CALGARY, Alberta, Feb. 08, 2024 (GLOBE NEWSWIRE) — 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.
CREW’S 2023 RESERVES & 2024 BUDGET HIGHLIGHTS
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
2024 BUDGET DETAIL
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.
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.
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 $15 million is planned for investment into site preparation, front-end engineering and design (“FEED”) and procuring long-lead items for the planned construction of an electric drive deep-cut gas plant (the “Groundbirch Plant”) in our Groundbirch area (the “Groundbirch Project”).
Laying the Groundwork at Groundbirch
Crew has received a permit from the B.C. Energy Regulator (“BCER”) approving the construction of our planned 180 mmcf per day Groundbirch Plant as well as 60 well authorization permits, bringing our total to 85 well authorizations in the Groundbirch area.The Groundbirch Plant supports our longer-term development and expanded scale, and with permitting now in place, this longer-range strategic plan can commence with the electrification of West Septimus, which represents the first step to full Groundbirch development.In addition to surface preparations and FEED work, Crew also plans to allocate capital in 2024 and 2025 for the construction of 20 kilometers of a 12-inch and a 10-inch pipeline from West Septimus to Groundbirch, upon receipt of regulatory approval.
With ongoing supply and demand imbalances in global natural gas, the current spot and future strip prices have remained under pressure. In response, we are investing prudently to advance key milestones of the Groundbirch Project while deferring large capital outlays until they are supported by an improved natural gas pricing environment.
2024 Budget Underlying Assumptions
20249Net capital expenditures7 ($Millions)165-185Annual average production1 (boe/d)29,000-31,000Liquids Production (%)26Royalty Rate (%)8-10Net operating costs7 ($ per boe)4.50-5.00Net transportation costs7 ($ per boe)3.50-4.00General and administrative (“G&A”) ($ per boe)1.00-1.20Effective 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.
2023 RESERVES DETAIL
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.
Light & Medium Crude OilNatural Gas LiquidsConventional Natural Gas14Barrels of oil equivalent15 (mbbl)(mbbl)(mmcf)(mboe)Proved Developed Producing28915,103417,06784,903Developed Non-producing-67517,4753,587Undeveloped3,18028,089767,866159,247Total Proved3,46943,8671,202,408247,737Total Probable5,14633,1571,122,959225,462Total Proved plus Probable8,61577,0242,325,367473,199
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%Proved Developed Producing1,420,9051,023,887795,360652,861556,750Developed Non-producing68,21144,02831,52624,17119,395Undeveloped2,606,6801,390,732808,917492,904303,203Total Proved4,095,7952,458,6471,635,8041,169,936879,348Total Probable5,010,0492,393,7911,394,993914,608647,455Total Proved plus Probable9,105,8444,852,4383,030,7972,084,5441,526,803
The IC3 Average December 31, 2023, price forecast used for the purposes of preparing the Sproule Report is summarized as follows:
YearExchange RateWTI @ CushingCanadian Light SweetHenry HubNatural gas at AECO/NIT spotWestcoast Station 2 ($US/$/Cdn)(US$/bbl)(C$/bbl)(US$/mmbtu)(C$/mmbtu)(C$/mmbtu)20240.75073.6792.912.752.202.0620250.75074.9895.043.643.373.2520260.76076.1496.074.024.053.9320270.76077.6697.994.104.134.0120280.76079.2299.954.184.214.0920290.76080.80101.944.274.304.1720300.76082.42103.984.354.384.2520310.76084.06106.064.444.474.3420320.76085.74108.184.534.564.4220330.76087.46110.354.624.654.512034+(18) +2.0%/yr+2.0%/yr+2.0%/yr+2.0%/yr+2.0%/yr
The following reconciliation of Crew’s gross reserves compares changes in the Company’s independently evaluated reserves as at December 31, 2023, relative to the reserves as at December 31, 2022.
