Crew Energy Announces 2023 Reserves, 2024 Capital Budget and Guidance

Source Company Press Release
Company Crew Energy Inc.
Tags Corporate: Corporate Results, Guidance, Overview/Strategy, Country: Canada, Financial - Costs & Metrics: Capital Expenditures, Segment: LNG, Upstream: Drilling Activity
Date February 08, 2024

Crew Energy Inc. (TSX: CR; OTCQB: CWEGF) ("Crew" or the "Company"), a growth-oriented natural gas weighted producer operating in the world-class Montney play in northeast British Columbia (“NE BC”), is pleased to announce the results of our year-end 2023 independent reserves evaluation along with our 2024 capital expenditure budget and guidance. Crew’s 2024 budget builds on the success of our 2023 drilling program, efficient execution and asset development, all of which are demonstrated by growth in our 2023 independent reserves evaluation. Production averaged 30,928 boe per day1 in the final quarter of 2023, a 15% increase from 26,834 boe per day1 in Q3/23 and in-line with guidance of 30,000 to 32,000 boe per day.

The Company invested approximately $54 million in Q4/23, 17% lower than the midpoint of guidance of $65 million, while net debt2 decreased 21% at year-end to approximately $117 million compared to year-end 2022. Crew’s 2024 budget aims to maintain current production levels, support strategic investments to advance long-term growth plans, and preserve a strong balance sheet. Together, this is expected to position Crew to take advantage of what is anticipated to be an improved supply and demand environment for natural gas as North American LNG export growth accelerates into 2025 and forward.

Highlights of our independent reserves evaluation prepared by Sproule Associates Ltd. (“Sproule”) are provided below, effective December 31, 2023 (the “Sproule Report”). 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.


  • 17% increase in Total Proved (“1P”) reserves and 27% increase in Total Proved Plus Probable (“2P”) reserves over 2022, with 1P reserve additions 129% and 2P reserve additions 600% greater than last year, excluding A&D.
  • NAV per share5 of $4.33 (PDP), $9.70 (1P) and $18.61 (2P), representing a significant discount to Crew’s current enterprise value.
  • Proved Developed Producing (“PDP”) reserve additions of 7.3 mmboe driving 3-year F&D3,4 and FD&A3,4 costs of $11.23 per boe and $8.61 per boe, respectively, with strong 3-year PDP recycle ratios3,4,6 of 2.0x and 2.6x, respectively.
  • $165 to $185 million of total net capital expenditures7, expected to maintain average annual production of between 29,000 to 31,000 boe per day1 (the “2024 Budget”), which is anticipated to include:
    • $105 to $115 million allocated to the drilling of approximately 6 (6.0 net) wells, and completion of approximately 11 (11.0 net) wells, with an expected inventory of ten (10.0 net) drilled uncompleted wells remaining at the end of 2024;
    • 5,300 bbls per day of anticipated average condensate and light crude oil production at Greater Septimus, representing a 15% increase in 2024 over 2023; and
  • $60 to $70 million in strategic infrastructure investments, including a facility expansion and electrification at West Septimus as well as site preparation and other preliminary expenditures on a future Groundbirch gas processing facility


Crew’s approved 2024 Budget includes net capital expenditures7 of $165 to $185 million and incorporates a conservative drilling and completions program as well as $60 to $70 million in strategic electrification and infrastructure expansion projects. These initiatives support Crew’s longer-term growth prospects while preserving the upside in our large resource base.

Maintenance Capital

  • Crew’s 2024 development capital of $105 to $115 million is budgeted to maintain production at levels similar to 2023, between 29,000 and 31,000 boe per day1, while increasing condensate and light oil production by 15% to an anticipated 5,300 bbls per day.
  • The Company plans to drill six (6.0 net) wells and to complete 11 (11.0 net) wells, including the completion of six wells previously drilled on the Tower 15-28 pad and five previously drilled wells on the Septimus 7-18 pad, with an expected inventory of ten (10.0 net) drilled uncompleted wells at the end of 2024, setting up for 2025 and aligning with the anticipated improvement in natural gas prices as LNG export becomes operational on Canada’s west coast.

