CALGARY, Alberta – Crew Energy Inc. (TSX: CR, OTCQB: CWEGF) (“Crew” or the “Company”), a growth-oriented natural gas weighted producer operating exclusively in the world-class Montney play in northeast British Columbia, is pleased to provide highlights from our year-end independent corporate reserves evaluation prepared by Sproule Associates Ltd. (“Sproule”) with an effective date of December 31, 2021 (the “Sproule Report”).
Crew’s 2021 year-end reserves reflect the successful first half execution of our previously announced two-year plan, designed to increase production and adjusted funds flow1 (“AFF”), generating free AFF1 which may be used for debt repayment, significantly improving leverage metrics. Record reserves additions, a successful capital program and a meaningfully improved commodity price environment have strategically positioned the Company to achieve the goals set out in our two-year plan.
Crew’s 2021 reserves evaluation was highlighted by a record addition of 24.6 million boe of Proved Developed Producing (“PDP”) reserves to total 82.0 million boe, representing a 22% increase year-over-year and a 43% increase when including replacing 2021 production of 9.7 million boe. Crew also materially increased the before tax net present value discounted at 10% (“NPV10”) of year-end 2021 PDP reserves by 70% to $674 million, and our Total Proved (“1P”) reserves by 51% to $1.3 billion. Supportive of the year-over-year growth is an estimated 34% increase in the Company’s Q4/21 average production to 29,100 boe per day2 from 21,666 boe per day2 in Q4/20.
2021 RESERVES HIGHLIGHTS
Highlights of our PDP, 1P and total proved plus probable (“2P”) reserves from the Sproule Report are provided below. All finding, development and acquisition (“FD&A”)3,4 costs and finding and development (“F&D”)3,4 costs below include changes in future development capital4 (“FDC”) unless otherwise noted.
- Record PDP Additions: Crew added 24.6 million boe of PDP reserves in 2021 to total 82.0 million boe, representing the highest year-over-year increase in the Company’s history. The additions were achieved with PDP F&D costs3,4 of $7.27 per boe and PDP FD&A costs3,4 of $7.10 per boe in 2021, resulting in recycle ratios3,4 of 4.0 and 4.1 times, respectively.
- Before Tax NPV Materially Higher: Crew’s before tax NPV10 for year-end 2021 PDP reserves increased 70% to $674 million compared to 2020 due to improved pricing and higher production. 1P and 2P before tax NPV10 increased 51% and 36% to $1.3 billion and $2.2 billion compared to year-end 2020, respectively, largely due to improved pricing and enhanced capital efficiencies in the undeveloped reserve categories.
|2021 F&D and FD&A Costs3,4|
- Strong 1P and 2P F&D Costs Provide Excellent Recycle Ratios3,4,5: 1P and 2P F&D3,4 costs in 2021 were $7.30 per boe and $3.33 per boe, respectively, despite reserve totals in both categories remaining stable year-over-year. This generated recycle ratios of 3.9 times for 1P F&D3,4 and 8.6 times for 2P F&D3,4. These results are largely attributable to continued operational improvements and successful capital program execution.
- 1P and 2P FD&A3,4Costs Supported by 2021 Lloydminster Disposition Metrics: Crew’s 2021 1P and 2P FD&A costs3,4 were $6.17 per boe and negative $4.22 per boe, respectively, which were lower than the Lloydminster disposition related metrics of $12.67 and $8.78 per boe for 1P and 2P reserves, respectively.
1 Non-IFRS Measure. See “Advisories – Non-IFRS Measures”.
2 See table in the Advisories for production breakdown by product type as defined in NI 51-101.
3 “Finding, Development and Acquisitions costs” or “FD&A costs”, “Finding and Development costs” or “F&D costs” and “recycle ratio” do not have standardized meanings. See “Capital Program Efficiency” and “Advisories – Information Regarding Disclosure on Oil and Gas Reserves, and Operational Information”.