MBOEFACTORSTotal ProvedTotal ProbableTotal Proved + ProbableDecember 31, 2022210,882163,136374,018Extensions and Improved Recovery2142,35462,763105,117Infill Drilling—Technical Revisions4,868(10)4,858Discoveries—Acquisitions—Dispositions—Economic Factors648(427)221Production(11,015)-(11,015)December 31, 2023247,737225,462473,199
Corporate level technical revisions on a boe basis were 2% at the Proved level and 1% at the Proved plus Probable level. Technical revisions were primarily due to the additional facility capacity available with the development of the Groundbirch Plant, as well as operating cost and well performance changes.
Material changes in other categories were attributable to extensions, which incorporated the addition of 56 locations in the Groundbirch area to fill the new Groundbirch Plant to capacity by 2027.
Capital Program Efficiency – Including FDC
2023 PDP1P2PExploration and Development Expenditures22,23 ($ thousands)217,027217,027217,027Acquisitions/(Dispositions)22,23 ($ thousands)(1,015)(1,015)(1,015)Change in Future Development Capital4,22 ($ thousands) – Exploration and Development1,127462,771637,564- Acquisitions/Dispositions—Reserves Additions with Revisions and Economic Factors (mboe) – Exploration and Development7,33147,870110,197- Acquisitions/Dispositions—
2023 PDP1P2PFinding & Development Costs4,24,25 ($ per boe)
29.7614.207.76- with revisions and economic factorsFinding, Development & Acquisition Costs4,24,25 ($ per boe)
29.6214.187.75- with revisions and economic factorsRecycle Ratio25 (F&D)0.81.62.9Reserves Replacement367%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 www.sedar.com on or before March 31, 2024.
Crew is a growth-oriented natural gas and liquids producer, committed to pursuing sustainable per share growth through a balanced mix of financially and socially responsible exploration and development. The Company’s operations are exclusively located in northeast British Columbia and feature a vast Montney resource with a large contiguous land base in the Greater Septimus and Groundbirch areas in British Columbia, offering significant development potential over the long-term. Crew has access to diversified markets with operated infrastructure and access to multiple pipeline egress options. The Company’s common shares are listed for trading on the Toronto Stock Exchange (“TSX”) under the symbol “CR” and on the OTCQB in the US under ticker “CWEGF”.
FOR FURTHER INFORMATION, PLEASE CONTACT:
Dale Shwed, President and CEOPhone: 403-266-2088
John Leach, Executive Vice President and CFOEmail: email@example.com
Unaudited Financial Information
Certain financial and operating information included in this press release for the quarter and year ended December 31, 2023, including, without limitation, exploration and development expenditures, acquisitions / dispositions, finding and development costs, finding, development and acquisition costs, recycle ratio, reserves replacement, operating netbacks and net debt 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, 2023 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, 2023, 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, 2024. 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”, “operating netback per boe”, “exploration and development expenditures” 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. Exploration and development expenditures as used herein is equivalent to property, plant and equipment expenditures, a term with a standardized meaning prescribed under IFRS. Reserves Replacement is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Crew’s annual 2023 production averaged 30,178 boe per day1. Management uses these metrics for its own performance measurements and to provide readers with measures to compare Crew’s performance over time.
Both F&D3,4 and FD&A3,4 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.
