Crew Energy announces Q2 2023 results highlighted by a 42% reduction in net debt over Q1/23 and an adjusted funds flow margin of 89% – Energy News for the Canadian Oil & Gas Industry | EnergyNow.ca

CALGARY, Alberta, Aug. 09, 2023 (GLOBE NEWSWIRE) — Crew Energy Inc. (TSX: CR; OTCQB: CWEGF) (“Crew” or the “Company”), a growth-oriented, liquids rich natural gas 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 six month periods ended June 30, 2023. Crew’s Financial Statements and Notes, as well as Management’s Discussion and Analysis (“MD&A”) are available on our website and filed on SEDAR at www.sedar.com.

HIGHLIGHTS

• 30,046 boe per day¹ (180 mmcfe per day) average production in Q2/23 was at the high end of Crew’s previous quarterly guidance of 28,000 to 30,000 boe per day as we realized continued strong performance from wells drilled and completed at the end of 2022 and early 2023, while first half 2023 (“1H/23”) production averaged 31,496 boe per day¹. Relative to the same periods in 2022, lower volumes reflect shut-in production due to weaker natural gas prices, as well as limited completion activity in the first half of 2023 while the Company focused on debt reduction.
  • 143,752 mmcf per day of natural gas production in Q2/23 represented 80% of total production and 47% of sales, with 149,738 mmcf per day in 1H/23 representing 79% of total production and 50% of sales.
  • 3,745 bbls per day of light crude oil and condensate production in Q2/23 represented 12% of total production and 45% of sales, with 4,192 bbls per day in 1H/23 representing 13% of production and 43% of sales.
  • 2,342 bbls per day of natural gas liquids^5,6 (“ngls”) production in Q2/23 represented 8% of total production and 7% of sales, with 2,348 bbls per day in 1H/23 representing 7% of production and 8% of sales.
• $59.0 million of Adjusted Funds Flow (“AFF”)² ($0.36 per fully diluted share³) was generated in Q2/23, and $133.6 million ($0.83 per fully diluted share³) in 1H/23, with AFF benefiting from the monetization of approximately $11.8 million of natural gas hedge contracts in the quarter.
  • AFF² as a percentage of petroleum and natural gas sales (“AFF Margin”)³ totaled 89% in Q2/23 and was 80% in 1H/23.
  • Operating netbacks⁴ averaged $23.43 per boe in Q2/23 and $25.40 per boe in 1H/23, assisted by realized hedging gains of $8.87 per boe and $6.71 per boe in Q2/23 and 1H/23, respectively.
• $36.7 million of net capital expenditures⁴ invested in Q2/23, including the drilling of six ultra-condensate rich (“UCR”) wells at Greater Septimus. Drier surface conditions in the area enabled the drilling and construction of surface leases earlier than anticipated during the quarter, allowing for investments originally planned for Q3/23 to be accelerated into Q2/23.
• 42% reduction in net debt² compared to Q1/23 to total $60.7 million at quarter-end, supported by the generation of $21.4 million of Free AFF⁴ in Q2/23, and further reduced by $29 million of other income arising from a non-refundable, third-party payment.
  • Reduced net debt² to trailing last twelve-month (“LTM”) EBITDA³ by 50% to 0.2 times at June 30, 2023, from 0.4 times at year-end 2022.
  • $28.9 million drawn on our $200 million credit facility that was extended to May 2025 during the quarter.
• Redeemed the remaining $172 million principal amount of our 2024 Senior Unsecured Notes at par on April 28, 2023, using cash on hand and drawings on the bank line, simultaneously extending our $200 million credit facility maturity to May 2025 with no financial maintenance covenants and no minimum liquidity requirements.
• $33.7 million in positive after-tax net income ($0.21 per fully diluted share) was recorded during the quarter, and $75.1 million ($0.46 per fully diluted share) in the first half of the year, with both periods reflecting lower commodity prices relative to the same periods in 2022.
• Cash costs per boe⁴ of $9.68 in Q2/23 were in-line with $9.63 per boe in Q2/22.