4 The 2021 change in Future Development Capital (FDC) used in the calculation of Crew’s 1P and 2P F&D and FD&A costs does not include approximately $162 million (undiscounted) in the 1P case and $180 million (undiscounted) in the 2P case of maintenance capital that was reclassified to FDC in the December 31, 2021, Sproule Report which was booked as operating costs in prior years.
5 Estimated operating netback in Q4 and full year 2021, used in the above calculations, averaged $28.76 per boe and $23.56 per boe (unaudited), respectively. See ‘Advisories – Unaudited Financial Information’ and ‘Advisories – Information Regarding Disclosure on Oil and Gas Reserves and Operational Information’.
1 “Finding, Development and Acquisitions costs” or “FD&A costs”, “Finding and Development costs” or “F&D costs” and “recycle ratio” do not have standardized meanings. See “Advisories – Capital Program Efficiency” and “Advisories – Information Regarding Disclosure on Oil and Gas Reserves and Operational Information”.
2 All 2021 financial amounts are unaudited. See advisories.
2021 RESERVES DETAIL
The detailed reserves data set forth below is based upon the Sproule Report with an effective date of December 31, 2021. The following presentation summarizes the Company’s crude oil, natural gas liquids and conventional natural gas reserves and the net present values before income tax of future net revenue for the Company’s reserves using forecast prices and costs based on the Sproule Report. The Sproule Report has been prepared in accordance with definitions, standards, and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The reserves evaluation was based on Sproule forecast escalated pricing and foreign exchange rates at December 31, 2021 as outlined in the table herein entitled “Price Forecast”.
All evaluations and summaries of future net revenue are stated prior to provision for interest, debt service charges and general administrative expenses, the input of hedging activities and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs (“ARC”) associated with the Company’s assets in the reserve report and estimated future capital expenditures associated with reserves. It should not be assumed that the estimates of net present value of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of our crude oil, natural gas liquids and conventional natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, conventional natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests) unless noted otherwise. In addition to the detailed information disclosed in this news release, more detailed information as prescribed by NI 51-101 will be included in the Company’s Annual Information Form (the “AIF”) for the year ended December 31, 2021, which will be filed on the Company’s profile at www.sedar.com on or before March 31, 2022.
See “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” for additional cautionary language, explanations and discussions and “Forward Looking Information and Statements” for a statement of principal assumptions and risks that may apply.
|Light & Medium
|Total Proved plus Probable||5,879||0||80,044||1,912,570||404,684|
1 Reserves have been presented on a “gross” basis which is defined as Crew’s working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Company.
2 Based on Sproule’s December 31, 2021 escalated price forecast.
3 Reflects 100% Conventional Natural Gas by product type.
4 Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.
5 Columns may not add due to rounding.
The estimated before tax net present value (“NPV”) of future net revenues associated with Crew’s reserves effective December 31, 2021, and based on the Sproule Report and the published Sproule (December 31, 2021) future price forecast, are summarized in the following table:
|Total Proved plus Probable||6,577,728||3,478,896||2,228,804||1,598,917||1,232,420|
1 Based on Sproule’s December 31, 2021 escalated price forecast. See “Price Forecast”.
2 The estimated future net revenues are stated prior to provision for interest, debt service charges, general administrative expenses, the impact of hedging activities, and after deduction of royalties, operating costs, ARC associated with the Company’s assets and estimated future capital expenditures.
3 The after-tax net present values of future net revenue attributed to Crew’s reserves will be included in the Company’s 2021 AIF to be filed on or before March 31, 2022.
4 Columns may not add due to rounding.
The Sproule December 31, 2021price forecast is summarized as follows:
|Henry Hub||Natural gas at
|Westcoast Station 2|
1 Escalated at 2.0% per year starting in 2032 with the exception of foreign exchange which remains constant.
2 Product sale prices will reflect these reference prices with further adjustments for quality and transportation to point of sale.