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 ProducingTotal ProvedTotal Proved + ProbableNPV10 BT (MM$)795.41,635.83,030.8Estimated net debt December 31, 2023 (MM$)117.4117.4117.4Net Asset Value (MM$)678.01,518.42,913.4Common shares* (MM)156.6156.6156.6Estimated NAV per basic share ($)4.339.7018.61
* Issued and outstanding as at December 31, 2023, on a non-diluted basis
Reserves Reconciliation by Product Types
TOTAL PROVEDLight/Med Crude Oil (mbbls)NGL’s (mbbls)Conventional Natural Gas (mmcf)Oil Equivalent (mboe)December 31, 20222,62840,4201,007,002210,882Extensions1,5906,244207,12242,354Infill Drilling0000Improved Recovery0000Technical Revisions(721)(416)36,0334,868Discoveries0000Acquisitions0000Dispositions0000Economic Factors01183,182648Production(28)(2,498)(50,930)(11,015)December 31, 20233,46943,8671,202,409247,737
TOTAL PROBABLELight/Med Crude Oil (mbbls)NGL’s (mbbls)Conventional Natural Gas (mmcf)Oil Equivalent (mboe)December 31, 20225,53028,641773,793163,136Extensions(920)3,745359,62962,763Infill Drilling0000Improved Recovery0000Technical Revisions539855(8,422)(10)Discoveries0000Acquisitions0000Dispositions0000Economic Factors(2)(84)(2,042)(427)Production0000December 31, 20235,14633,1571,122,958225,462
TOTAL PROVED PLUS PROBABLELight/Med Crude Oil (mbbls)NGL’s (mbbls)Conventional Natural Gas (mmcf)Oil Equivalent (mboe)December 31, 20228,15869,0611,780,795374,018Extensions6709,989566,751105,117Infill Drilling0000Improved Recovery0000Technical Revisions(183)43927,6114,858Discoveries0000Acquisitions0000Dispositions0000Economic Factors(2)341,139221Production(28)(2,498)(50,930)(11,015)December 31, 20238,61577,0242,325,366473,199
Forward-Looking Information and Statements
This news release contains certain forward–looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends”, “forecast”, targets, goals and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the potential recognition of significant additional reserves under the heading 2023 Reserves Detail; the volumes and estimated value of Crew’s oil and gas reserves, the future net value of Crew’s reserves, the future development capital and costs, the future ARC, the life of Crew’s reserves, the estimated volumes, and production mix of Crew’s oil and gas production; the ability to execute on its four-year strategic plan and underlying strategy, associated plans, goals and targets, all as more particularly outlined and described in this press release; our annual capital budget range (the “2024 Budget”), associated drilling, completion and infrastructure plans, the anticipated timing thereof, and all associated strategies, initiatives, goals and targets, along with all forecasts, guidance and underlying assumptions and sensitivities related to the 2024 Budget as outlined in this press release; production estimates and targets under the 2024 Budget and balance of the longer range plan including, without limitation, Crew’s goal to double annual average production volumes to over 60,000 boe per day through the coming years; infrastructure plans and anticipated benefits associated therewith as outlined in this press release including, without limitation, the planned expansion and electrification of the West Septimus gas plant and anticipated economic and other benefits thereof, expectations in regards to the extent of provincial and federal government grants, credits and financial incentives related thereto, the planned construction of the Groundbirch Plant and anticipated benefits thereof, anticipated timing and assumed receipt of all regulatory approvals required in connection with our infrastructure plans and our ability to secure financing for these plans as may be required, from time to time, and the potential costs associated therewith; commodity price expectations and assumptions; Crew’s commodity risk management programs and future hedging plans; marketing and transportation and processing plans and requirements; estimates of processing capacity and requirements; anticipated reductions in GHG emissions and decommissioning obligations; future liquidity and financial capacity and ability to finance our longer range strategic plan; potential hedging opportunities and plans related thereto; future results from operations and operating and leverage metrics; world supply and demand projections and long-term impact on pricing; future development, exploration, acquisition, disposition and infrastructure activities, development timing and cost estimates; the potential to serve a Canadian LNG market including the anticipated start-up of LNG Canada in 2025 and the anticipated benefits thereof to the Corporation both strategically and economically; the number of estimated potential identified drilling locations outlined in this press release; the potential of our Groundbirch area to be a core area of future development and the anticipated commerciality of up to four potential prospective zones to be drilled; the successful implementation of our ESG initiatives, and significant emissions intensity improvements going forward; the amount and timing of capital projects; and anticipated improvement in our long-term sustainability and the expected positive attributes discussed herein attributable to our long range strategic plan.
