CALGARY, AB – Tamarack Valley Energy Ltd. (“Tamarack” or the “Company“) is pleased to announce certain unaudited financial and operating results for the three months and year ended December 31, 2021 and the results of Tamarack’s year end independent oil and gas reserves evaluation as of December 31, 2021 (the “GLJ Report”), prepared by Tamarack’s independent qualified reserves evaluator, GLJ Ltd. (“GLJ”). Selected reserves information is outlined below. The Company anticipates announcing its fourth quarter and audited year end 2021 financial results and filing an annual information form (“AIF”) for the year ended December 31, 2021, on or near March 3, 2022.
Brian Schmidt, President and Chief Executive Officer of Tamarack commented, “2021 was a transformational year for Tamarack as we advanced our strategy of driving long term sustainable free funds flow(1) growth forward with the repositioning and further consolidation of the Company in the Charlie Lake and Clearwater oil plays. These plays complement our highly economic waterflood assets. Operationally, we exceeded our full year guidance and successfully integrated the assets into our portfolio, which is demonstrated in our robust reserves metrics including our low finding and development (“F&D”) costs and strong recycle ratios.”
Strong Fourth Quarter and Full Year 2021 Results
The following are unaudited highlights, and all numbers are approximate. During the quarter and year ended December 31, 2021, Tamarack:
- Achieved fourth quarter average production of 40,384 boe/d(2), driving full year production of approximately 34,562 boe/d(3) which is above our full year guidance range of 34,250 boe/d(4), despite the extreme cold weather impacts that hampered December production across the basin;
- Increased our oil and natural gas liquids (“NGL”) weighting to 69% for both the fourth quarter and full year average 2021;
- Executed a capital program of $41.7 million for the fourth quarter and a total of $191.2 million for 2021, which was higher than our forecast due to the continued consolidation of Clearwater and Charlie Lake land positions through land sales during the quarter as well as the acceleration of approximately $9 million of first quarter 2022 capital into fourth quarter 2021 to ensure access to services in a timely and cost-efficient manner;
- Achieved adjusted funds flow(1) of $124 million for the quarter and $340 million for the year and generated $82 million and $149 million of free funds flow(1), excluding acquisitions, for the fourth quarter and full year 2021, respectively;
- Achieved operating netbacks(1), excluding the impacts of hedging, of $44.87/boe and $36.51/boe for the fourth quarter and full year 2021, respectively;
- Further consolidated our Charlie Lake position through two tuck-in acquisitions during the quarter; and
- Exited the quarter with $463.0 million in net debt(1).
2021 Reserve Highlights
Tamarack is pleased to provide select highlights of the Company’s proved developed producing (“PDP”), total proved (“TP”) and total proved plus probable (“TPP”) reserves from the GLJ Report below. Finding, development and acquisition (“FD&A”) costs and F&D costs contained within this press release include changes in future development capital (“FDC”). In addition to the summary information disclosed in this press release, more detailed information regarding Tamarack oil and gas reserves will be included in the AIF to be filed on SEDAR (www.sedar.com). The Company’s reserves as presented in the GLJ Report do not include reserves associated with the previously announced planned acquisition of Crestwynd Exploration Ltd. (“Crestwynd“) given such acquisition has yet to close. The ongoing positive impact of Tamarack’s drilling program combined with Clearwater and Charlie Lake asset acquisitions contributed significantly to the reserves in 2021, further enhancing the long-term resiliency and sustainability of free funds flow(1) for the Company moving forward.
- Relative to year-end 2020, Tamarack increased PDP reserves 39% to 56.3 MMboe, TP reserves 63% to 104.1 MMboe and TPP reserves 64% to 181.9 MMboe in 2021.
- Replaced 225% of total 2021 production on a PDP basis, 419% on a TP basis and 661% on a TPP basis. PDP reserves represent 54% and 31% of TP and TPP reserves, respectively.
- Achieved 2021 PDP F&D costs of $14.38/boe, including changes in FDC, TP F&D costs of $14.66/boe and TPP F&D costs of $8.74/boe. These F&D metrics yielded reserve recycle ratios of 3.1x, 3.1x and 5.1x, respectively based on a Q4/21 operating netback(1). Based on a full year 2021 operating netback(1) the PDP, TP and TPP recycle ratios were 2.5x, 2.5x and 4.2x respectively.
