CALGARY, Alberta, March 07, 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 our operating and financial results for the three and twelve-month periods ended December 31, 2023. Crew’s audited consolidated Financial Statements and Notes, Management’s Discussion and Analysis (“MD&A”) and Annual Information Form are available on Crew’s website and filed on SEDAR+ at sedarplus.ca.
HIGHLIGHTS
30,178 boe per day1 (181 mmcfe per day) average production in 2023, while Q4/23 production averaged 30,928 boe per day1 (186 mmcfe per day) and was 15% higher than the preceding quarter. Crew’s Q4/23 volumes by product averaged: 6,268 bbls per day of light crude oil and condensate, a 55% increase over 4,039 bbls per day in Q4/22133,270 mmcf per day of natural gas2,448 bbls per day of natural gas liquids5,6 (“NGLs”) 21% reduction in net debt2 to $117.4 million at year-end 2023 compared to year-end 2022, with an expanded credit facility totaling $250 million and a net debt2 to trailing last twelve-month (“LTM”) EBITDA3 ratio of 0.5 times at year-end 2023. In April 2023, Crew completed an early redemption of the $172 million principal amount of our previously outstanding senior unsecured notes, representing the full remaining balance, positioning the Company with an improved balance sheet. $246.5 million of AFF2 ($1.52 per fully diluted share3) generated in 2023, supported by an operating netback4 of $24.24 per boe. In Q4/23, AFF2 totaled $67.6 million ($0.42 per fully diluted share).$29.5 million of Free AFF4 generated in 2023, further enhancing Crew’s long-term sustainability.$119.7 million of net income ($0.74 per fully diluted share) in 2023, including $39.7 million ($0.24 per fully diluted share) in Q4/23, was enhanced by Crew’s low cost structure and risk management program. Low cash costs per boe4 averaged $9.46 in 2023, compared to $9.53 in 2022, while cash costs per boe4 in Q4/23 averaged $8.76 and were comparable to $8.67 in Q4/22. $216.0 million of net capital expenditures4 supported a safe and successful exploration and development program, drilling 22 (22.0 net) wells and completing 12 (12.0 net) wells along with completing condensate stabilization and waste heat recovery infrastructure projects.
FINANCIAL & OPERATING HIGHLIGHTS
FINANCIAL
($ thousands, except per share amounts)Three months
ended
Dec. 31, 2023Three months
ended
Dec. 31, 2022Year ended
Dec. 31, 2023Year ended
Dec. 31, 2022Petroleum and natural gas sales90,135136,948327,756598,569Cash provided by operating activities58,72162,570241,373317,337Adjusted funds flow267,64374,994246,508337,345Per share3 – basic0.440.491.602.21– diluted0.420.461.522.08Net income39,73371,383119,694264,359Per share – basic0.260.470.781.73– diluted0.240.440.741.63Property, plant and equipment expenditures53,16560,639217,028176,621Net property dispositions4–(7)(1,016)(129,787)Net capital expenditures453,16560,632216,01246,834
Capital Structure
($ thousands)As at
Dec. 31, 2023As at
Dec. 31, 2022Working capital (deficiency) surplus2 (24,873)21,844Other long-term obligations(18,223)-Bank loan(74,259)-Senior unsecured notes–(171,298)Net debt2(117,355)(149,454)Common shares outstanding (thousands)156,560154,377
OPERATIONALThree months
ended
Dec. 31, 2023Three months
ended
Dec. 31, 2022Year ended
Dec. 31, 2023Year ended
Dec. 31, 2022Daily production Light crude oil (bbl/d)81847898 Condensate (bbl/d)6,1873,9554,5484,546 Natural gas liquids (“ngl”)5,6 (bbl/d)2,4482,5652,2962,804 Conventional natural gas (mcf/d)133,270157,732139,535154,971 Total (boe/d @ 6:1)30,92832,89330,178 33,277Average realized3 Light crude oil price ($/bbl)88.90100.1088.09111.56 Condensate price ($/bbl)92.95105.3094.12115.43 Natural gas liquids price ($/bbl)27.3037.4228.9844.42 Natural gas price ($/mcf)2.486.142.846.32 Commodity price ($/boe)31.6845.2529.7649.28
Three months
ended
Dec. 31, 2023Three months
ended
Dec. 31, 2022Year ended
Dec. 31, 2023Year ended
Dec. 31, 2022Netback ($/boe) Petroleum and natural gas sales31.6845.2529.7649.28 Royalties(2.27)(6.09)(2.74)(4.90) Realized gain (loss) on derivative financial instruments3.13(5.72)4.84(7.07) Net operating costs4(3.55)(3.47)(4.17)(3.65) Net transportation costs4(3.39)(3.05)(3.45)(3.23) Operating netback425.6026.9224.2430.43 General and administrative (“G&A”)(1.15)(1.17)(1.13)(0.98) Interest expense on debt4(0.67)(0.98)(0.71)(1.67) Adjusted funds flow223.7824.7722.4027.78 1 See table in the Advisories for production breakdown by product type as defined 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 Supplementary financial 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.4 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 sedarplus.ca.5 Throughout this news release, NGLs comprise all natural gas liquids as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), other than condensate, which is disclosed separately, and natural gas means conventional natural gas by NI 51-101 product type.6 Excludes condensate volumes which have been reported separately.7 See “Advisories – Type Curves / Wells”.8 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 on a reasonable basis, reflecting management’s best estimates and judgments.