FINANCIAL & OPERATING HIGHLIGHTS

FINANCIAL ($ thousands, except per share amounts)	Three months ended June 30, 2023		Three months ended June 30, 2022	Six months ended June 30, 2023		Six months ended June 30, 2022
Petroleum and natural gas sales	66,623		198,329	167,304		328,671
Cash provided by operating activities	69,952		117,363	136,596		172,445
Adjusted funds flow2	59,035		115,274	133,552		192,934
Per share3 – basic	0.38		0.76	0.87		1.27
– diluted	0.36		0.71	0.83		1.19
Net income	33,729		88,695	75,083		87,318
Per share – basic	0.22		0.58	0.49		0.57
– diluted	0.21		0.55	0.46		0.54
Property, plant and equipment expenditures	37,657		7,061	59,818		62,422
Net property dispositions4	(966	)	–	(966	)	–
Net capital expenditures4	36,661		7,061	58,822		62,422

Capital Structure ($ thousands)	As at Jun. 30, 2023		As at Dec. 31, 2022
Working capital (deficiency) surplus2	(13,563	)	21,844
Other long-term obligations	(18,223	)	–
Bank loan	(28,902	)	–
Senior unsecured notes	–		(171,298	)
Net debt2	(60,688	)	(149,454	)
Common shares outstanding (thousands)	154,191		154,377

OPERATIONAL			Three months ended June 30, 2023	Three months ended June 30, 2022	Six months ended June 30, 2023	Six months ended June 30, 2022
Daily production
Light crude oil (bbl/d)7			74	108	73	112
Condensate (bbl/d)			3,671	5,570	4,119	4,752
Natural gas liquids5,6 (bbl/d)			2,342	3,108	2,348	2,982
Conventional natural gas (mcf/d)			143,752	157,547	149,738	158,273
Total (boe/d @ 6:1)			30,046	35,044	31,496	34,225
Average realized3
Light crude oil price ($/bbl)			83.30	130.66	83.91	118.68
Condensate price ($/bbl)			88.72	130.07	94.02	124.40
Natural gas liquids price ($/bbl)			23.20	49.09	30.98	48.91
Natural gas price ($/mcf)			2.41	8.17	3.06	6.73
Commodity price ($/boe)			24.37	62.16	29.35	53.06

	Three months ended June 30, 2023		Three months ended June 30, 2022		Six months ended June 30, 2023		Six months ended June 30, 2022
Netback ($/boe)
Petroleum and natural gas sales	24.37		62.16		29.35		53.06
Royalties	(1.95	)	(3.98	)	(3.09	)	(3.40	)
Realized gain (loss) on derivative financial instruments	8.87		(12.41	)	6.71		(8.89	)
Net operating costs4	(4.43	)	(3.52	)	(4.21	)	(3.51	)
Net transportation costs4	(3.43	)	(3.33	)	(3.36	)	(3.23	)
Operating netback4	23.43		38.92		25.40		34.03
General and administrative (“G&A”)	(1.09	)	(0.83	)	(1.12	)	(0.89	)
Interest expenses on debt4	(0.73	)	(1.95	)	(0.85	)	(1.99	)
Adjusted funds flow2	21.61		36.14		23.43		31.15

^{____________________________
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 www.sedar.com.

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 Throughout this news release, light crude oil refers to light and medium crude oil product type as defined by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).

BALANCE SHEET STRENGTH REFLECTS SUCCESS OF DELEVERAGING PLAN

• In keeping with our 2023 plans, Crew remained committed to deleveraging and has successfully reduced net debt² from $406 million at year end 2021 to $60.7 million at June 30, 2023, a decline of 85% over that period with no shareholder dilution. Compared to the previous quarter, net debt² in Q2/23 was reduced by $44.6 million despite a more challenging environment for commodity prices.
• To capitalize on an improved outlook for North American natural gas fundamentals and expanding market dynamics through the second half of 2023, we strategically elected to monetize a portion of our hedge book in Q2/23, generating $11.8 million. The cash received from this hedge monetization, coupled with $29 million realized in other income, enabled Crew to exceed our Q2/23 leverage target and meaningfully enhance our financial flexibility.
• A key tenet of Crew’s four-year plan to increase productive capacity to over 60,000 boe per day is the expansion of our gas processing infrastructure, including the construction of an electric drive 180 mmcf per day deep-cut gas plant in our Groundbirch area, ideally situated to supply natural gas to Canada’s future liquified natural gas (“LNG”) export facilities. Progressing our Groundbirch area development plan will depend on receiving all necessary permits, gaining visibility into a supportive commodity price environment, and being able to secure the requisite financing while maintaining conservative debt leverage metrics. With ongoing supply and demand imbalances in global natural gas, the current spot and future strip prices have remained under pressure. Considering this, Crew intends to continue monitoring price signals that may support additional hedging opportunities and is actively exploring a variety of project financing options while we await regulatory approvals.
• Our diverse land base affords the opportunity to pursue light oil and condensate during periods of reduced natural gas pricing. As a result, we plan to increase our light oil and condensate production to over 7,000 bbls per day by year-end 2023 from Q2/23 volumes of 3,745 bbls per day, which is 1,000 bbls per day, or 17%, over previous guidance. The financial leverage of this strategy is demonstrated in our Q2/23 results, with light oil and condensate having constituted 12% of total production while contributing 45% of sales.

