Crew Energy Announces Year end 2019 Reserves Highlighted by Strong Capital Efficiencies and Provides Operational Update

Source Company Press Release
Company Crew Energy Inc.
Tags Corporate: Corporate Results, Guidance, Overview/Strategy, Country: Canada, Financial - Costs & Metrics: Capital Expenditures, Hedging
Date February 10, 2020

Crew Energy Inc. (TSX: CR) of Calgary, Alberta ("Crew" or the "Company") is pleased to provide highlights from our independent corporate reserves evaluation prepared by  Sproule Associates Ltd. ("Sproule") with an effective date of December 31, 2019 (the "Sproule Report").


Highlights of our proved developed producing ("PDP"), total proved ("1P") and total proved plus probable ("2P") reserves from the Sproule Report are provided below.  All finding, development and acquisition ("FD&A")1,2 costs and finding and development ("F&D")1,2 costs below include changes in future development capital ("FDC").   

Crew's 2019 capital program focused on the development of the Company's Ultra-Condensate Rich ("UCR")3 area emphasizing growth in high-value condensate production and reserves.  Continued efforts to control both capital expenditures and operating costs and our ongoing initiatives to improve efficiencies led to net capital expenditures of $95.0 million ($114.1 million gross)1,4.  This capital program resulted in the drilling of 8.0 net extended reach horizontal ("ERH") wells in B.C., of which 6.0 net wells were drilled in Greater Septimus, and the completion of 12.0 net wells in our UCR area at Greater Septimus. 

  • Proved Developed Producing Reserves Growth:  In 2019, Crew added 11.3 MMboe of PDP reserves representing approximately 19% of 2018 PDP reserves, bringing the total to 63.1 MMboe at year-end, 5% higher than 2018.  PDP FD&A2 costs were $8.79 per boe resulting in a recycle ratio2 of 1.4x.

  • Proved Reserves Increased 17% over 2018:  Crew added 37.5 MMboe of 1P reserves, which increased 17% to 202.0 MMboe, and achieved a 1P FD&A cost of $6.16 per boe resulting in a recycle ratio of 2.0x.  The Company's PDP and 1P reserves additions were achieved in concert with lower development capital due to efficiency enhancements in part associated with increasing the number of ERH wells.  Crew's 2P reserves replaced production and remained stable at 410.6 MMboe, as the Company reduced 2P FDC by $107 million, reflecting improved cost efficiencies and the removal of longer-dated reserve additions. 

  • Continued Strong Performance from UCR Area:  Reserves assigned at Crew's UCR area of operations increased meaningfully in 2019 across all reserve categories:  
    • 2P totaled 97.3 MMboe, 1P was 50.8 MMboe, and PDP was 15.8 Mmboe.
    • Condensate5 reserves in the area increased over 2018 with PDP up 110% to 4.0 MMbbls; 1P up 52% to 13.7 MMbbls and 2P increased by 24% to 26.4 MMbbls. 
    • In Crew's UCR area the estimated net present value of future net revenue discounted at 10% (before tax) ("NPV10 BT") for 2P reserves assigned by Sproule to 17.5 net sections was $856.0 million6.

  • Longer Laterals Improve Recoveries:  Significant efficiencies and improvements in recoveries have been gained with the ERH program in Crew's UCR area relative to previous shorter-reach horizontal wells, with a 35% improvement in drilling cost per lateral length realized from 2016 to 2019.  The ERH program can generate equivalent recoveries and superior economic returns with a smaller environmental footprint, lower operating costs and significantly lower development costs.  Crew now has 50 ERH undeveloped 2P locations assigned by Sproule in the UCR area.  

  • Strong Capital Efficiencies and Recycle Ratios1,2: Continued development success was realized at Crew's UCR area, leveraging improved completions design, longer ERH wells and reduced drill times to improve per well recoveries with reduced capital.  Recycle ratios shown below are based on the estimated fourth quarter 2019 corporate operating netback of $12.16 per boe1,4 divided by the F&D or FD&A costs.  For informational purposes, the estimated annual operating netback for 2019 is $14.05 per boe1,4.
2019 F&D and FD&A Costs 
  F&D per boe    F&D recycle7    FD&A per boe    FD&A recycle7 
PDP  $10.49    1.2x    $8.79    1.4x 
1P  $6.66    1.8x    $6.16    2.0x 
2P  $0.86    14.1x    ($1.54)    (7.9x) 
  • Three Year Costs Trending Lower: With an ongoing focus on reduced capital costs and capturing drilling and completions efficiencies, Crew achieved another consecutive year of declining average three year 2P F&D and FD&A costs in 2019 which totaled $5.66 per boe and $5.02 per boe, respectively, reflecting reductions of 4% and 9% from 2018, respectively. 