Infrastructure Investments

  • Approximately $50 million is expected to be directed to West Septimus for advancing the estimated $80 million facility expansion and electrification, targeting reduced costs and emissions upon completion, and increasing the inlet capacity at the West Septimus plant from 120 mmcf per day to 140 mmcf per day8. As a result of this project, Crew also expects to connect and deliver power to the planned future facility at Groundbirch and reduce electrification costs for the Groundbirch project by approximately $30 million.
  • Upon completion of the electrification project at West Septimus, targeted for H2 2025, Crew anticipates recovering approximately 53% of the project’s estimated costs by recognizing funding and credits totaling $42 million associated with various provincial and federal government financial incentives for clean energy conversion initiatives. The funding and credits are related to securing a line position and the installation of power to the West Septimus gas plant. Crew gratefully acknowledges assistance from the Province of British Columbia’s CleanBC Industry Fund for their part in supporting this project.
  • Approximately $15 million is planned for investment into site preparation, front-end engineering and design (“FEED”) and procuring long-lead items for the planned construction of an electric drive deep-cut gas plant (the “Groundbirch Plant”) in our Groundbirch area (the “Groundbirch Project”).

Laying the Groundwork at Groundbirch

  • Crew has received a permit from the B.C. Energy Regulator (“BCER”) approving the construction of our planned 180 mmcf per day Groundbirch Plant as well as 60 well authorization permits, bringing our total to 85 well authorizations in the Groundbirch area.
  • The Groundbirch Plant supports our longer-term development and expanded scale, and with permitting now in place, this longer-range strategic plan can commence with the electrification of West Septimus, which represents the first step to full Groundbirch development.
  • In addition to surface preparations and FEED work, Crew also plans to allocate capital in 2024 and 2025 for the construction of 20 kilometers of a 12-inch and a 10-inch pipeline from West Septimus to Groundbirch, upon receipt of regulatory approval.

With ongoing supply and demand imbalances in global natural gas, the current spot and future strip prices have remained under pressure. In response, we are investing prudently to advance key milestones of the Groundbirch Project while deferring large capital outlays until they are supported by an improved natural gas pricing environment.

2024 Budget Underlying Assumptions

Net capital expenditures7 ($Millions)  165-185 
Annual average production1 (boe/d)  29,000-31,000 
Liquids Production (%)  26 
Royalty Rate (%)  8-10 
Net operating costs7 ($ per boe)  4.50-5.00 
Net transportation costs7 ($ per boe)  3.50-4.00 
General and administrative (“G&A”) ($ per boe)  1.00-1.20 
Effective interest rate on long-term debt (%)  8-10 


We would like to recognize our Crew’s commitment to safety in our field operations. We are extremely proud to report that over 1.568-million-person hours of work were undertaken to the end of 2023 without a single recordable injury, further extending our corporate record and underscoring the Company’s firm commitment to safety.

NE BC Montney (Greater Septimus)

  • Crew drilled seven (7.0 net) Montney wells during Q4/23.
  • Over the first 30 days on production (“IP30”), four (4.0 net) ultra-condensate rich (“UCR”) natural gas wells which were completed on the 1-24 pad in Q4/23 have produced average raw wellhead rates of 2,625 mcf per day of natural gas and 1,037 bbls per day of condensate. Crew achieved our target by averaging over 7,000 bbls per day of condensate and light crude oil production in November.
  • During Q1/24, Crew plans to complete five (5.0 net) Montney UCR wells, equip and tie-in 11 (11.0 net) Montney UCR wells and drill six (6.0 net) Montney wells.