OPERATIONS UPDATE & AREA OVERVIEW

NE BC Montney (Greater Septimus)

• Crew’s second quarter capital program concentrated on drilling five (5.0 net) wells at our 4-32 pad, all of which are scheduled to be completed in Q3/23, along with construction and drilling of one extended reach horizontal (“ERH”) well on the 2-24 pad.
• The Company acquired additional spoolable surface pipeline in Q2/23 to support water transfer during completion of the 4-32 pad, building on the success of our past use of the equipment and facilitating the safe and environmentally responsible transportation of produced water with reduced emissions.
• Average production from the five (5.0 net) ERH UCR wells that that were completed on the 11-27 pad have produced at wellhead rates of 1,401 mcf per day of natural gas and 437 bbls per day of condensate over the first 150 days of production (IP150).
• Advancement of key projects at the Septimus Gas Plant continued during Q2/23, including the waste heat recovery and condensate stabilization projects, the latter of which is expected to increase the plant’s condensate capacity to 5,000 bbls per day and facilitate expanded development of our UCR area. These projects are anticipated to be completed in Q3/23.
• Construction was initiated on our North Septimus 6-18 UCR pad. These five (5.0 net) wells are planned to be drilled in late summer of 2023 following the drilling of the seven (7.0 net) wells on the 2-24 pad.

Groundbirch

• The original three (3.0 net) wells on the 4-17 pad have produced an average of 3.24 bcf of natural gas over 510 days, exceeding our independent reserve evaluator’s year-end 2022 proved plus probable type curve by approximately 34% to date.
• The five (5.0 net) ERH wells in the second phase of development at Crew’s 4-17 pad continue to exceed internal type curve estimates, with an average per well raw gas production rate over 300 days (“IP300”) of 5,670 mcf per day. We recently received regulatory approval to drill six (6.0 net) additional wells at the 4-17 pad and expand the lease to accommodate the additional required facilities.

• Engineering design is continuing for Crew’s proposed Groundbirch plant, which will expand our gas processing infrastructure and support future growth (the “Groundbirch Plant”).
• The Upper Montney at Groundbirch is approximately 470 feet in thickness and has four prospective zones, all of which were tested through our 4-17 exploration and development program in 2021 and 2022, with each zone having generated promising initial commercial development rates. Drilling and testing results at Groundbirch have demonstrated the strength of our asset base, positioning the Company with decades of potential development runway.
• Crew currently holds 25 well permits in the Groundbirch area, with an additional 60 well permit applications submitted to date which are pending approval.

Other NE BC Montney

• The Company currently has six drilled ERH wells on the 15-28 pad at Tower, which are planned to be completed in Q1/24. The wells were drilled to target light oil in the upper Montney “B” and “C” zones and feature lateral lengths of over 4,000 meters.

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. The strategic decision to monetize an average of 25,700 GJ per day of hedges for the balance of 2023 contributed an incremental $11.8 million of AFF² in Q2/23. The monetization was completed at an average market price of $2.02 per GJ, realizing a gain of $2.44 per GJ compared to our average hedge price, taking advantage of a low point in the natural gas shoulder season. The current market for AECO natural gas is averaging approximately $2.90 per GJ for the remainder of the year.

As of August 9, 2023, our hedging profile includes:

• Approximately 48,000 GJ per day at C$4.29 per GJ for the remainder of 2023, or C$5.23 per mcf using Crew’s higher heat content factor;
• 1,250 bbls per day of Edmonton condensate at an average price of C$100.25 per bbl for the remainder of 2023; and
• 500 bbls per day of WTI at an average price of C$100.18 per bbl for Q4/23 and Q1/24.

LAUNCH OF 2022 SUSTAINABILITY & TCFD REPORTS

Our commitment to environmental, social and governance (“ESG”) initiatives remained a key focus in Q2/23 as we continue to invest in developing sustainable solutions to complement our operational and financial growth. We are proud to confirm that we have updated our online, interactive ESG report with 2022 data, and produced an inaugural, standalone report aligned with the Task Force on Climate-related Financial Disclosures (“TCFD”) framework. These reports highlight our performance compared with goals and targets, along with current and planned sustainability initiatives and are available www.esg.crewenergy.com.