Results from Crew's 3-32 UCR pad at West Septimus have demonstrated continued improvement in operating efficiencies. In the fourth quarter of 2019, the Company completed four UCR wells that came in under budget and averaged greater than 3,000 metres in length, which are the longest in the Company's history.  On this pad, which incorporated recent completion design improvements, completion costs averaged approximately $3.8 million, or $1,278 per lateral metre which is 26% lower than Crew's previous pacesetter pad.

The four wells on the 3-32 pad flowed back at restricted rates, with per well condensate sales volumes averaging 758 bbls per day, a propane/butane sales rate averaging 142 bbls per day and a conventional natural gas sales rate averaging 2.37 mmcf per day over the last six hours of a 19 day production test.  During the flow period, over 50,000 bbls of sales condensate was produced and total sales liquid averaged approximately 70% of total production, with strong final flowing casing pressures averaging 1,123 psi at the end of the test.

Based on unaudited field estimates, Crew's annual production averaged 22,837 boe per day8 in 2019 while fourth quarter production was at the high end of the guidance range at 22,446 boe per day9 as the four completed UCR wells saw first hydrocarbons sooner and rates were higher than anticipated. Annual condensate volumes averaged 2,693 bbls per day which were 6% higher than the previously announced forecast of 2,550 bbls per day.

1 All 2019 financial amounts are unaudited. See advisories." 
2 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 the table "Capital Program Efficiency" and "Information Regarding Disclosure on Oil and Gas Reserves and Operational Information" contained in this news release. 
3 Ultra-Condensate Rich" or "UCR" is not defined in NI 51-101 and means a fairway of land at Crew's Greater Septimus area of operations where productive zones have high condensate rates (initial 30-day condensate / gas ratio rates of greater than 75 bbls per mmcf). 
4 Non-IFRS Measure. "Operating netback" and "net capital expenditures" do not have standardized measures prescribed by International Financial Reporting Standards ("IFRS"), and therefore may not be comparable with the calculations of similar measures for other companies. See "Information Regarding Disclosure on Oil and Gas Reserves, Operational Information and Non-IFRS Measures" within this press release and the Company's MD&A for details including reasons for use. 
5 Condensate is defined as a mixture of pentanes and heavier hydrocarbons recovered as a liquid at the inlet of a gas processing plant before the gas is processed and pentanes and heavier hydrocarbons obtained from the processing of raw natural gas. 
6 Excludes field-level facility and maintenance operating expenses. 
7 Crew's estimated operating netback in fourth quarter 2019, used in the above calculations, averaged $12.16 per boe (unaudited), while the Company's estimated full year 2019 operating netback averaged $14.05 per boe (unaudited).  See 'Unaudited Financial Information' and 'Information Regarding Disclosure on Oil and Gas Reserves, Operational Information and Non-IFRS Measures' in the advisories. 
8 71% conventional natural gas, 12% condensate, 9% NGLs, 7% heavy oil and 1% light oil. 
9 72% conventional natural gas, 11% condensate, 9% NGLs, 7% heavy oil and 1% light oil. 


The detailed reserves data set forth below is based upon the Sproule Report with an effective date of December 31, 2019.  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, 2019 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, decommissioning and reclamation costs 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, 2019, which will be filed on the Company's profile at on or before March 30, 2020.  

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.

Corporate Reserves(1,2,5)

  Light Crude Oil
and Medium
Crude Oil 
Heavy Crude
Natural Gas
Natural Gas(3) 
Barrels of
  (mbbl)  (mbbl)   (mbbl)   (mmcf)   (mboe) 
     Developed Producing  315  1,070  13,141  291,587  63,122 
     Developed Non-producing  856  195  5,098  1,901 
     Undeveloped  3,198  2,068  27,784  623,453  136,958 
Total Proved  3,512  3,994  41,120  920,138  201,982 
Total Probable  3,794  3,574  43,310  947,488  208,592 
Total Proved plus Probable  7,306  7,568  84,430  1,867,626  410,574 
(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, 2019 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. 