  • The original three (3.0 net) wells on the 4-17 pad have completed lateral lengths averaging 3,000 meters and have produced an average of over 4 bcf of natural gas over the first 720 days, exceeding Sproule’s year-end 2023 proved plus probable undeveloped Groundbirch type curve by approximately 33% to date.
  • The second phase of development at Crew’s 4-17 pad has completed lateral lengths averaging 2,650 meters, featuring a three-zone development with five (5.0 net) wells that have continued to exceed the 3,000-meter lateral length type curve estimates with average raw gas Expected Ultimate Recovery (EUR) of 12 BCF per well.

Other NE BC Montney

  • The Company has six (6.0 net) drilled Extended Reach Horizontal wells on the 15-28 pad at Tower, targeting light crude oil and featuring lateral lengths of over 4,000 meters. Of these wells, four (4.0 net) Upper Montney “B” wells and two (2.0 net) Upper Montney “C” wells are now planned for completion in Q3/24.


  • With near- and medium-term natural gas prices remaining under pressure, Crew plans to focus on the development of our condensate-rich assets at Greater Septimus with plans to increase average condensate and light oil production by approximately 15% from 2023 levels, while allowing 2024 natural gas production to decline by an average of approximately 5% compared to the prior year. This strategy sets up an active Q1/24 capital program for Crew, with plans to invest $75 to $85 million and drill six (6.0 net) wells, complete five (5.0 net) wells and equip and tie-in 11 (11.0 net) Montney wells. This level of activity is expected to result in forecast average production of 29,000 to 31,000 boe per day1 for the first quarter, which includes the impact of an anticipated 2,100 boe per day of production that is shut-in for offsetting completion and construction operations.
  • Our long-range plans are designed to generate maximum value from the strategic location, target zone optionality, commodity diversity and multiple egress options that are offered by our large, contiguous Montney land base. The Company is well positioned to be an active participant in what is expected to be an improved natural gas supply and demand dynamic when LNG Canada is commissioned in 2025, and we are targeting a continued improvement in per unit costs, increasing margins and expanding Adjusted Funds Flow (“AFF”). Crew intends to continue advancing development of the Company’s large inventory of over 2,500 identified potential drilling locations10, of which only 238 are booked within our year-end 2023 independent reserves evaluation.
  • Given this significant flexibility and ideal positioning, Crew’s asset base offers a perfect fit for the future of Canadian energy. Throughout 2024, we will remain committed to building on the positive momentum realized over the last three years and focusing on responsible growth and operational excellence in the further development of our top-tier, strategically located assets. We extend our appreciation to all stakeholders for their ongoing support of Crew while we continue to unlock value from our expansive inventory of Montney well locations.


The detailed reserves data set forth below is based upon the Sproule Report. 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 the forecast prices and costs reflected in 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 an arithmetic average of the published escalated price forecasts of  Sproule, McDaniel & Associates Consultants (“McDaniel”) and GLJ Ltd. (“GLJ”) (the “IC3 Average”) and Sproule’s foreign exchange rates at December 31, 2023 as outlined in the table below entitled "Price Forecast".

See "Information Regarding Disclosure on Oil and Gas Reserves and Operational Information" for additional cautionary language, explanations and discussion and "Forward Looking Information and Statements" for principal assumptions and risks that may apply.

Corporate Reserves11,12,13

  Light & Medium Crude Oil  Natural Gas Liquids  Conventional Natural Gas14  Barrels of oil equivalent15 
  (mbbl)  (mbbl)  (mmcf)  (mboe) 
Developed Producing  289  15,103  417,067  84,903 
Developed Non-producing  675  17,475  3,587 
Undeveloped  3,180  28,089  767,866  159,247 
Total Proved  3,469  43,867  1,202,408  247,737 
Total Probable  5,146  33,157  1,122,959  225,462 
Total Proved plus Probable  8,615  77,024  2,325,367  473,199 

Reserves Values12,13,16,17

The estimated before tax net present value (“NPV”) of future net revenues associated with Crew’s reserves effective December 31, 2023, and based on the Sproule Report and the published IC3 Average future price forecast, are summarized in the following table:

(M$)  0%  5%  10%  15%  20% 
Developed Producing  1,420,905  1,023,887  795,360  652,861  556,750 
Developed Non-producing  68,211  44,028  31,526  24,171  19,395 
Undeveloped  2,606,680  1,390,732  808,917  492,904  303,203 
Total Proved  4,095,795  2,458,647  1,635,804  1,169,936  879,348 
Total Probable  5,010,049  2,393,791  1,394,993  914,608  647,455 
Total Proved plus Probable  9,105,844  4,852,438  3,030,797  2,084,544  1,526,803 

Price Forecast18,19

The IC3 Average December 31, 2023, price forecast used for the purposes of preparing the Sproule Report is summarized as follows:

 Year  Exchange Rate  WTI @ Cushing  Canadian Light Sweet  Henry Hub  Natural gas at AECO/NIT spot  Westcoast Station 2 
  ($US/$/Cdn)  (US$/bbl)  (C$/bbl)  (US$/mmbtu)  (C$/mmbtu)  (C$/mmbtu) 
2024  0.750  73.67  92.91  2.75  2.20  2.06 
2025  0.750  74.98  95.04  3.64  3.37  3.25 
2026  0.760  76.14  96.07  4.02  4.05  3.93 
2027  0.760  77.66  97.99  4.10  4.13  4.01 
2028  0.760  79.22  99.95  4.18  4.21  4.09 
2029  0.760  80.80  101.94  4.27  4.30  4.17 
2030  0.760  82.42  103.98  4.35  4.38  4.25 
2031  0.760  84.06  106.06  4.44  4.47  4.34 
2032  0.760  85.74  108.18  4.53  4.56  4.42 
2033  0.760  87.46  110.35  4.62  4.65  4.51 
2034+(18)    +2.0%/yr  +2.0%/yr  +2.0%/yr  +2.0%/yr  +2.0%/yr 

Reserves Reconciliation13,20

The following reconciliation of Crew’s gross reserves compares changes in the Company’s independently evaluated reserves as at December 31, 2023, relative to the reserves as at December 31, 2022.

FACTORS  Total Proved  Total Probable  Total Proved + Probable 
December 31, 2022  210,882  163,136  374,018 
Extensions and Improved Recovery21  42,354  62,763  105,117 
Infill Drilling 
Technical Revisions  4,868  (10)  4,858 
Economic Factors  648  (427)  221 
Production  (11,015)  (11,015) 
December 31, 2023  247,737  225,462  473,199 

Corporate level technical revisions on a boe basis were 2% at the Proved level and 1% at the Proved plus Probable level. Technical revisions were primarily due to the additional facility capacity available with the development of the Groundbirch Plant, as well as operating cost and well performance changes.

Material changes in other categories were attributable to extensions, which incorporated the addition of 56 locations in the Groundbirch area to fill the new Groundbirch Plant to capacity by 2027.

Capital Program Efficiency – Including FDC

  PDP  1P  2P 
Exploration and Development Expenditures22,23 ($ thousands)  217,027  217,027  217,027 
Acquisitions/(Dispositions)22,23 ($ thousands)  (1,015)  (1,015)  (1,015) 
Change in Future Development Capital4,22 ($ thousands)       
- Exploration and Development  1,127  462,771  637,564 
- Acquisitions/Dispositions 
Reserves Additions with Revisions and Economic Factors (mboe)       
- Exploration and Development  7,331  47,870  110,197 
- Acquisitions/Dispositions 
  PDP  1P  2P 
Finding & Development Costs4,24,25 ($ per boe)  29.76  14.20  7.76 
- with revisions and economic factors 
Finding, Development & Acquisition Costs4,24,25 ($ per boe)  29.62  14.18  7.75 
- with revisions and economic factors 
Recycle Ratio25 (F&D)  0.8  1.6  2.9 
Reserves Replacement3  67%  435%  1000% 

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, 2023, which will be filed on the Company's profile at on or before March 31, 2024.

