Financial Update (all numbers are unaudited and approximate)
Fourth quarter production averaged 10,060 boe/d (44% liquids) generating funds flow from operations of $32 million ($0.38 per share). Capital spending for the fourth quarter of $27 million was higher than previously forecast primarily due to drilling through the Christmas break and additional reclamation and abandonment activities. The fourth quarter operating netback was $39.62/boe and net debt at December 31, 2021 was $197 million, resulting in an annualized debt to funds flow ratio of 1.5:1 vs 2.1:1 for the quarter ended September 31, 2021.
Operations Update
The Company brought on four wells in late December 2021 and has drilled an additional eight wells (completed six) on the fourteen-well pad in West Ferrier in late January.
Since pioneering the economic development of bioturbated Cardium wells five years ago, the strategic progression of the Company has been as follows:
- 2016 & 2017 were used to determine where drilling bioturbated wells was economic and to accumulate potential acreage.
- 2018 & 2019 was spent building out the gathering and compression infrastructure as well as expanding the fluid hauling group to handle planned production growth.
- During 2020 & 2021 work commenced on ESG initiatives including; identifying baseline carbon intensity, implementing numerous methane and CO2 reduction initiatives, reducing the non producing well ARO to less than $2 million and diversifying the Board of Directors and staff. Also, during this period, the internal Oilfield Servicing Group (“OFS”) (working exclusively for Yangarra) was expanded with the addition of earth moving, road maintenance and rig hauling equipment.
- With these important building blocks in place, the Company will focus on debt reduction for 2022, while maintaining a 30-well capital program. 2022 production guidance remains at 12,000 boe/d with funds flow from operations estimated at $130 million assuming CDN$78.00/bbl for Edmonton par and CDN$3.50/GJ for AECO natural gas.
ESG Report
The Company is pleased to announce the publication of its inaugural ESG report. ESG standards have been a core principle of Yangarra’s operations for years as evidenced by the Company’s low ARO & recent work on reducing emissions. The ESG report will allow stakeholders to benchmark Yangarra’s metrics with a peer group and highlights Yangarra’s stellar track record. The report can be found on our website at www.yangarra.ca.
Reserve Report Highlights
Summary
Yangarra has been drilling its bioturbated Cardium formation for over five years. Initial decline profiles were determined without the benefit of production history, as none existed, and were therefore based entirely on initial production rates. As significant production history is now available, the reserve report and in particular the Company’s proved developed non-producing reserves is being revised appropriately with the updated production history. To better reflect the accumulated progression of drilling and production in the bioturbated Cardium, the Company is presenting a 5-year average for F&D costs.
The reserve report uses an Edmonton Par price of $81.25/bbl for 2022 vs current pricing for Edmonton par at over $95.00/bbl.
All reserves information contained in this press release are based on the Company’s 2021 NI 51-101 oil and gas reserve report dated February 1, 2022, as prepared by Deloitte LLP (The “2021 Reserve Report“).
Proved Developed Producing (“PDP”) Reserves
- 19.6 million boe (14% decrease from 2020)
- Net present value before tax discounted at 10% (“NPV10”) of $345 million (9% increase from 2020)
- Yangarra’s trailing 5-year PDP F&D is $17.25/boe
- PDP net asset value per fully diluted common share (“NAV per FD Share”) of $1.63
- PDP Reserve Life Index (“RLI”) based on fourth quarter 2021 production of 5.3 years
Total Proved reserves (“1P”)
- 82.8 million boe (14% decrease from 2020)
- NPV10 of $1.0 billion (1% decrease from 2020)
- 1P future development costs of $443 million
- Yangarra’s trailing 5-year 1P F&D is $10.87/boe
- 1P NAV per FD Share of $8.92
- RLI based on fourth quarter 2021 production of 22.7 years
Proved plus probable reserves (“2P”)
- 141.2 million boe (10% decrease from 2020)
- NPV10 of $1.5 billion (1% increase from 2020)
- 2P Future development costs of $658 million
- Yangarra’s trailing 5-year 2P F&D is $8.06/boe
- 2P NAV per FD Share of $13.86
- RLI of 38.7 years
Oil and Gas Reserves
The following tables summarize certain information contained in the 2021 Reserve Report. The 2021 Reserve Report encompasses 100% of Yangarra’s oil and gas properties and was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101“) by Deloitte.