The internal projections, expectations, or beliefs underlying our Board approved 2024 Budget and associated guidance, as well as management’s strategy, and associated plans, goals and targets in respect of the balance of its strategic plan, are subject to change in light of, without limitation, the continuing impact of the Russia/Ukraine conflict, war in the Middle East and any related actions taken by businesses and governments, ongoing results, prevailing economic circumstances, volatile commodity prices, resulting changes in our underlying assumptions, goals and targets provided herein and changes in industry conditions and regulations. Crew’s financial outlook and guidance provides shareholders with relevant information on management’s expectations for results of operations, excluding any potential acquisitions or dispositions, for such time periods based upon the key assumptions outlined herein. In this press release reference is made to the Company’s longer range 2025 and beyond internal plan and associated economic model. Such information reflects internal goals and targets used by management for the purposes of making capital investment decisions and for internal long-range planning and future budget preparation. Readers are cautioned that events or circumstances and updates to underlying assumptions could cause capital plans and associated results to differ materially from those predicted and Crew’s guidance for 2024, and more particularly its internal plan, goals and targets for 2025 and beyond which are not based upon Board approved budget(s) at this time, may not be appropriate for other purposes. Accordingly, undue reliance should not be placed on same.
In addition, forward-looking statements or information are based on a number of material factors, expectations or assumptions of Crew which have been used to develop such statements and information, but which may prove to be incorrect. Although Crew believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Crew can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: that Crew will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities consistent with past operations; the quality of the reservoirs in which Crew operates and continued performance from existing wells; the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Crew’s reserve volumes; certain commodity price and other cost assumptions; continued availability of debt and equity financing and cash flow to fund Crew’s current and future plans and expenditures; the impact of increasing competition; the general stability of the economic and political environment in which Crew operates; that future business, regulatory and industry conditions will be within the parameters expected by Crew; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of Crew to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Crew has an interest in to operate the field in a safe, efficient and effective manner; the ability of Crew to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Crew to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes, environmental and indigenous matters in the jurisdictions in which Crew operates; that regulatory authorities in British Columbia continue granting approvals for oil and gas activities on time frames, and on terms and conditions, consistent with past practices; and the ability of Crew to successfully market its oil and natural gas products.
The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: the continuing and uncertain impact of the Russia / Ukraine conflict and war in the Middle East; changes in commodity prices; changes in the demand for or supply of Crew’s products, the early stage of development of some of the evaluated areas and zones and the potential for variation in the quality of the Montney formation; interruptions, unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates; climate change regulations, or other regulatory matters; changes in development plans of Crew or by third party operators of Crew’s properties, increased debt levels or debt service requirements; inaccurate estimation of Crew’s oil and gas reserve volumes and identified drilling inventory; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in Crew’s public disclosure documents (including, without limitation, those risks identified in this news release and Crew’s MD&A and Annual Information Form).
This press release contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about Crew’s prospective capital expenditures and associated guidance, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. The actual results of operations of Crew and the resulting financial results will likely vary from the amounts set forth in this press release and such variation may be material. Crew and its management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments. However, because this information is subjective and subject to numerous risks, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, Crew undertakes no obligation to update such FOFI. FOFI contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about Crew’s anticipated future business operations. Readers are cautioned that the FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein.
The forward-looking information and statements contained in this news release speak only as of the date of this news release, and Crew does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
Risk Factors to the Company’s Four-Year Plan
Risk factors that could materially impact successful execution and actual results of the Four-Year Plan include:
volatility of petroleum and natural gas prices and inherent difficulty in the accuracy of predictions related thereto;changes in Federal and Provincial regulations;execution of construction timelines from BC Hydro to support the electrification of the West Septimus and Groundbirch plants;receipt of high-value regulatory permits required to launch development under the Four-Year Plan;the Company’s ability to secure financing for the Groundbirch plant; andThose additional risk factors set forth in the Company’s MD&A and most recent Annual Information Form filed on SEDAR.
