timing of capital costs and the subjectivity in the estimation of future costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. The reserves used in this calculation are Company net reserve additions, including revisions.
Proved Developed Producing Finding & Development Costs ($ millions)
2019 | 2018 | 2017 – 2019 | |
Capital expenditures | 121.0 | 151.0 | 355.0 |
Reserve additions, net production (Mboe) | 6,687 | 14,878 | 27,778 |
Proved Developed Producing F&D costs – including future capital ($/boe) | 18.10 | 10.15 | 12.78 |
Proved Recycle Ratio ( | 1.24 | 2.69 |
Proved Finding & Development Costs ($ millions)
2019 | 2018 | 2017 - 2019 | |
Capital expenditures | 121.0 | 151.0 | 355.0 |
Change in future capital | 36.5 | 1.9 | 179.2 |
Total capital for F&D | 157.5 | 152.9 | 534.2 |
Reserve additions, net production (Mboe) | 14,665 | 23,072 | 59,241 |
Proved F&D costs – including future capital ($/boe) | 10.74 | 6.63 | 9.02 |
Proved F&D costs – excluding future capital ($/boe) | 8.25 | 6.54 | 5.99 |
Proved Recycle Ratio ( | |||
Including future capital | 2.08 | 4.12 | |
Excluding future capital | 2.71 | 4.17 |
Proved plus Probable Finding & Development Costs ($ millions)
2019 | 2018 | 2017 - 2019 | |
Capital expenditures | 121.0 | 151.0 | 355.0 |
Change in future capital | 43.1 | 54.2 | 283.6 |
Total capital for F&D | 164.1 | 205.2 | 638.6 |
Reserve additions, net production (Mboe) | 23,912 | 41,847 | 95,108 |
Proved plus Probable F&D costs – including future capital ($/boe) | 6.86 | 4.90 | 6.71 |
Proved plus Probable F&D costs – excluding future capital ($/boe) | 5.06 | 3.61 | 3.73 |
Proved plus Probable Recycle Ratio ( | |||
Including future capital | 3.26 | 5.57 | |
Excluding future capital | 4.42 | 7.57 |
Net Asset Value ("NAV")
As at | PDP | PDP +PNP | Total Proved | Proved + Probable |
Present Value Reserves, before tax (discounted at 10%) | 413.7 | 453.2 | 1,112.5 | 1,668.5 |
Total Net Debt ($ million) (unaudited) | (187.0) | (187.0) | (187.0) | (187.0) |
Proceeds from the exercise of options (2) | 1.8 | 1.8 | 1.8 | 1.8 |
Net Asset Value | 228.5 | 268.0 | 927.3 | 1,483.3 |
Fully diluted common shares outstanding (million) | 87.0 | 87.0 | 87.0 | 87.0 |
Net asset value per share |
Notes to table: | |
(1) | The preceding table shows what is customarily referred to as a "produce out" net asset value calculation under which the current value of Yangarra's reserves would be produced at the Deloitte forecast future prices and costs. The value is a snapshot in time as at |
(2) | The calculation of proceeds from exercise of stock options and the diluted number of common shares outstanding only include stock options that are "in-the-money" based on the closing price of YGR of |
(3) | Net debt or adjusted working capital (deficit), which represent current assets less current liabilities, excluding current derivative financial instruments, are used to assess efficiency, liquidity and the general financial strength of the Company. There is no IFRS measure that is reasonably comparable to net debt or adjusted working capital (deficit). |
Year End Disclosure
The financial statements for the year-ended
Additional reserve information as required under NI 51-101 will be included in the Company's Annual Information Form which will be filed on SEDAR on or before
Reader Advisories:
Unaudited Financial Information and Non-IFRS Measures
Certain financial and operating information included in this press release for the quarter and year ended
Oil and Gas Advisories. Natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated. The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore Boe's may be misleading if used in isolation. References to natural gas liquids ("NGLs") in this news release include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (Boe). One ("BCF") equals one billion cubic feet of natural gas. One ("Mmcf") equals one million cubic feet of natural gas.
All reserve references in this press release are "Company share gross reserves". Company share gross reserves are the Company's total working interest reserves (operating or non-operating) before the deduction of any royalty obligation s but including royalty interests payable the Company. It should not be assumed that the present worth of estimated future cash flow presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserve estimates of Yangarra's crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
This press release contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as "recycle ratio", "operating netback", "finding and development costs", "reserve life index" and "net asset value". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons.
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Yangarra's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from metrics presented in this press release, should not be relied upon for investment or other purposes.
All amounts in this news release are stated in Canadian dollars unless otherwise specified. Our oil and gas reserves statement for the year ended
Forward Looking Information. This press release contains forward-looking statements and forward-looking information (collectively "forward-looking information") within the meaning of applicable securities laws relating to the Company's plans and other aspects of our anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities. Forward-looking information typically uses words such as "anticipate", "believe", "continue", "sustain", "project", "expect", "forecast", "budget", "goal", "guidance", "plan", "objective", "strategy", "target", "intend" or similar words suggesting future outcomes, statements that actions, events or conditions "may", "would", "could" or "will" be taken or occur in the future, including statements about our strategy, plans, objectives, priorities and focus, growth plans; our estimations on future costs; volatility of commodity prices, and currency fluctuations. Statements relating to "reserves" are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
The forward-looking information is based on certain key expectations and assumptions made by our management, including expectations and assumptions concerning prevailing commodity prices, exchange rates, interest rates, applicable royalty rates and tax laws; future production rates and estimates of operating costs; performance of existing and future wells; reserve volumes; anticipated timing and results of capital expenditures; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; benefits to shareholders of our programs and initiatives, the timing, location and extent of future drilling operations; the expected timing of release of our audited financials and AIF; the state of the economy and the exploration and production business; results of operations; performance; business prospects and opportunities; the availability and cost of financing, labour and services; the impact of increasing competition; ability to efficiently integrate assets and employees acquired through acquisitions, ability to market oil and natural gas successfully and our ability to access capital.
Although we believe that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Yangarra can give no assurance that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature they involve inherent risks and uncertainties. Our actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits that we will derive therefrom. Management has included the above summary of assumptions and risks related to forward-looking information provided in this press release in order to provide security holders with a more complete perspective on our future operations and such information may not be appropriate for other purposes.
Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).
These forward-looking statements are made as of the date of this press release and we disclaim any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.
All reference to $ (funds) are in Canadian dollars unless otherwise stated.
Neither the TSX nor its Regulation Service Provider (as that term is defined in the Policies of the TSX) accepts responsibility for the adequacy and accuracy of this release.
SOURCE
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