- Achieved PDP FD&A costs of $32.68/boe including changes in FDC, TP FD&A costs of $22.79/boe and TPP FD&A costs of $15.10/boe. The TPP FD&A recycle ratio was 2.4x based on a full year 2021 corporate operating field netback(1).
- Before-tax net present value (“NPV”) of reserves, discounted at 10% (“NPV10”), was $1.0 billion on a PDP basis, $1.7 billion on a TP basis and $3.0 billion on a TPP basis evaluated using three independent reserve evaluators average forecast pricing and foreign exchange rates as at January 2022.
2021 Independent Qualified Reserve Evaluation
The following tables highlight the findings of the GLJ Report, which has been prepared in accordance with definitions, standards and procedures contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the most recent publication of the Canadian Oil and Gas Evaluation Handbook (“COGEH”). All evaluations and summaries of future net revenue are stated prior to the provision for interest, debt service charges or general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. The information included in the “Net Present Values of Future Net Revenue Before Income Taxes Discounted” table below is based on an average of pricing assumptions prepared by the following three independent external reserves evaluators: GLJ, Sproule Associates Limited and McDaniel & Associates Consultants Ltd (the “3-Consultant Average Forecast Pricing”). It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. All per share reserves metrics below are based on basic shares outstanding as of December 31, 2021.
Reserves Snapshot by Category:
PDP |
TP |
TPP |
|
Total Reserves (mboe)(1) |
56,290 |
104,133 |
181,932 |
Reserves Added(2) (mboe) |
28,398 |
52,908 |
83,375 |
Reserves Replacement |
225% |
419% |
661% |
NPV10 Before Tax ($mm) |
$1,009 |
$1,675 |
$2,953 |
Notes: |
|
(1) |
Total reserves are Company Gross Reserves which exclude royalty volumes |
(2) |
Reserves Added takes the difference in reserves year-over-year plus the production for the year |
Year-Over-Year Reserves Data (Forecast Prices and Costs)
(mboe) |
December 31, 2021 (1) |
December 31, 2020 (1) |
% Change |
PDP |
56,290 |
40,507 |
39% |
TP |
104,133 |
63,840 |
63% |
TPP |
181,932 |
111,172 |
64% |
Note: |
|
(1) |
Total reserves are Company Gross Reserves which exclude royalty volumes |
FD&A Costs
PDP |
TP |
TPP |
|
FD&A Cost per boe(1) |
32.68 |
22.79 |
15.10 |
F&D Cost per boe(1) |
14.38 |
14.66 |
8.74 |
Notes: |
|
(1) |
2021; including changes in FDC |
Company Reserves Data (Forecast Prices and Costs)
RESERVES CATEGORY |
LIGHT & MEDIUM |
HEAVY CRUDE OIL |
CONVENTIONAL NATURAL GAS(2) |
NATURAL GAS LIQUIDS |
TOTAL OIL EQUIVALENT |
|||||||||||||
Gross (Mbbls) |
Net (Mbbls) |
Gross (Mbbls) |
Net (Mbbls) |
Gross (Mmcf) |
Net (Mmcf) |
Gross (Mbbls) |
Net (Mbbls) |
Gross (Mboe) |
Net (Mboe) |
|||||||||
PROVED: |
||||||||||||||||||
Developed Producing |
26,322 |
21,496 |
4,093 |
3,487 |
114,981 |
104,619 |
6,712 |
5,551 |
56,290 |
47,971 |
||||||||
Developed Non-Producing |
1,242 |
1,089 |
0 |
0 |
5,053 |
4,567 |
255 |
200 |
2,339 |
2,051 |
||||||||
Undeveloped |
25,690 |
21,568 |
4,188 |
3,765 |
69,461 |
63,461 |
4,049 |
3,385 |
45,504 |
39,295 |
||||||||
TOTAL PROVED |
53,253 |
44,153 |
8,281 |
7,252 |
189,495 |
172,647 |
11,016 |
9,136 |
104,133 |
89,316 |
||||||||
PROBABLE |
40,856 |
32,806 |
7,819 |
6,644 |
128,681 |
117,187 |
7,677 |
6,232 |
77,799 |
65,214 |
||||||||
TOTAL PROVED PLUS PROBABLE |
94,110 |
76,960 |
16,100 |
13,896 |
318,177 |
289,833 |
18,692 |
15,369 |
181,932 |
154,531 |
||||||||
Notes: |
|
(1) |
Tight oil included in the light & medium crude oil product type represents less than 5.0% of any reserves category |
(2) |
Conventional natural gas amounts include coal bed methane, in amounts less than 0.3% of any reserves category |
(3) |
Columns may not add due to rounding |
Net Present Values of Future Net Revenue before Income Taxes Discounted at (% per year)
RESERVES CATEGORY |
0% ($000s) |
5% ($000s) |
10% ($000s) |
15% ($000s) |
20% ($000s) |
Unit Value |
PROVED: |
||||||
Developed Producing |
1,261,988 |
1,121,358 |
1,008,539 |
919,330 |
847,794 |
21.02 |
Developed Non-Producing |
58,418 |
48,404 |
40,960 |
35,369 |