This press release discloses internally identified “potential drilling locations” which are comprised of: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Company’s independent reserve evaluator’s report effective December 31, 2023 (the “Sproule Report”) and account for drilling inventory that have associated proved and/or probable reserves assigned by Sproule. Unbooked locations are internally identified potential drilling opportunities based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have reserves or resources attributed to them and are not estimates of drilling locations which have been evaluated by a qualified reserves evaluator performed in accordance with the COGE Handbook. There is no certainty that the Company will drill any of these potential drilling opportunities and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors.
The following table provides a detailed breakdown of the identified gross potential drilling locations presented herein:
Total Drilling LocationsProved LocationsProbable LocationsUnbooked LocationsMontney Total Drilling Locations2,5371321062,299Groundbirch Locations1,71737661,614West Septimus Locations4835928396Septimus Locations191369146Tower Locations146-3143
Test Results and Initial Production Rates
A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production (“IP”) rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery.
The Groundbirch type curves referenced herein reflect the average per well proved plus probable undeveloped raw gas assignments (EUR) for Crew’s area of operations, as derived from the Company’s year-end independent reserve evaluations prepared by Sproule in accordance with the definitions and standards contained in the COGE Handbook. Unless otherwise stated, the type wells are based upon all Crew producing wells in the area as well as non-Crew wells determined by the independent evaluator to be analogous for purposes of the reserve assignments. There is no guarantee that Crew will achieve the estimated or similar results derived therefrom and therefore undue reliance should not be placed on them. Such information has been prepared by Management, where noted, for purposes of making capital investment decisions and for internal budget preparation only.
BOE and Mcfe Conversions
Measurements expressed in barrel of oil equivalents, BOEs or Mcfe may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl and an Mcfe conversion ratio of 1 bbl:6 Mcf are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of 6:1, utilizing the 6:1 conversion ratio may be misleading as an indication of value.
Non-IFRS and Other Financial Measures
Throughout this press release and other materials disclosed by the Company, Crew uses certain measures to analyze financial performance, financial position and cash flow. These non-IFRS and other specified financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-IFRS and other specified financial measures should not be considered alternatives to, or more meaningful than, financial measures that are determined in accordance with IFRS as indicators of Crew’s performance. Management believes that the presentation of these non-IFRS and other specified financial measures provides useful information to shareholders and investors in understanding and evaluating the Company’s ongoing operating performance, and the measures provide increased transparency and the ability to better analyze Crew’s business performance against prior periods on a comparable basis.
Capital Management Measures
Funds from Operations and Adjusted Funds Flow (“AFF”)
Funds from operations represents cash provided by operating activities before changes in operating non-cash working capital, accretion of deferred financing costs and transaction costs on property dispositions. Adjusted funds flow represents funds from operations before decommissioning obligations settled (recovered). The Company considers these metrics as key measures 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. Management believes that such measures provide an insightful assessment of the Company’s operations on a continuing basis by eliminating certain non-cash charges, actual settlements of decommissioning obligations and transaction costs on property dispositions, the timing of which is discretionary. Funds from operations and adjusted funds flow should not be considered as an alternative to or more meaningful than cash provided by operating activities as determined in accordance with IFRS as an indicator of the Company’s performance. Crew’s determination of funds from operations and adjusted funds flow may not be comparable to that reported by other companies. Crew also presents adjusted funds flow per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of income per share.
Net Debt and Working Capital Surplus (Deficiency)
Crew closely monitors its capital structure with a goal of maintaining a strong balance sheet to fund the future growth of the Company. The Company monitors net debt as part of its capital structure. The Company uses net debt (bank debt plus working capital deficiency or surplus, excluding the current portion of the fair value of financial instruments) as an alternative measure of outstanding debt. Management considers net debt and working capital deficiency (surplus) an important measure to assist in assessing the liquidity of the Company.