Reserves Values(1)(2)(3)(4)  

The estimated before tax net present value ("NPV") of future net revenues associated with Crew's reserves effective December 31, 2019 and based on the Sproule Report and the published  Sproule (December 31, 2019) future price forecast are summarized in the following table:

(m$)  0%  5%  10%  15%  20% 
     Developed Producing  704,938  543,075  438,722  370,013  322,240 
     Developed Non-producing  27,826  23,323  20,130  17,755  15,903 
     Undeveloped  1,983,005  1,081,723  653,409  423,237  286,736 
Total Proved  2,715,768  1,648,121  1,112,261  811,005  624,879 
Total Probable  4,343,823  1,829,803  956,345  579,980  390,500 
Total Proved plus Probable  7,059,591  3,477,924  2,068,605  1,390,985  1,015,379 
(1)  Based on Sproule's December 31, 2019 escalated 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, ADR associated with the Company's assets and estimated future capital expenditures. 
(3)  The after-tax present values of future net revenue attributed to Crew's reserves will be included in the Company's 2019 AIF to be filed on or before
March 30, 2020. 
(4)  Columns may not add due to rounding. 

Commencing in 2019, Sproule included additional abandonment and reclamation obligations ("ARO") in the Company's reserves evaluation, which resulted in a decrease in value relative to 2018. This significant change to the prior years' practices, which were consistent with the reporting of many other companies in the industry, was made based on new guidelines contained within the COGE Handbook, which recommends adopting the best practice of including abandonment, decommissioning and reclamation ("ADR") costs associated with all of the Company's assets evaluated in the  Sproule Report. This includes costs for both active and inactive wells, including ADR costs for producing wells, suspended wells, service wells, gathering systems, facilities, and surface land development for all the Company's assets. At year-end 2019,  Sproule's evaluation of Crew's NPV10 BT for ADR related to Crew's 2P, 1P and PDP reserves was $42.5 million, $42.7 million, and $40.8 million, respectively, an increase of $35.3 million, $35.8 million, and $36.2 million compared to the corresponding ADR measures at the end of 2018.

Price Forecast

The Sproule December 31, 2019 price forecast is summarized as follows:  

 Year  Exchange
Light Sweet 
Canada Select 
Natural gas
AECO-C spot 
  ($US/$Cdn)  (US$/bbl)  (C$/bbl)  (C$/bbl)  (US$/mmbtu)  (C$/mmbtu) 
2020  0.760  61.00  73.84  59.81  2.80  2.04 
2021  0.770  65.00  78.51  63.98  3.00  2.27 
2022  0.800  67.00  78.73  63.77  3.25  2.81 
2023  0.800  68.34  80.30  65.04  3.32  2.89 
2024  0.800  69.71  81.91  66.34  3.38  2.98 
2025  0.800  71.10  83.54  67.67  3.45  3.06 
2026  0.800  72.52  85.21  69.02  3.52  3.15 
2027  0.800  73.97  86.92  70.40  3.59  3.24 
2028  0.800  75.45  88.66  71.81  3.66  3.33 
2029  0.800  76.96  90.43  73.25  3.73  3.42 
2030  0.800  78.50  92.24  74.71  3.81  3.51 
2031 +(1)    2.0%/yr  2.0%/yr  2.0%/yr  2.0%/yr  2.0%/yr 
(1)  Escalated at 2.0% per year starting in 2030 with the exception of foreign exchange which remains flat. 

Reserves Reconciliation

The following reconciliation of Crew's gross reserves compares changes in the Company's reserves as at December 31, 2019 based on the Sproule (December 31, 2019) future price forecast relative to the reserves as at December 31, 2018.

FACTORS  Total Proved  Total Probable  Total Proved +
December 31, 2018  172,840  238,127  410,967 
Extensions and Improved Recovery(1)  9,542  17,626  27,168 
Infill Drilling  65  43  108 
Technical Revisions  30,114  (48,168)  (18,054) 
Dispositions  (49)  (23)  (72) 
Economic Factors  (2,195)  987  (1,208) 
Production  (8,336)  (8,336) 
December 31, 2019  201,982  208,593  410,574 
(1)  Increases to Extensions and Improved Recovery are the result of step-out locations drilled by Crew. Reserves additions for improved recovery and extensions are combined and reported as "Extensions and Improved Recovery". 
(2)  Columns may not add due to rounding. 
(3)  Reconciliation by product type in accordance with NI 51-101 will be contained in Crew's AIF to be filed on or before March 30, 2020. 