Continuing this commitment to responsible and sustainable development, we are pleased to highlight Crew’s ESG progress and achievements during Q2/23:

• Further demonstrated our unwavering commitment to safety with no recordable or lost time injuries in the period;
• Directed a total of $1.28 million to abandonment and reclamation activities;
• Purchased an additional six kilometres of spoolable pipeline which increases in-field water handling efficiencies while also reducing GHG emissions due to the elimination of water truck hauling; and
• Invested 53 volunteer hours 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.

OUTLOOK

• 2023 Guidance – We have benefited from improved capital efficiencies in our operations through the effective execution of our plan to date, and are maintaining our annual capital investment guidance of $190 to $210 million. As a result of improved efficiencies, we now plan to have an additional two (2.0 net) drilled wells, one (1.0 net) completed well and one (1.0 net) drilled and uncompleted well by year end 2023. This has allowed us to refine our 2023 exit rate guidance and add condensate production. Crew’s full year 2023 net capital investment program now plans to:
  • Maintain 2023 average production at 30,000 to 32,000 boe per day¹ targeting a tightened exit rate of 33,000 to 34,000 boe per day¹;
  • Increase our light oil and condensate production to over 7,000 bbls per day by year end 2023 from Q2/23 volumes of 3,745 bbls per day, which is 1,000 bbls per day, or 17%, higher than previous guidance;
  • Drill 17 (17.0 net) UCR Montney wells;
  • Complete, equip and tie-in 13 (13.0 net) wells; and
  • Hold an inventory of 11 (11.0 net) drilled and uncompleted UCR wells at year end 2023.

• Q3 Outlook – Net capital expenditures⁴ in Q3/23 are forecast at $115 to $125 million with average production of 26,000 to 28,000 boe per day¹, reflecting offsetting completion activities, natural production declines, and planned pipeline and processing maintenance by our third party pipeline and midstream partners. Our Q3/23 capital program includes plans to:
  • Complete the five (5.0 net) well 4-32 pad;
  • Complete the last remaining well on the 11-27 UCR pad;
  • Finish drilling and begin completions on the seven (7.0 net) well 2-24 UCR pad;
  • Begin the drilling of a five (5.0 net) well UCR pad at 6-18;
  • Drill and complete a water disposal well; and
  • Undertake a shutdown at Septimus in Q3 that will enable the tie-in of installed condensate stabilization and waste heat recovery facilities.

With dry weather in NE BC, the B.C. Government has temporarily restricted the withdrawal of water from a number of rivers. Crew uses produced water wherever possible in our completion operations. However, we periodically withdraw water from one of the affected rivers, which may result in the Company altering the timing of completions.

• 2024 Preliminary Outlook – We will continue to advance permitting and engineering on the Groundbirch expansion project and await a supportive forward natural gas price before advancing project financing options. 2024 capital expenditures are expected to focus on developing our liquids rich natural gas at Septimus and West Septimus along with progressing the electrification and expansion of our gas processing facilities.

The following table sets forth Crew’s reaffirmed guidance and underlying material assumptions:

		2023 Guidance and Assumptions8
Net capital expenditures4 ($Millions)		190-210
Annual average production1 (boe/d)		30,000–32,000
Adjusted funds flow2 ($Millions)		240-260
Free adjusted funds flow4 ($Millions)		30-70
EBITDA4 ($Millions)		250-270
Oil price (WTI)($US per bbl)		$75.00
Natural gas price (NYMEX) ($US per mmbtu)		$3.20
Natural gas price (AECO 5A) ($C per mcf)		$2.85
Natural gas price (Crew est. wellhead) ($C per mcf)		$3.30
Foreign exchange ($US/$CAD)		$0.74
Royalties		9–11%
Net operating costs4 ($ per boe)		$4.50–$5.00
Net transportation costs4 ($ per boe)		$3.50–$4.00
G&A ($ per boe)		$1.00–$1.20
Effective interest rate on long-term debt		6.5–7.5%

2023 Sensitivities (Q3 to Q4)	AFF ($MM)		AFF/Share		FD AFF/Share
100 bbl per day Condensate	$	3.0	$	0.02	$	0.02
C$1.00 per bbl WTI	$	1.2	$	0.01	$	0.01
US $0.10 NYMEX (per mmbtu)	$	5.1	$	0.03	$	0.03
1 mmcf per day natural gas	$	1.1	$	0.01	$	0.01
$0.10 AECO 5A (per GJ)	$	2.9	$	0.02	$	0.02
$0.01 FX CAD/US	$	3.7	$	0.02	$	0.02

Crew’s world-class Montney asset base, operational excellence and financial strength positions the Company to succeed across dynamic market conditions by providing optionality to adjust our capital program to optimize our production mix, ensuring long term sustainability. Our dedicated team is excited to continue delivering long-term shareholder value through innovation and adaptability, supported by a robust risk management program and proven strategy which enables us to achieve our goals while maintaining a safe and responsible operating culture. We express our gratitude to our stakeholders for their commitment and ongoing support of Crew in this dynamic environment.