BALANCING FINANCIAL STRENGTH WITH LONG-TERM GROWTH
Crew intends to maintain our track record of successfully managing through periods of commodity weakness with a strong financial position through prudent capital allocation and a focus on long-term value creation. This includes strategically directing development investment in a manner that maintains flexibility, prioritizes higher value products and positions the Company for future success through expansion of infrastructure while reducing costs and significantly reducing emissions. This strategy was successfully demonstrated in 2023 when Crew materially increased our condensate production to offset the impact of a weaker natural gas market while reducing net debt. Continuing this strategy of balancing capital discipline with growth, the Company remains committed to our longer-range plans, supported by strategic infrastructure investments that include the expansion of our gas processing capabilities while reducing operating costs and maintaining a strong balance sheet.
In addition to having flexibility in the selection of commodity type and geologic zone to optimize value creation, the Company also has a strategic advantage geographically. Crew’s sizeable and contiguous land base is proximal to the Coastal Gas Link Pipeline, accesses multiple Canadian and US sales hubs, and stands to benefit from the potential for coastal liquids egress via the CN Rail line. Additionally, with the country’s first liquified natural gas (“LNG”) export terminal anticipated to start-up in 2025, we are positioned to capitalize on what is anticipated to be an improved natural gas supply and demand landscape to further solidify our strategic advantage.
Crew takes pride in initiatives that can both reduce our environmental footprint while also maximizing economic benefit, including our recently announced electrification projects and use of spoolable pipelines. The electrification of the West Septimus gas plant is expected to reduce emissions from the facility by approximately 82% and operating costs by over 10%. Crew gratefully acknowledges assistance from the Province of British Columbia’s CleanBC Industry Fund for their part in supporting this project.
OPERATIONS UPDATE
NE BC Montney (Greater Septimus)
Crew drilled seven (7.0 net) Montney wells during Q4/23.Over the first 60 days on production (“IP60”), 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 2,973 mcf per day of natural gas and 874 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 2023 and averaged 6,268 bbls per day in Q4/23.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.
Groundbirch
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 (“2P”) undeveloped Groundbirch type curve (the “Sproule 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 Sproule Type Curve when normalized to 3,000 meters, with estimated average raw gas Expected Ultimate Recovery (EUR) of 12 BCF per well7.
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 planned for completion in Q3/24.
RISK MANAGEMENT PROFILE
To secure a base level of AFF2 to fund planned capital projects, Crew continues to utilize hedging to limit exposure to fluctuations in commodity prices and foreign exchange rates, while allowing for participation in spot commodity prices.
As of March 7, our 2024 and 2025 hedging profile includes:
2024
2,500 GJ per day of natural gas at C$2.76 per GJ or C$3.37 per mcf using Crew’s heat factor;2,000 bbls per day of condensate at an average price of C$104.04 per bbl for 1st half 2024;1,750 bbls per day of condensate at an average price of C$104.01 per bbl for 2nd half 2024;1,000 bbls per day of WTI at C$106.09 per bbl for Q1 2024;500 bbls per day of WTI at C$112.00 per bbl for Q2 2024; and250 bbls per day of WTI at C$110.50 per bbl for 2nd half 2024.
2025
10,000 GJ per day of AECO natural gas utilizing a costless collar at $2.75 by $3.25 per GJ.