Summary of Oil and Gas Reserves (1)(2)
(Company Share Gross volumes based on forecast price and costs)
Reserves Category |
||||||||||||
Light and Medium Oil (Mbbl) |
Natural Gas Liquids (Mbbl) |
Conventional Gas (MMcf) |
Shale Gas (MMcf) |
Total BOE 2021 (Mboe) |
Total BOE 2020 (Mboe) |
|||||||
Proved Developed Producing |
3,972 |
4,029 |
68,792 |
521 |
19,553 |
22,754 |
||||||
Proved Developed Non-Producing |
143 |
296 |
5,092 |
0 |
1,288 |
12,595 |
||||||
Proved Undeveloped |
13,768 |
12,492 |
208,703 |
5,315 |
61,929 |
61,084 |
||||||
Total Proved |
17,883 |
16,817 |
282,587 |
5,835 |
82,770 |
96,434 |
||||||
Probable |
12,109 |
12,350 |
196,865 |
7,692 |
58,461 |
61,127 |
||||||
Total Proved Plus Probable |
29,902 |
29,166 |
479,453 |
13,527 |
141,232 |
157,561 |
Notes: |
(1) Total values may not add due to rounding. |
(2) BOEs are derived by converting gas to oil equivalent in the ratio of six thousand cubic feet of gas to one barrel of oil (6 Mcf:1 bbl). |
Summary of Net Present Values of Future Net Revenue (Before Tax) (1)(4)
(Based on forecast price and costs)
As At December 31, 2021(2) |
As At December 31, 2020 (3) |
|||||||||
Reserves Category |
0.0% (M$) |
5.0% (M$) |
10.0% (M$) |
15.0% (M$) |
20.0% (M$) |
10.0% (M$) |
||||
Proved Developed Producing |
493,715 |
404,060 |
345,074 |
303,694 |
273,146 |
316,329 |
||||
Proved Developed Non-Producing |
26,153 |
19,487 |
15,348 |
12,613 |
10,705 |
160,446 |
||||
Proved Undeveloped |
1,242,479 |
890,609 |
676,652 |
536,017 |
438,033 |
573,429 |
||||
Total Proved |
1,762,346 |
1,314,155 |
1,037,073 |
852,323 |
721,883 |
1,050,203 |
||||
Probable |
1,417,042 |
762,882 |
469,039 |
313,911 |
222,951 |
439,246 |
||||
Total Proved Plus Probable |
3,179,388 |
2,077,037 |
1,506,113 |
1,166,235 |
944,834 |
1,489,449 |
Notes: |
|
(1) |
Total values may not add due to rounding. |
(2) |
Forecast pricing used is based on Deloitte published price forecasts effective December 31, 2021. |
(3) |
Forecast pricing used is based on Deloitte published price forecasts effective December 31, 2020. |
(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 December 31, 2021 against such reserves at December 31, 2020 based on forecast prices and cost assumptions:
Light and Medium Oil |
Natural Gas Liquids |
|||||||
Gross Proved |
Gross Probable |
Gross Proved Plus Probable |
Gross Proved |
Gross Probable |
Gross Proved Plus Probable |
|||
(Mstb) |
(Mstb) |
(Mstb) |
(Mstb) |
(Mstb) |
(Mstb) |
|||
Opening Balance |
19,972.4 |
12,153.9 |
32,126.4 |
19,709.0 |
12,959.3 |
32,668.2 |
||
Production |
-882.8 |
0.0 |
-882.8 |
-691.7 |
0.0 |