Technical revisions in the 1P category for year end 2019 were predominantly the result of undeveloped locations moving from the Total Probable category into the Total Proved category.  Several factors contributed to technical revisions on 2P reserves at year end 2019, including a minor reduction in NGL yield at Septimus and West Septimus, which declined from 38.5 bbls/mmcf in 2018 to 36.0 bbls/mmcf in 2019.  Due to the increase in UCR wells in 2019, Crew realized changes to gas shrinkage rates at Septimus and West Septimus, which increased from 7.5% at year end 2018 to 9.0% in 2019.  Finally, in the greater Tower area, 16 probable only locations were removed as those extended beyond the ten years of development timing guidance as prescribed within the COGE Handbook, with a lower priority of corporate commitment to the project.

Capital Program Efficiency

  2019  2018  2017-2019 
  1P  2P  1P  2P  1P  2P 
Exploration and Development Expenditures(1)(6) ($ thousands)  114,094  114,094  103,219  103,219  455,615  455,615 
($ thousands) 
(19,085)  (19,085)  (9,805)  (9,805)  (76,796)  (76,796) 
Change in Future Development Capital(1) ($ thousands)             
      - Exploration and Development  135,712  (107,199)  (19,952)  130,237  125,274  205,907 
      - Acquisitions/Dispositions  (10)  (10)  (40)  (40)  (7,925)  (21,850) 
Reserves Additions with Revisions and Economic Factors (mboe)             
      - Exploration and Development  37,526  8,015  12,200  49,506  75,596  74,244 
      - Acquisitions/Dispositions  (49)  (72)  (18)  (28)  (1,352)  (4,788) 
  37,476  7,943  12,182  49,478  74,244  112,102 
  2019  2018  3 Year Average
  1P  2P  1P  2P  1P  2P 
Finding & Development Costs(2)(5) 
($ per boe) 
      - with revisions and economic factors  6.66  0.86  6.82  4.72  7.68  5.66 
Finding, Development & Acquisition Costs(2)(5) ($ per boe)             
      - with revisions and economic factors  6.16  (1.54)  6.03  4.52  6.68  5.02 
Recycle Ratio(3)(5) (F&D)  1.8  14.1  2.3  3.4     
Reserves Replacement(4)(5)  450%  95%  140%  568%     
(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)  The calculation of F&D and FD&A costs incorporates the change in FDC required to bring proved undeveloped and developed reserves into production.  In all cases, the F&D or FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions after changes in FDC costs. 
(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 (including realized hedging gains and losses) minus royalties, operating expenses, and transportation expenses.  Crew's estimated operating netback in fourth quarter 2019, used in the above calculations, averaged $12.16 per boe (unaudited), while the Company's full year 2019 estimated operating netback averaged $14.05 per boe (unaudited).  These amounts are estimates and subject to audit verification.  See Non-IFRS Measures contained in Crew's MD&A for calculations and rationale for use. 
(4)  Reserves replacement ratio is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Based on field estimates, Crew's 2019 annual production averaged 22,837 boe per day. 
(5)  "Reserves Replacement", "FD&A Cost", "F&D Cost", and "Recycle Ratio" do not have standardized meanings and therefore may not be comparable with the calculation of similar measures for other entities.  See "Information Regarding Disclosure on Oil and Gas Reserves and Operational Information" in this news release. 
(6)  All 2019 financial amounts are unaudited. See advisories. 

Future Development Capital

The following table provides a summary of the estimated FDC required to bring Crew's reserves on production.

  Total  Total Proved 
Future Development Capital ($millions)(1)  Proved  plus Probable 
2020  76  80 
2021  139  150 
2022  191  221 
2023  164  187 
2024  83  88 
Remainder  192  1,061 
Total FDC undiscounted  844  1,787 
Total FDC discounted at 10%  618  998 
Source: EvaluateEnergy® ©2024 EvaluateEnergy Ltd