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” 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 Four-Year Plan and underlying strategy, plans, goals and targets, all as more particularly outlined and described in this press release; our 2023 annual capital budget range (the “2023 Budget”), associated drilling and completion plans, the anticipated timing thereof, and all associated near term initiatives, goals and targets, along with all guidance and underlying assumptions related to the 2023 Budget as outlined in the “Outlook” section in this press release; preliminary 2024 plans as outlined in the “Outlook” section in this press release; production and type-curve estimates and targets under the 2023 Budget and balance of the Four-Year Plan; infrastructure plans and anticipated benefits outlined in this press release including construction of the Groundbirch plant and anticipated benefits thereof; completion of the Company’s waste heat recovery and condensate stabilization projects at its Septimus Gas Plant and anticipated benefits thereof; the planned conversion of our West Septimus gas processing facility to electric drive and anticipated timing and benefits thereof; anticipated timing, costs and assumed receipt of all regulatory approvals required in connection therewith; our ability to secure financing for the Groundbirch plant and timing thereof; continued improvement in debt and leverage metrics; 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 Four-Year Plan; future results from operations and operating and leverage metrics; targeted debt levels and leverage metrics over the course of the Four-Year Plan; world supply and demand projections and long-term impact on pricing; future development, exploration, acquisition, disposition and infrastructure activities (including our capital investment model through 2026 and associated drilling and completion plans, associated receipt of all required regulatory permits for our Four-Year Plan, development timing and cost estimates); the potential to serve a Canadian LNG market; the potential of our Groundbirch area to be a core area of future development for potentially decades, and the anticipated commerciality of up to four potential prospective zones to be drilled; the successful implementation of our ESG initiatives as set forth herein and in our updated ESG Report; 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 Four-Year Plan.

The internal projections, expectations, or beliefs underlying our Board approved 2023 Budget and associated guidance, as well as management’s preliminary strategy, and associated plans, goals and targets in respect of the balance of its Four-Year Plan, are subject to change in light of, without limitation, the Russia/Ukraine conflict 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 2024 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 2023, and more particularly its internal plan, goals and targets for 2024 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 several 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 pandemics and the Russia / Ukraine conflict; 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; 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, 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 Groundbirch plant;
• 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 sourced from AFF, bank or other Debt instruments, asset sales, equity issuance, infrastructure financing or some combination thereof; and
• Those additional risk factors set forth in the Company’s MD&A and most recent Annual Information Form filed 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.

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 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.

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

Funds from operations represents cash provided by operating activities before changes in operating non-cash working capital, accretion of deferred financing charges 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.

b) Net Capital Expenditures

Net capital expenditures equals property, plant and equipment 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 June 30, 2023		Three months ended March 31, 2023	Three months ended June 30, 2022	Six months ended June 30, 2023		Six months ended June 30, 2022
Property, plant and equipment expenditures	37,657		22,161	7,061	59,818		62,422
Less: Net property dispositions	(996	)	–	–	(996	)	–
Net capital expenditures	36,661		22,161	7,061	58,822		62,422

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 June 30, 2023	Three months ended March 31, 2023	Three months ended June 30, 2022	Six months ended June 30, 2023	Six months ended June 30, 2022
Adjusted funds flow	59,035	74,517	115,274	133,552	192,934
Financing expenses on debt	2,003	2,815	6,230	4,818	12,324
EBITDA	61,038	77,332	121,504	138,370	205,258

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 June 30, 2023		Three months ended March 31, 2023		Three months ended June 30, 2022		Six months ended June 30, 2023		Six months ended June 30, 2022
Cash provided by operating activities	69,952		66,644		117,363		136,596		172,445
Change in operating non-cash working capital	(12,154	)	4,520		(2,666	)	(7,634	)	17,009
Accretion of deferred financing costs	(49	)	(150	)	(245	)	(199	)	(491	)
Funds from operations	57,749		71,014		114,452		128,763		188,963
Decommissioning obligations settled excluding government grants	1,286		3,503		822		4,789		3,971
Adjusted funds flow	59,035		74,517		115,274		133,552		192,934
Less: property, plant and equipment expenditures	37,657		22,161		7,061		59,818		62,422
Free adjusted funds flow	21,378		52,356		108,213		73,734		130,512

e) Net Operating Costs

Net operating costs equals operating expenses 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 expenses.