SUSTAINABILITY AND ESG INITIATIVES
Crew’s environment, social and governance (“ESG”) program remained a key focus in 2023, as we continued to invest in innovations designed to complement our operational and financial growth. We are proud to share highlights from Crew’s ESG performance in 2023:
Realized over 1.568-million-person hours of work without a single recordable injury to the end of 2023, marking a new corporate record. We are extremely proud of our Crew team for demonstrating this unprecedented level of dedication to the safety and protection of our team.Crew continued to strive for top-tier emissions intensity through the successful implementation of waste heat recovery at our Septimus gas plant, and the use of spoolable produced water transfer, with over 217,000 m3 transferred during 2023, removing over 173,000 kilometers of truck traffic and preventing approximately 531 tonnes of CO2e emissions.Directed a total of $7.9 million to abandonment and reclamation activities in 2023, reducing Crew’s idle well count by 16%.Invested 188 volunteer hours in 2023 as part of our “Crew Cares” initiative and made financial contributions into community support initiatives and not-for-profit organizations, largely geared towards fostering the health, well-being and resilience of our local communities and their economies.Published our second digital ESG report in September 2023, which outlined our achievements and progress in achieving targets and commitments, along with issuing a standalone report on the Task Force on Climate-Related Financial Disclosure (TCFD) and completing re-verification under the Equitable Origin EO100 standard for responsible energy development.
OUTLOOK
Full Year 2024 Guidance Reaffirmed – The Company’s currently planned 2024 capital program, as previously outlined in our February 8, 2024 press release, is designed to: Allocate $165 to $185 million of net capital expenditures4, including: $105 to $115 million to drilling 6.0 net wells and completing 11.0 net wells, with 10.0 net wells remaining drilled and uncompleted at year-end 2024.$60 to $70 million to infrastructure spending, including: $50 to $55 million to electrification at West Septimus.$10 to $15 million to front-end engineering and design (“FEED”) and site preparation at the future Groundbirch plant. Maintain forecasted average 2024 production of 29,000 to 31,000 boe per day1. Increase condensate production by 15%.Reduce natural gas production by 5%. Maintain a strong financial position. Net Debt to LTM EBITDA3 forecast at <1.0x. Electrify the West Septimus Plant. Increase capacity by 20 mmcf per day to total 140 mmcf per day in 2025.Reduce operating costs by more than 10%.Reduce CO2 emissions by approximately 82%, and potentially generate carbon credits under BC’s Output-Based Pricing System. Position the Company to thrive and grow in an improved natural gas price environment. 2024 Guidance and Assumptions8Net capital expenditures4 ($Millions)165–185Annual average production1 (boe/d)29,000–31,000Natural gas weighting73-75%Royalties8–10%Net operating costs4 ($ per boe)$4.50–$5.00Net transportation costs4 ($ per boe)$3.50–$4.00G&A ($ per boe)$1.00–$1.20Effective interest rate on long-term debt8.0–10.0% * No change to guidance previously released on February 8, 2024 Active Q1 Capital Program – Our previously announced Q1/24 net capital expenditure4 forecast remains unchanged and is designed to: Allocate $75 to $85 million of net capital expenditures4.Drill six (6.0 net) wells, complete five (5.0 net) wells and equip and tie-in 11 (11.0 net) Montney wells in Q1/24.Result in forecast average Q1/24 production of 29,000 to 31,000 boe per day1, which includes the impact of an anticipated 2,100 boe per day of production that is currently shut-in for offsetting completion and construction operations.
Our long-range strategic plan is designed to generate optimal value from our expansive Montney land base, which is advantageously positioned to capitalize on the anticipated improvement in the natural gas supply and demand landscape following the commissioning of LNG Canada in 2025. With its strategic location, target zones optionality, commodity diversity, multiple egress options and most importantly, large inventory of over 2,500 drilling locations, our land base serves as a cornerstone for Crew’s long-term success.
We remain committed to the pursuit of operational excellence and financial resilience to deliver long-term shareholder value while upholding our commitment to safety and environmental responsibility. Thank you to all stakeholders for their ongoing support of Crew while we continue to unlock value from our robust inventory of Montney well locations.
ABOUT CREW
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 CEO
John Leach, Executive Vice President and CFOPhone: (403) 266-2088
Email: investor@crewenergy.com
ADVISORIES
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 ability to execute on its near and longer range strategic plan (the “Strategic Plan”) and underlying strategy, associated plans, goals and targets, all as more particularly outlined and described in this press release; our 2024 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 the “Outlook” section in this press release; production estimates and targets under the 2024 Budget and balance of the longer range plan including 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 associated metrics estimates, 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; the potential for coastal liquids egress via the CN rail line; estimates of processing capacity and requirements; anticipated reductions in GHG emissions and decommissioning obligations; future liquidity and financial capacity and ability to finance our Strategic Plan; potential hedging opportunities and plans related thereto; future results from operations and targeted operating and leverage metrics; world supply and demand projections and long-term impact on pricing; future development, exploration, acquisition, disposition and infrastructures activities (including our capital investment model and associated drilling and completion plans, associated receipt of all required regulatory permits for our Strategic Plan, 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 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. 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 model, 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 will 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 all 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 Strategic Plan
Risk factors that could materially impact successful execution and actual results of the Company’s strategic 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 strategic plan;the Company’s ability to secure financing for the Groundbirch plant; andThose additional risk factors set forth in the Company’s most recently filed MD&A and Annual Information Form on SEDAR+.