The following reconciliation of Crew’s gross reserves compares changes in the Company’s reserves as at December 31, 2021, based on the Sproule (December 31, 2021) future price forecast relative to the reserves as at December 31, 2020.
|FACTORS||Total Proved||Total Probable||Total Proved + Probable|
|December 31, 2020||202,488||207,490||409,978|
|Extensions and Improved Recovery1||11,452||7,735||19,187|
|December 31, 2021||206,807||197,878||404,684|
1 Increases to Extensions and Improved Recovery are the result of step-out locations drilled or proposed to be drilled by Crew. Reserves additions for improved recovery and extensions are combined and reported as “Extensions and Improved Recovery”.
2 Related to the previously disclosed sale of Crew’s Lloydminster heavy oil operations in Q3/21.
3 See the tables under “Reserves Reconciliation by Product Types” contained in this news release for a reconciliation by product type in accordance with NI 51-101.
4 Columns may not add due to rounding.
Corporate level technical revisions on a boe basis were -3.0% at the Proved level and -4.0% at the Proved plus Probable level. Technical revisions were primarily due to reserves reclassification and performance adjustments related to increased pipeline pressures from the addition of new wells in the 2021 capital program, offsetting completion operations, annual maintenance and removal of low priority future development bookings and adjustments to timing of future development drilling locations. Other revisions were attributable to the Company’s updated development planning resulting in adjustments to future development bookings, reflecting the continuing shift towards extended reach horizontal well designs and compliance with the COGE Handbook guidance on five year and 10 year development plans.
Capital Program Efficiency – Including FDC
|Exploration and Development Expenditures1,5
|Change in Future Development Capital1,6
|– Exploration and Development||4,725||(54,492||)||(143,361||)||4,598||(13,359||)||(429,892||)|
|Reserves Additions with Revisions and Economic Factors (mboe)|
|– Exploration and Development||25,125||16,915||10,388||48,418||63,033||25,996|
|Finding & Development Costs2,3,6
($ per boe)
– with revisions and economic factors
|Finding, Development & Acquisition Costs2,3,6
($ per boe)
– with revisions and economic factors
|Recycle Ratio3 (F&D)||4.0||3.9||8.6||3.6||5.0||(14.5||)|
1 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 capital generally will not reflect total finding and development costs related to reserve additions for that year.
2 F&D and FD&A costs above are calculated, as noted, after changes in FDC required to bring proved undeveloped and developed reserves into production, by dividing the identified capital expenditures by the applicable reserves additions.
3 Recycle ratio is defined as operating netback per boe divided by F&D costs on a per boe basis. Operating netback is a Non-IFRS Measure and is calculated as revenue (excluding realized hedging gains and losses) minus royalties, operating expenses, and transportation expenses. Crew’s estimated operating netback in fourth quarter 2021, used in the above calculations, averaged $28.76 per boe (unaudited), while the Company’s full year 2021 estimated operating netback averaged $23.56 per boe (unaudited). These amounts are estimates and subject to audit verification. See ‘Advisories – Unaudited Financial Information’ and ‘Advisories – Information Regarding Disclosure on Oil and Gas Reserves and Operational Information’.
4 “Reserves Replacement”, “FD&A Cost”, “F&D Cost”, “Operating Netback” and “Recycle Ratio” do not have standardized meanings and therefore may not be comparable with the calculation of similar measures for other entities. See “Advisories – Information Regarding Disclosure on Oil and Gas Reserves and Operational Information”.
5 All 2021 financial amounts are unaudited. See “Advisories – Unaudited Financial Information”.
6 The 2021 change in Future Development Capital (FDC) used in the calculation of Crew’s 1P and 2P F&D and FD&A costs does not include approximately $162 million (undiscounted) in the 1P case and $180 million (undiscounted) in the 2P case of maintenance capital that was reclassified to FDC in the December 31, 2021, Sproule Report which was booked as operating costs in prior years.
Unaudited Financial Information
Certain financial and operating information included in this press release for the quarter and year ended December 31, 2021, including, without limitation, exploration and development expenditures, acquisitions / dispositions, finding and development costs, finding, development and acquisition costs, recycle ratio and operating 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.