Net Asset Value (“NAV”)

The following table sets out the calculation of the Company's NAV referred to herein based on the before-tax estimated net present value of future net revenue discounted at 10% ("NPV10 BT") associated with the PDP, 1P and 2P reserves, as evaluated in the Sproule Report:

  Proved Developed Producing  Total Proved  Total Proved + Probable 
NPV10 BT (MM$)  795.4  1,635.8  3,030.8 
Estimated net debt December 31, 2023 (MM$)  117.4  117.4  117.4 
Net Asset Value (MM$)  678.0  1,518.4  2,913.4 
Common shares* (MM)  156.6  156.6  156.6 
Estimated NAV per basic share ($)  4.33  9.70  18.61 

* Issued and outstanding as at December 31, 2023, on a non-diluted basis

Reserves Reconciliation by Product Types

TOTAL PROVED  Light/Med Crude Oil (mbbls)  NGL's (mbbls)  Conventional Natural Gas (mmcf)  Oil Equivalent (mboe) 
December 31, 2022  2,628  40,420  1,007,002  210,882 
Extensions  1,590  6,244  207,122  42,354 
Infill Drilling 
Improved Recovery 
Technical Revisions  (721)  (416)  36,033  4,868 
Economic Factors  118  3,182  648 
Production  (28)  (2,498)  (50,930)  (11,015) 
December 31, 2023  3,469  43,867  1,202,409  247,737 
TOTAL PROBABLE  Light/Med Crude Oil (mbbls)  NGL's (mbbls)  Conventional Natural Gas (mmcf)  Oil Equivalent (mboe) 
December 31, 2022  5,530  28,641  773,793  163,136 
Extensions  (920)  3,745  359,629  62,763 
Infill Drilling 
Improved Recovery 
Technical Revisions  539  855  (8,422)  (10) 
Economic Factors  (2)  (84)  (2,042)  (427) 
December 31, 2023  5,146  33,157  1,122,958  225,462 
TOTAL PROVED PLUS PROBABLE  Light/Med Crude Oil (mbbls)  NGL's (mbbls)  Conventional Natural Gas (mmcf)  Oil Equivalent (mboe) 
December 31, 2022  8,158  69,061  1,780,795  374,018 
Extensions  670  9,989  566,751  105,117 
Infill Drilling 
Improved Recovery 
Technical Revisions  (183)  439  27,611  4,858 
Economic Factors  (2)  34  1,139  221 
Production  (28)  (2,498)  (50,930)  (11,015) 
December 31, 2023  8,615  77,024  2,325,366  473,199


The following table provides a detailed breakdown of the identified gross potential drilling locations presented herein:

  Total Drilling Locations  Proved Locations  Probable Locations  Unbooked Locations 
Montney Total Drilling Locations  2,537  132  106  2,299 
Groundbirch Locations  1,717  37  66  1,614 
West Septimus Locations  483  59  28  396 
Septimus Locations  191  36  146 
Tower Locations  146  143


Supplemental Information Regarding Product Types

References to gas or natural gas and NGLs in this press release refer to conventional natural gas and natural gas liquids product types, respectively, as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities ("NI 51-101"), except where specifically noted otherwise.

The following is intended to provide the product type composition for each of the production figures provided herein, where not already disclosed within tables above:

  Light and Medium Crude Oil  Condensate  Natural Gas Liquids1  Conventional Natural Gas  Total (boe/d) 
Q3 2023 Average  0%  14%  8%  78%  26,834 
Q4 2023 Average  0%  20%  8%  72%  30,928 
Q1 2024 Average  0%  16%  8%  76%  29,000-31,000 
2024 Annual Average  3%  15%  8%  74%  29,000-31,000 

1) Excludes condensate volumes which have been reported separately.

Source: EvaluateEnergy® ©2024 EvaluateEnergy Ltd