-691.7 |
||
Technical Revisions |
-3,006.8 |
-981.6 |
-3,988.5 |
-4,233.1 |
-1,678.0 |
-5,911.0 |
||
Extensions |
1,785.5 |
818.5 |
2,604.0 |
2,020.7 |
1,045.0 |
3,065.7 |
||
Economic Factors |
15.0 |
28.2 |
43.2 |
11.7 |
23.1 |
34.8 |
||
Closing Balance |
17,883.4 |
12,018.9 |
29,902.3 |
16,816.5 |
12,349.5 |
29,166 |
||
Conventional Gas |
Shale Gas |
|||||||
Gross Proved |
Gross Probable |
Gross Proved Plus Probable |
Gross Proved |
Gross Probable |
Gross Proved Plus Probable |
|||
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
|||
Opening Balance |
333,869.6 |
207,953.4 |
541,823.0 |
6,643.0 |
8,131.8 |
14,774.8 |
||
Production |
-11,728.6 |
0.0 |
-11,728.6 |
-65.1 |
0.0 |
-65.1 |
||
Technical Revisions |
-74,175.3 |
-29,187.3 |
-103,362.6 |
-742.7 |
-439.6 |
-1,182.2 |
||
Extensions |
34,417.6 |
17,697.1 |
52,114.8 |
0.0 |
0.0 |
0.0 |
||
Economic Factors |
204.1 |
401.9 |
606.0 |
0.0 |
0.0 |
0.0 |
||
Closing Balance |
282,587.4 |
196,865.2 |
479,452.6 |
5,835.2 |
7,692.2 |
13,527.4 |
||
MBOE |
||||||||
Gross Proved |
Gross Probable |
Gross Proved Plus Probable |
||||||
(Mboe) |
(Mboe) |
(Mboe) |
||||||
Opening Balance |
96,433.5 |
61,127.4 |
157,560.9 |
|||||
Production |
-3,540.1 |
0.0 |
-3,540.1 |
|||||
Technical Revisions |
-19,726.2 |
-7,597.4 |
-27,323.6 |
|||||
Extensions |
9,542.5 |
4,813.0 |
14,355.5 |
|||||
Economic Factors |
60.7 |
118.3 |
179.0 |
|||||
Closing Balance |
82,770.3 |
58,461.4 |
141,231.6 |
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 |
|
2022 |
0.0% |
0.0% |
0.800 |
2023 |
2.0% |
2.0% |
0.800 |
2024 |
2.0% |
2.0% |
0.800 |
2025 |
2.0% |
2.0% |
0.800 |
2026 beyond |
2.0% |
2.0% |
0.800 |
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 Cushing (Oklahoma) |
Edmonton City Gate 40° API |
Alberta Reference – Gas Prices |
Alberta AECO – Gas Prices |
Pentanes + Condensate Edmonton |
Butanes Edmonton |
Propane Edmonton |
||
($US/bbl) |
($Cdn/bbl) |
($Cdn/mcf) |
($Cdn/mcf) |
($Cdn/bbl) |
($Cdn/bbl) |
($Cdn/bbl) |
|||
Forecast |
|||||||||
2022 |
$69.00 |
$81.25 |
$3.25 |
$3.65 |
$85.30 |
$56.90 |
$44.70 |
||
2023 |
$65.30 |
$75.25 |
$2.85 |
$3.25 |
$79.00 |
$45.15 |
$33.85 |
||
2024 |
$61.40 |
$70.25 |
$2.75 |
$3.15 |
$73.75 |
$42.15 |
$31.65 |
||
2025 |
$62.60 |
$71.65 |
$2.80 |
$3.25 |
$75.25 |
$43.00 |
$32.25 |
||
2026 |
$63.85 |
$73.05 |
$2.85 |
$3.30 |
$76.75 |
$43.85 |
$32.90 |
||
Escalation of 2.0% Thereafter |
Notes:
- All prices are in Canadian dollars except WTI which are in U.S. dollars.
- Edmonton City Gate prices based on light sweet crude posted at major Canadian refineries (40 Deg. API <0.5% Sulphur).