Information Regarding Disclosure on Oil and Gas Operational Information
All amounts in this news release are stated in Canadian dollars unless otherwise specified. This press release contains metrics commonly used in the oil and natural gas industry. 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. See “Non-IFRS and Other Financial Measures” below for additional disclosures.
Drilling Locations
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.
Type Curves/Wells
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
a) 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. The applicable reconciliation to the most directly comparable measure, cash provided by operating activities, is contained under “free adjusted funds flow” below.
b) 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
a) Net Property Acquisitions (Dispositions)
Net property acquisitions (dispositions) equals property acquisitions less property dispositions and transaction costs on property dispositions. Crew uses net property acquisitions (dispositions) to measure its total capital investment compared to the Company’s annual capital budgeted expenditures. The most directly comparable IFRS measures to net property acquisitions (dispositions) are property acquisitions and property dispositions.
($ thousands)Three months
ended
December 31, 2023Three months
ended
September 30, 2023Three months
ended
December 31, 2022Year ended
December 31, 2023Year ended
December 31, 2022Property acquisitions–—–-Property dispositions–(20)(7)(1,016)(129,990)Transaction costs on property dispositions–—–203Net property dispositions–(20)(7)(1,016)(129,787)
b) Net Capital Expenditures
Net capital expenditures equals exploration and development expenditures less net property acquisitions (dispositions). Crew uses net capital expenditures to measure its total capital investment compared to the Company’s annual capital budgeted expenditures. The most directly comparable IFRS measure to net capital expenditures is property, plant and equipment expenditures.
($ thousands)Three months
ended
December 31, 2023Three months ended
September 30, 2023Three months ended
December 31,
2022Year ended
December 31, 2023Year ended
December 31, 2022Total property, plant and equipment expenditures53,165104,04560,639217,028176,621Net property dispositions–(20)(7)(1,016)(129,787)Net capital expenditures53,165104,02560,632216,01246,834
c) EBITDA
EBITDA is calculated as consolidated net income (loss) before interest and financing expenses, income taxes, depletion, depreciation and amortization, adjusted for certain non-cash, extraordinary and non-recurring items primarily relating to unrealized gains and losses on financial instruments and impairment losses. The Company considers this metric 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. The most directly comparable IFRS measure to EBITDA is cash provided by operating activities.
($ thousands)Three months
ended
December 31, 2023Three months ended
September 30, 2023Three months ended
December 31,
2022Year ended
December 31, 2023Year ended
December 31, 2022Adjusted funds flow67,64345,31374,994246,508337,345Financing expenses on debt1,9151,1202,9717,85320,270EBITDA69,55846,43377,965254,361357,615
d) Free Adjusted Funds Flow
Free adjusted funds flow represents adjusted funds flow less capital expenditures, excluding acquisitions and dispositions. The Company considers this metric a key measure that demonstrates the ability of the Company’s continuing operations to fund future growth through capital investment and to service and repay debt. The most directly comparable IFRS measure to free adjusted funds flow is cash provided by operating activities.
($ thousands)Three months
ended
December 31, 2023Three months
ended
September 30, 2023Three months
ended
December 31, 2022Year ended
December 31, 2023Year ended
December 31, 2022 Cash provided by operating activities58,72146,05662,570241,373317,337Change in operating non-cash working capital6,350(1,238)7,565(2,522)8,331Accretion of deferred financing costs–-(149)(199)(854)Transaction costs on property dispositions–—–203Funds from operations65,07144,81869,986238,652325,017Decommissioning obligations settled
excluding government grants2,5724955,0087,85612,328Adjusted funds flow67,64345,31374,994246,508337,345Less: property, plant and equipment
expenditures53,165104,04560,639217,028176,621Free adjusted funds flow14,478(58,732)14,35529,480160,724
e) Net Operating Costs
Net operating costs equals operating costs net of processing revenue. Management views net operating costs as an important measure to evaluate its operational performance. The most directly comparable IFRS measure for net operating costs is operating costs.