31,072 |
19.97 |
Undeveloped |
1,045,941 |
799,826 |
625,970 |
500,594 |
407,702 |
15.93 |
TOTAL PROVED |
2,366,347 |
1,969,587 |
1,675,469 |
1,455,293 |
1,286,568 |
18.76 |
PROBABLE |
2,344,259 |
1,677,816 |
1,278,008 |
1,019,532 |
841,347 |
19.60 |
TOTAL PROVED PLUS PROBABLE |
4,710,606 |
3,647,403 |
2,953,476 |
2,474,825 |
2,127,915 |
19.11 |
Notes: |
|
(1) |
Unit values based on Company net interest reserves |
(2) |
The prices used to estimate net present values are based on the 3-Consultant Average Forecast Pricing |
(3) |
Columns may not add due to rounding |
Reconciliation of Company Gross Reserves Based on Forecast Prices and Costs
MBOE |
|||
FACTORS |
TP |
Probable |
TPP |
December 31, 2020 |
63,840 |
47,332 |
111,172 |
Extensions and Improved Recovery(1) |
13,969 |
11,440 |
25,409 |
Technical Revisions |
(3,638) |
(11,467) |
(15,105) |
Acquisitions |
40,747 |
30,323 |
71,070 |
Dispositions |
(550) |
(217) |
(767) |
Economic Factors |
2,380 |
389 |
2,768 |
Production |
(12,615) |
0 |
(12,615) |
December 31, 2021 |
104,133 |
77,799 |
181,932 |
Notes: |
|
(1) |
Reserves additions under Infill Drilling, Improved Recovery and Extensions are combined and reported as “Extensions and Improved Recovery” |
(2) |
Columns may not add due to rounding |
(3) |
Company Gross Reserves exclude royalty volumes |
Future Development Capital Costs
The following is a summary of GLJ’s estimated FDC required to bring TP and TPP undeveloped reserves on production.
FDC(1) |
||
(amounts in $000s) |
TP |
TPP |
2022 |
161,379 |
190,710 |
2023 |
169,751 |
219,325 |
2024 |
178,018 |
241,292 |
2025 and Subsequent |
114,366 |
314,299 |
Total Undiscounted FDC |
623,515 |
965,626 |
Total Discounted FDC at 10% per year |
518,215 |
773,442 |
Note: |
|
(1) |
FDC as per GLJ Report based on the 3-Consultant Average Forecast Pricing |
FD&A Costs |
2021 |
Three-Year Average |
||
(amounts in $000s except as noted) |
TP |
TPP |
TP |
TPP |
FD&A costs, including FDC(1)(2) |
||||
Exploration and development capital expenditures (3)(4) |
191,159 |
191,519 |
157,889 |
157,889 |
Acquisitions, net of dispositions(5) |
739,205 |
739,205 |
277,478 |
277,478 |
Total change in FDC |
275,464 |
328,268 |
80,643 |
88,475 |
Total FD&A capital, including change in FDC |
1,205,828 |
1,258,632 |
516,010 |
523,842 |
Reserve additions, including revisions – Mboe |
12,711 |
13,074 |
8,128 |
5,999 |
Acquisitions, net of dispositions(5) – Mboe |
40,197 |
70,302 |
17,854 |
30,609 |
Total FD&A Reserves |
52,908 |
83,376 |
25,982 |
36,608 |
F&D costs, including FDC – $/boe |
14.66 |
8.74 |
16.33 |
14.71 |
Acquisition costs, net of dispositions – $/boe |
25.36 |
16.28 |
21.47 |
14.23 |
FD&A costs, including FDC – $/boe |
22.79 |
15.10 |
19.86 |
14.31 |
Notes: |
|
(1) |
While Nl 51-101 requires that the effects of acquisitions and dispositions be excluded from the calculation of finding and development costs, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Company’s ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company’s cost structure. Finding and development costs both including and excluding acquisitions and dispositions have been presented above. |
(2) |
The calculation of FD&A costs incorporates the change in FDC required to bring proved undeveloped and developed reserves into production. In all cases, the FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions after changes in FDC costs. |
(3) |
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 reserves additions for that year. |
(4) |
The capital expenditures also exclude capitalized administration costs. |
(5) |
Includes capital spent in 2021 to develop the assets acquired during 2021. |
(6) |
Columns may not add due to rounding |
(7) |
Calculations use Company Gross Reserves which exclude royalty volumes. |
Crestwynd Acquisition Update
Further to the Company’s previous announcement, Tamarack expects the previously announced acquisition of Crestwynd to close on or around February 15, 2022, subject to certain customary conditions. Tamarack has internally estimated the effect of the Crestwynd reserves, and has highlighted the following pro forma reserves and future values for the combined entities as at December 31, 2021.