- Natural Gas Liquid prices are forecasted at Edmonton therefore an additional transportation cost must be included to plant gate sales point.
- 1 Mcf is equivalent to 1 mmbtu.
- Alberta gas prices, except AECO, include an average cost of service to the plant gate.
Finding and Development Costs
Yangarra’s F&D costs for 2021, 2020 and the five-year average are presented in the tables below. The costs used in the F&D calculation are the capital costs related to: land acquisition and retention; drilling; completions; tangible well site; tie-ins; and facilities, plus the change in estimated future development costs as per the independent reserve report. Acquisition costs are net of any proceeds from dispositions of properties. Due to the timing of capital costs and the subjectivity in the estimation of future costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. The reserves used in this calculation are Company net reserve additions, including revisions.
Proved Developed Producing Finding & Development Costs ($ millions)
2021 |
2020 |
2017 – 2021 |
|
Capital expenditures |
88.5 |
51.5 |
494.8 |
Reserve additions, net production (Mboe) |
58.9 |
845 |
28,686 |
Proved Developed Producing F&D costs – including future capital ($/boe) |
1,502.2 |
60.76 |
17.25 |
Proved Recycle Ratio ($32.25/boe annual operating netback) |
0.02 |
0.26 |
Proved Finding & Development Costs ($ millions)
2021 |
2020 |
2017 – 2021 |
|
Capital expenditures |
88.5 |
51.5 |
494.8 |
Change in future capital |
23.5 |
(9.7) |
193.0 |
Total capital for F&D |
108.5 |
41.8 |
684.3 |
Reserve additions, net production (Mboe) |
(10,404) |
14,452 |
63,289 |
Proved F&D costs – including future capital ($/boe) |
N/A |
2.88 |
10.87 |
Proved F&D costs – excluding future capital ($/boe) |
N/A |
3.55 |
7.82 |
Proved Recycle Ratio |
|||
Including future capital |
N/A |
5.56 |
|
Excluding future capital |
N/A |
4.51 |
Proved plus Probable Finding & Development Costs ($ millions)
2021 |
2020 |
2017 – 2021 |
|
Capital expenditures |
88.5 |
51.5 |
494.8 |
Change in future capital |
36.4 |
(28.2) |
291.8 |
Total capital for F&D |
121.4 |
23.3 |
783.1 |
Reserve additions, net production (Mboe) |
(13,070) |
15,534 |
97,572 |
Proved plus Probable F&D costs – including future capital ($/boe) |
N/A |
1.49 |
8.06 |
Proved plus Probable F&D costs – excluding future capital ($/boe) |
N/A |
3.31 |
5.07 |
Proved plus Probable Recycle Ratio |
|||
Including future capital |
N/A |
10.74 |
|
Excluding future capital |
N/A |
4.85 |
Net Asset Value (“NAV”)
As at December 31, 2021 |
PDP |
Total Proved |
Proved + |
Present Value Reserves, before tax (discounted at 10%) |
345.1 |
1037.1 |
1,506.1 |
Total Net Debt ($ million) (unaudited) |
(197.0) |
(197.0) |
(197.0) |
Proceeds from the exercise of options (2) |
7.1 |
7.1 |
7.1 |
Net Asset Value |
155.2 |
847.2 |
1,316.2 |
Fully diluted common shares outstanding (million)
|
94.9 |
94.9 |
94.9 |
Net asset value per share |
$1.63 |
$8.92 |
$13.86 |
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 December 31, 2021 and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. In this analysis, the present value of the proved and probable reserves is calculated at a before tax 10 percent discount rate. |
(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 $1.57 as at December 31, 2021. |
(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 audited financial statements for the year-ended December 31, 2021 are scheduled to be released on March 3, 2022.
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 March 31, 2022.
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 December 31, 2021, including F&D costs and netbacks are based on estimated unaudited financial results for the quarter and year then ended, and are subject to the same limitations as discussed under Forward Looking Information set out below. These estimated amounts may change upon the completion of audited financial statements for the year ended December 31, 2021 and changes could be material.