Non-IFRS Financial Measures and Ratios
Operating Netback per boe
Operating netback per boe equals petroleum and natural gas sales including realized gains and losses on commodity related derivative financial instruments, marketing income, less royalties, net operating costs and transportation costs calculated on a boe basis. Management considers operating netback per boe an important measure to evaluate its operational performance as it demonstrates its field level profitability relative to current commodity prices.
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 OilCondensateNatural Gas Liquids1Conventional Natural GasTotal (boe/d)Q3 2023 Average0%14%8%78%26,834Q4 2023 Average0%20%8%72%30,928Q1 2024 Average 0%16%8%76%29,000-31,0002024 Annual Average 3%15%8%74%29,000-31,000
1) Excludes condensate volumes which have been reported separately.
1 See table in the Advisories for production breakdown by product type as detailed in NI 51-101.
2 Capital management measure that does not have any standardized meaning as prescribed by International Financial Reporting Standards, and therefore, may not be comparable with the calculations of similar measures for other entities. See “Advisories – Non-IFRS and Other Financial Measures” contained within this press release.
3 “Finding, Development and Acquisitions costs” or “FD&A costs”, “Finding and Development costs” or “F&D costs”, “Reserves Replacement”, “Operating Netback” 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 2023 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 $190 million (undiscounted) in the 1P case and $220 million (undiscounted) in the 2P case of maintenance capital that was reclassified as a capital expense in the December 31, 2021, Sproule Report and maintained the same classification in the December 31, 2023 Sproule Report.
5 Calculated based on the Sproule Report before-tax estimated net present value of future net revenue associated with the reserves and discounted at 10% (“NPV10 BT”), debt adjusted per share. See “Advisories – Net Asset Value” contained within this press release for details of the NAV calculations used in this press release.
6 Estimated operating netback per boe in Q4 2023, used in the above calculations, averaged $22.47 per boe (unaudited). See ‘Advisories – Unaudited Financial Information’ and ‘Advisories – Information Regarding Disclosure on Oil and Gas Reserves and Operational Information’.
7 Non-IFRS financial measure or ratio that does not have any standardized meaning as prescribed by International Financial Reporting Standards, and therefore, may not be comparable with calculations of similar measures or ratios for other entities. See “Advisories – Non-IFRS and Other Financial Measures” contained within this press release and in our most recently filed MD&A, available on SEDAR at www.sedar.com.
8 Estimated inlet capacity increase reflects internally generated forecasts and is dependent on operating conditions.
9 The actual results of operations of Crew and the resulting financial results will likely vary from the estimates and material underlying assumptions set forth in this guidance by the Company and such variation may be material. The guidance and material underlying assumptions have been prepared based on information currently available on a reasonable basis, reflecting management’s best estimates and judgments.
10 See “Drilling Locations” in the Advisories.
11 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.
12 Based on the IC3 Average December 31, 2023, escalated price forecast as used in the Sproule Report.
13 Columns may not add due to rounding.
14 Reflects 100% Conventional Natural Gas by product type.
15 Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.
16 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.
17 The after-tax net present values of future net revenue attributed to Crew’s reserves will be included in the Company’s 2023 AIF to be filed on or before March 31, 2024.
18 Escalated at 2.0% per year starting in 2034 with the exception of foreign exchange which remains constant.
19 Product sale prices will reflect these reference prices with further adjustments for quality and transportation to point of sale.
20 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
21 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”.
22 The aggregate of the exploration and development expenditures 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.
23 All 2023 financial amounts are unaudited. See “Advisories – Unaudited Financial Information”.
24 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.
25 Recycle ratio is defined as operating netback per boe divided by F&D costs on a per boe basis. Operating netback per boe 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 per boe in fourth quarter 2023, used in the above calculations, averaged $22.47 per boe (unaudited). This amount is an estimate and is subject to audit verification. See ‘Advisories – Unaudited Financial Information’ and ‘Advisories – Information Regarding Disclosure on Oil and Gas Reserves and Operational Information’.