Reserves Snapshot Pro Forma the Crestwynd Acquisition:
PDP |
TP |
TPP |
|
Total Tamarack Reserves (mboe)(1) |
56,290 |
104,133 |
181,932 |
Total Crestwynd Reserves (mboe)(1)(2) |
1,902 |
6,320 |
9,650 |
Total Pro Forma Reserves (mboe)(1)(2) |
58,192 |
110,453 |
191,582 |
Tamarack NPV10 Before Tax ($mm) |
$1,009 |
$1,675 |
$2,953 |
Crestwynd NPV10 Before Tax ($mm)(2) |
$67 |
$149 |
$218 |
Proforma NPV10 Before Tax ($mm)(2) |
$1,076 |
$1,824 |
$3,171 |
Notes: |
|
(1) |
Total reserves are Company Gross Reserves which exclude royalty volumes. |
(2) |
PDP reserves, TP reserves, TPP reserves and NPV10 Before Tax in respect of the Crestwynd assets have been internally estimated by the Company’s internal Qualified Reserve Evaluators (“QRE”) and prepared in accordance with NI 51-101 and COGEH effective as of December 31, 2021, using the 3-Consultant Average Pricing to estimate net present values. “Internally estimated” means an estimate that is derived by the Company’s internal QRE and prepared in accordance with NI 51-101 and COGEH. |
About Tamarack Valley Energy Ltd.
Tamarack is an oil and gas exploration and production company committed to creating long-term value for its shareholders through sustainable free funds flow generation, financial stability and the return of capital. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily on Charlie Lake, Clearwater and EOR plays in Alberta. Operating as a responsible corporate citizen is a key focus to ensure we deliver on our environmental, social and governance (ESG) commitments and goals. For more information, please visit the Company’s website at www.tamarackvalley.ca.
Abbreviations
AECO |
the natural gas storage facility located at Suffield, Alberta connected to TC Energy’s Alberta System |
ARO |
asset retirement obligation |
bbls |
barrels |
bbls/d |
barrels per day |
boe |
barrels of oil equivalent |
boe/d |
barrels of oil equivalent per day |
GJ |
gigajoule |
IFRS |
International Financial Reporting Standards as issued by the International Accounting Standards Board |
mcf |
thousand cubic feet |
mcf/d |
thousand cubic feet per day |
mmcf/d |
million cubic feet per day |
MSW |
Mixed sweet blend, the benchmark for conventionally produced light sweet crude oil in Western Canada |
WTI |
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade |
Reader Advisories
Notes to Press Release |
|
(1) |
See “Non-IFRS Measures”; free funds flow was previously referred to as free adjusted funds flow |
(2) |
Comprised of 18,487 bbl/d light and medium crude oil, 5,616 bbl/d heavy crude oil, 3,899 bbl/d NGL and 74,297 mcf/d conventional natural gas. |
(3) |
Comprised of 15,670 bbl/d light and medium crude oil, 4,613 bbl/d heavy crude oil, 3,408 bbl/d NGL and 65,226 mcf/d conventional natural gas. |
(4) |
Comprised of 15,250-15,750 bbl/d light and medium crude oil, 4,800-5,000 bbl/d heavy crude oil, 3,300-3,500 bbl/d NGL and 64,000-65,000 mcf/d conventional natural gas. |
Unaudited Financial Information
Certain financial and operating results included in this press release, including adjusted funds flow, free funds flow, operating netbacks, capital expenditures and production information, are based on unaudited estimated results. These estimated results are subject to change upon completion of the Company’s audited financial statements for the year ended December 31, 2021, and changes could be material. Tamarack anticipates filing its audited financial statements and related management’s discussion and analysis for the year ended December 31, 2021 on or near March 3, 2022.