Information Regarding Disclosure on Oil and Gas Reserves and Operational Information
All amounts in this news release are stated in Canadian dollars unless otherwise specified. Our oil and gas reserves statement for the year ended December 31, 2021, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at www.sedar.com on or before March 31, 2022. The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties or subsets thereof, such estimates 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 metrics commonly used in the oil and natural gas industry, such as “recycle ratio”, “finding and development costs”, “finding, development and acquisition costs, “future development capital”, “maintenance capital”, and “reserves replacement”. Each of these metrics are determined by Crew as specifically set forth in this news release. These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included to provide readers with additional information to evaluate the Company’s performance however, such metrics are not reliable indicators of future performance and therefore should not be unduly relied upon for investment or other purposes. Recycle Ratio is calculated as operating netback per boe divided by F&D costs on a per boe basis. Reserves Replacement Ratio is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Crew’s annual 2021 production averaged 26,442 boe per day. Management uses these metrics for its own performance measurements and to provide readers with measures to compare Crew’s performance over time.
Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated FDC may not reflect total F&D 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 our ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure.
Certain financial measures referred to in this press release, such as adjusted funds flow or AFF, net operating costs and working capital deficiency and are not prescribed by IFRS. Crew uses these measures to help evaluate its financial and operating performance as well as its liquidity and leverage. These non-IFRS financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other issuers.
“Adjusted funds flow” or “AFF”, presented herein is equivalent to funds from operations before decommissioning obligations settled. The Company considers this metric as a key measure that demonstrate the ability of the Company’s continuing operations to generate the cash flow necessary to maintain production at current levels and fund future growth through capital investment and to service and repay debt. Crew also presents AFF per share in this presentation whereby per share amounts are calculated using fully diluted shares outstanding.
“Free AFF” is calculated by taking adjusted funds flow and subtracting capital expenditures, excluding acquisitions and dispositions. Management believes that free adjusted funds flow provides a useful measure to determine Crew’s ability to improve sustainability and to manage the long-term value of the business.
“Net Operating Costs” equals operating costs net of processing revenue.
Please refer to Crew’s most recently filed MD&A for additional information relating to Non-IFRS measures including a reconciliation of AFF to its most closely related IFRS measure. The MD&A can be accessed either on Crew’s website at www.crewenergy.com or under the Company’s profile on www.sedar.com.
Reserves Reconciliation by Product Types
|December 31, 2020||3,493||3,232||41,291||926,837||202,488|
|Extensions and Improved Recovery||0||0||34||68,506||11,452|
|December 31, 2021||3,457||0||38,891||986,753||206,807|
|December 31, 2020||3,484||3,071||45,064||935,232||207,490|
|Extensions and Improved Recovery||0||0||23||46,274||7,735|
|December 31, 2021||2,422||0||41,152||925,817||197,878|
|TOTAL PROVED PLUS PROBABLE||Light/Med
|December 31, 2020||6,977||6,302||86,354||1,862,069||409,978|
|Extensions and Improved Recovery||0||0||57||114,780||19,187|
|December 31, 2021||5,879||0||80,044||1,912,570||404,684|
Supplemental Information Regarding Product Types
The following is intended to provide the product type composition for each of the boe/d production figures provided herein, where not already disclosed within tables above:
Corporate Production Volume Breakdown2
|Crude Oil1||Natural gas
|Condensate||Conventional Natural gas||Total (boe/d)|
|2020 Q4 Average||7||%||9||%||10||%||74||%||21,666|
|2021 Q4 Average||1||%||7||%||9||%||83||%||29,100|
|2021 Annual Average||4||%||9||%||10||%||77||%||26,442|
(1) Crude oil is comprised primarily of Heavy crude oil, with an immaterial portion of Light and Medium crude oil.
(2)With respect to forward looking production guidance, given the potential for variability in actual product type results, the issuer approximates percentages for budget planning purposes based on management’s reasonable assumptions including, without limitation, historical well results.
(3) Excludes condensate volumes which have been reported separately.