($ thousands, except per boe)Three months
ended
December 31, 2023Three months
ended
September 30, 2023Three months
ended
December 31, 2022Year ended
December 31, 2023Year ended
December 31, 2022 Operating costs10,72212,37211,11548,36447,759Processing revenue(622)(557)(616)(2,425)(3,441)Net operating costs10,10011,81510,49945,93944,318Per boe3.554.793.474.173.65
f) Net Operating Costs per boe
Net operating costs per boe equals net operating costs divided by production. Management views net operating costs per boe as an important measure to evaluate its operational performance. The calculation of Crew’s net operating costs per boe can be seen in the non-IFRS measure entitled “Net Operating Costs” above.
g) Net Transportation Costs
Net transportation costs equals transportation costs net of transportation revenue. Management views net transportation costs as an important measure to evaluate its operational performance. The most directly comparable IFRS measure for net transportation costs is transportation costs. The calculation of Crew’s net transportation costs can be seen in the section entitled “Net Transportation Costs” of this MD&A.
($ thousands, except per boe)Three months
ended
December 31, 2023Three months
ended
September 30, 2023Three months
ended
December 31, 2022Year ended
December 31, 2023Year ended
December 31, 2022 Transportation costs11,84211,05310,70145,15045,120Transportation revenue(2,185)(1,827)(1,485)(7,108)(5,892)Net transportation costs9,6579,2269,21638,04239,228Per boe3.393.743.053.453.23
h) Net Transportation Costs per boe
Net transportation costs per boe equals net transportation costs divided by production. Management views net transportation costs per boe as an important measure to evaluate its operational performance.
i) 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.
j) Cash costs per boe
Cash costs per boe is comprised of net operating, transportation, general and administrative and interest expense on debt calculated on a boe basis. Management views cash costs per boe as an important measure to evaluate its operational performance.
($/boe)Three months
ended
December 31, 2023Three months
ended
September 30, 2023Three months
ended
December 31, 2022Year ended
December 31, 2023Year ended
December 31, 2022 Net operating costs3.554.793.474.173.65Net transportation costs3.393.743.053.453.23General and administrative expenses1.151.141.171.130.98Interest expense on debt0.670.450.980.711.67Cash costs8.7610.128.679.469.53
k) Interest expense on debt per boe
Interest expense on debt per boe is comprised of the sum of interest on bank loan and other, interest on senior notes and accretion of deferred financing charges, divided by production. Management views interest expense on debt per boe as an important measure to evaluate its cost of debt financing.
($ thousands, except per boe)Three months ended
December 31, 2023Three months ended
September 30, 2023Three months ended
December 31, 2022Year ended
December 31, 2023Year ended
December 31, 2022 Interest on bank loan and other1,9151,12044,0702,321Interest on senior notes–-2,8183,58417,095Accretion of deferred financing charges–-149199854Financing expenses on debt1,9151,1202,9717,85320,270Production (boe/d)30,92826,83432,89330,17833,277Interest expense on debt per boe0.670.450.980.711.67
Supplementary Financial Measures
“Adjusted funds flow per basic share” is comprised of adjusted funds flow divided by the basic weighted average common shares.
“Adjusted funds flow per diluted share” is comprised of adjusted funds flow divided by the diluted weighted average common shares.
“Adjusted funds flow per boe” is comprised of adjusted funds flow divided by total production.
“Average realized commodity price” is comprised of commodity sales from production, as determined in accordance with IFRS, divided by the Company’s production. Average prices are before deduction of net transportation costs and do not include gains and losses on financial instruments.
“Average realized light crude oil price” is comprised of light crude oil commodity sales from production, as determined in accordance with IFRS, divided by the Company’s light crude oil production. Average prices are before deduction of net transportation costs and do not include gains and losses on financial instruments.
“Average realized ngl price” is comprised of ngl commodity sales from production, as determined in accordance with IFRS, divided by the Company’s ngl production. Average prices are before deduction of net transportation costs and do not include gains and losses on financial instruments.
“Average realized condensate price” is comprised of condensate commodity sales from production, as determined in accordance with IFRS, divided by the Company’s condensate production. Average prices are before deduction of net transportation costs and do not include gains and losses on financial instruments.
“Average realized natural gas price” is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company’s natural gas production. Average prices are before deduction of net transportation costs and do not include gains and losses on financial instruments.
“Net debt to last twelve months (“LTM”) EBITDA” is calculated as net debt at a point in time divided by EBITDA earned from that point back for the trailing twelve months.
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 & Medium Crude OilCondensateNatural Gas Liquids1Conventional
Natural GasTotal
(boe/d)Q1 2024 Average0%16%8%76%29,000–31,0002024 Annual Average3%15%8%74%29,000–31,000Notes:
1) Excludes condensate volumes which have been reported separately.