($ thousands, except per boe)	Three months ended June 30, 2023		Three months ended March 31, 2023		Three months ended June 30, 2022		Six months ended June 30, 2023		Six months ended June 30, 2022
Operating expenses	12,712		12,558		12,705		25,270		24,064
Processing revenue	(610	)	(636	)	(1,475	)	(1,246	)	(2,305	)
Net operating costs	12,102		11,922		11,230		24,024		21,759
Per boe	4.43		4.02		3.52		4.21		3.51

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 expenses 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 expenses. 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 June 30, 2023		Three months ended March 31, 2023		Three months ended June 30, 2022		Six months ended June 30, 2023		Six months ended June 30, 2022
Transportation expenses	10,967		11,288		12,092		22,255		22,937
Transportation revenue	(1,576	)	(1,520	)	(1,469	)	(3,096	)	(2,922	)
Net transportation costs	9,391		9,768		10,623		19,159		20,015
Per boe	3.43		3.29		3.33		3.36		3.23

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.

($/boe)	Three months ended June 30, 2023		Three months ended March 31, 2023		Three months ended June 30, 2022		Six months ended June 30, 2023		Six months ended June 30, 2022
Petroleum and natural gas sales	24.37		33.94		62.16		29.35		53.06
Royalties	(1.95	)	(4.13	)	(3.98	)	(3.09	)	(3.40	)
Realized gain (loss) on derivative financial instruments	8.87		4.72		(12.41	)	6.71		(8.89	)
Net operating costs	(4.43	)	(4.02	)	(3.52	)	(4.21	)	(3.51	)
Net transportation costs	(3.43	)	(3.29	)	(3.33	)	(3.36	)	(3.23	)
Operating netbacks	23.43		27.22		38.92		25.40		34.03
Production (boe/d)	30,046		32,963		35,044		31,496		34,225

j) Cash costs per boe

Cash costs per boe is comprised of net operating, transportation, general and administrative and financing expenses 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 June 30, 2023	Three months ended March 31, 2023	Three months ended June 30, 2022	Six months ended June 30, 2023	Six months ended June 30, 2022
Net operating costs	4.43	4.02	3.52	4.21	3.51
Net transportation costs	3.43	3.29	3.33	3.36	3.23
General and administrative expenses	1.09	1.14	0.83	1.12	0.89
Financing expenses on debt	0.73	0.95	1.95	0.85	1.99
Cash costs	9.68	9.40	9.63	9.54	9.62

k) Interest expenses on debt per boe

Interest expenses 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 expenses on debt per boe as an important measure to evaluate its cost of debt financing.

($ thousands, except per boe)	Three months ended June 30, 2023	Three months ended March 31, 2023		Three months ended June 30, 2022	Six months ended June 30, 2023	Six months ended June 30, 2022
Interest on bank loan and other	1,127	(92	)	1,123	1,035	2,163
Interest on senior notes	827	2,757		4,862	3,584	9,670
Accretion of deferred financing costs	49	150		245	199	491
Financing expenses on debt	2,003	2,815		6,230	4,818	12,324
Production (boe/d)	30,046	32,963		35,044	31,496	34,225
Interest expenses on debt per boe	0.73	0.95		1.95	0.85	1.99

Supplementary Financial Measures

“Adjusted fund flow margin” is comprised of adjusted funds flow divided by petroleum and natural gas sales.

“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 Oil		Condensate		Natural Gas Liquids1		Conventional Natural Gas		Total (boe/d)
Q3 2023 Average	0	%	14	%	7	%	79	%	26,000-28,000
2023 Annual Average	0	%	15	%	7	%	78	%	30,000-32,000
2023 Exit Rate	0	%	23	%	7	%	70	%	33,000-34,000

Notes:
¹⁾ Excludes condensate volumes which have been reported separately.

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, Tower 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 DETAILED INFORMATION, PLEASE CONTACT:

Dale Shwed, President and CEO	Phone: (403) 266-2088  Email: investor@crewenergy.com
John Leach, Executive Vice President and CFO

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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.