Disclosure of Oil and Gas Information
AIF. Tamarack’s Statement of Reserves Data and Other Oil and Gas Information on Form 51-101F1 dated effective as at December 31, 2021, which will include further disclosure of Tamarack’s oil and gas reserves and other oil and gas information (excluding in respect of the assets to be acquired pursuant to Tamarack’s previously announced acquisition of Crestwynd) in accordance with NI 51-101 and COGEH forming the basis of this press release, will be included in the AIF which will be available on SEDAR at www.sedar.com on or near March 3, 2022.
Unit Cost Calculation. For the purpose of calculating unit costs, natural gas volumes have been converted to a boe using six thousand cubic feet equal to one barrel unless otherwise stated. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with NI 51-101. Boe may be misleading, particularly if used in isolation.
Reserves and Future Net Revenue Disclosure. All reserves values, future net revenue and ancillary information contained in this press release are derived from the GLJ Report unless otherwise noted. All reserve references in this press release are “Company gross reserves”. Company gross reserves are the Company’s total working interest reserves before the deduction of any royalties payable by the Company. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions applied by GLJ in evaluating Tamarack’s reserves or by the QRE in evaluating Crestwynd’s reserves will be attained and variances could be material. All reserves assigned in the GLJ Report are located in the Provinces of Alberta and Saskatchewan and presented on a consolidated basis.
All evaluations and summaries of future net revenue are stated prior to the provision for interest, debt service charges or general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. The recovery and reserve estimates of Tamarack’s and Crestwynd’s, as applicable, 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. There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only.
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. Proved 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. Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., 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 category (proved, probable, possible) to which they are assigned. Certain terms used in this press release but not defined are defined in NI 51-101, CSA Staff Notice 51-324 – Revised Glossary to NI 51-101, Revised Glossary to NI 51-101, Standards of Disclosure for Oil and Gas Activities (“CSA Staff Notice 51-324“) and/or the COGEH and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA Staff Notice 51-324 and the COGEH, as the case may be.
Oil and Gas Metrics. This press release contains metrics commonly used in the oil and natural gas industry, such as development capital, F&D costs, FD&A costs, recycle ratio, operating netback and reserves replacement.
“Development capital” means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Development capital presented herein excludes land and capitalized administration costs but includes the cost of acquisitions and capital associated with acquisitions where reserve additions are attributed to the acquisitions.
“Finding and development costs” or “F&D costs” are calculated as the sum of field capital plus the change in FDC for the period divided by the change in reserves that are characterized as development for the period and “finding, development and acquisition costs” are calculated as the sum of field capital plus acquisition capital plus the change in FDC for the period divided by the change in total reserves, other than from production, for the period. Both finding and development costs and finding development and acquisition costs take into account reserves revisions during the year on a per boe basis. The aggregate of the exploration and development costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. Finding and development costs both including and excluding acquisitions and dispositions have been presented in this press release because acquisitions and dispositions can have a significant impact on Tamarack’s ongoing reserves replacements costs and excluding these amounts could result in an inaccurate portrayal of the Company’s cost structure.
“Finding, development and acquisition costs” or “FD&A costs” incorporate the change in FDC required to bring proved undeveloped and developed reserves into production. In all cases, the FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions after changes in FDC costs.
“Recycle ratio” is measured by dividing the operating netback for the applicable period by F&D cost per boe for the year. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves.
“Operating Netback” is calculated as total petroleum and natural gas sales, including realized gains and losses on commodity, interest rate and foreign exchange derivative contracts, less royalties and net production and transportation costs.
“Reserves replacement” is calculated as reserves in the referenced category divided by estimated referenced production.
These terms have been calculated by management and 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 Tamarack’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.