Crew Energy Inc. Announces Second Quarter 2019 Financial and Operating Results Highlighted by 36% Increase in Condensate Volumes Year-Over-Year

CALGARY, Aug. 1, 2019 /CNW/ - Crew Energy Inc. (TSX: CR) ("Crew" or the "Company") is pleased to announce our operating and financial results for the three and six month periods ended June 30, 2019.  Crew's Financial Statements and Notes, as well as Management's Discussion and Analysis ("MD&A") for the three and six month periods ended June 30, 2019 are available on Crew's website and filed on SEDAR at www.sedar.com.

Q2 2019 HIGHLIGHTS

• Ultra Condensate-Rich ("UCR") Montney Development Drives 36% Growth in Condensate Production: Q2 condensate volumes averaged 3,127 bbls per day, an increase of 19% over Q1 2019 and 36% over Q2 2018. Total liquids contributed 61% to Crew's total petroleum and natural gas sales for the quarter.
  
  
• Production of 22,865 boe per day with 31% Liquids: Total liquids increased to 31% of production, compared to 28% in Q1 2019 and 26% in Q2 2018. Greater Septimus production of 19,594 boe per day was in line with the previous quarter and 3% higher than Q2 2018, with significantly higher condensate volumes from newly completed UCR wells.
  
  
• Stable Adjusted Funds Flow ("AFF"): Q2 AFF totaled $22.5 million or $0.15 per fully diluted share, compared to Q2 2018 AFF of $21.8 million or $0.14 per fully diluted share, reflecting the impact of increased higher-value condensate production.
  
  
• Continued Strong UCR Results from 15-20 Pad: Crew's four "B" zone wells on the 15-20 pad at Greater Septimus have exceeded projections, generating average sales of 1,021 boe per day with 43% condensate and 11% other natural gas liquids ("ngl") over 120 days.
  
  
• Positive Contribution from 4-21 Pad in UCR Transition Zone: Crew finalized completing and equipping wells on the 4-21 pad in Q2, which have flowed at restricted rates with average sales over 90 days of 1,042 boe per day, comprised of 28% condensate and 13% ngl.
  
  
• Low Base Declines at Septimus Supports Sustainability: Production declines at Septimus are approaching 12% generating an operating netback that exceeds maintenance capital for the area. With continued development Crew plans on replicating this success in the UCR area.
  
  
• UCR Spending Supports Strong Operational Execution: Exploration and development capital expenditures in the quarter totaled $14.0 million, in line with forecast guidance for the period. Net capital expenditures were $10.7 million, including a $3.3 million non-core disposition. Activity in Q2 was directed to finalizing the drilling of one (1.0 net) extended reach horizontal ("ERH") well on the 3-32 pad in the UCR area, and finalizing the completion, equip and tie-in of eight (8.0 net) wells, along with the recompletion of six (6.0 net) heavy oil wells at Lloydminster.
  
  
• Financial Flexibility Maintained: Quarter end net debt of $353.4 million was 2% lower than Q1 2019 and includes $300 million of term debt due in 2024 which has no financial maintenance covenants. The Company's $235 million credit facility was renewed during the quarter and was drawn approximately 21% at the end of the period.

FINANCIAL & OPERATING HIGHLIGHTS:

FINANCIAL	Three months  ended	Three months ended	Six months ended	Six months ended
($ thousands, except per share amounts)	June 30, 2019	June 30, 2018	June 30, 2019	June 30, 2018
Petroleum and natural gas sales	51,543	54,040	106,994	113,467
Adjusted Funds Flow^(1)	22,513	21,804	48,284	48,177
Per share  - basic	0.15	0.14	0.32	0.32
- diluted	0.15	0.14	0.32	0.32
Net income (loss)	15,375	(9,181)	21,561	(5,033)
Per share  - basic	0.10	(0.06)	0.14	(0.03)
- diluted	0.10	(0.06)	0.14	(0.03)
Exploration and Development expenditures	13,997	12,468	69,238	46,389
Property acquisitions (net of dispositions)	(3,249)	17	(19,173)	(9,990)
Net capital expenditures	10,748	12,485	50,065	36,399
Capital Structure			As at	As at
($ thousands)			June 30, 2019	Dec. 31, 2018
Working capital deficiency (surplus)^(2)			9,653	(11,984)
Bank loan			48,398	59,904
			58,051	47,920
Senior Unsecured Notes			295,376	294,885
Total Net Debt^(2)			353,427	342,805
Current Debt Capacity^(3)			535,000	535,000
Common Shares Outstanding (thousands)			152,032	151,730

Notes:
(1)	Non-IFRS Measure. AFF is calculated as cash provided by operating activities, adding the change in non-cash working capital, decommissioning obligation expenditures and accretion of deferred financing costs on the senior unsecured notes.  AFF does not have a standardized measure prescribed by International Financial Reporting Standards ("IFRS"), and therefore may not be comparable with the calculations of similar measures for other companies.  See "Non-IFRS Measures" contained within Crew's MD&A for details including reasons for use and a reconciliation of AFF to its most closely related IFRS measure.
(2)	Non-IFRS Measure. Working capital deficiency / (surplus) includes cash and cash equivalents plus accounts receivable less accounts payable and accrued liabilities.  See "Non-IFRS Measures" contained within Crew's MD&A.
(3)	Current Debt Capacity reflects the bank facility of $235 million plus $300 million in senior unsecured notes outstanding.

	Three months ended	Three months ended	Six months ended	Six months ended
Operations	June 30, 2019	June 30, 2018	June 30, 2019	June 30, 2018
Daily production
Light crude oil (bbl/d)	155	261	190	288
Heavy crude oil (bbl/d)	1,722	1,930	1,666	1,839
Condensate (bbl/d)	3,127	2,304	2,873	2,500
Ngl (bbl/d)	2,049	1,710	2,031	1,751
Natural gas (mcf/d)	94,873	104,269	97,692	110,257
Total (boe/d @ 6:1)	22,865	23,583	23,042	24,754
Average prices^(1)
Light crude oil ($/bbl)	66.15	75.72	63.14	71.62
Heavy crude oil ($/bbl)	60.00	55.65	52.44	46.41
Condensate ($/bbl)	68.96	82.73	65.88	77.95
Ngl ($/bbl)	7.50	25.63	9.17	25.21
Natural gas ($/mcf)	2.34	2.23	2.91	2.56
Oil equivalent ($/boe)	24.77	25.18	25.65	25.32

Notes:
(1)	Average prices are before deduction of transportation costs and do not include realized gains and losses on financial instruments.

	Three months ended	Three months ended	Six months ended	Six months ended
	June 30, 2019	June 30, 2018	June 30, 2019	June 30, 2018
Netback ($/boe)
Petroleum and natural gas sales	24.77	25.18	25.65	25.32
Royalties	(1.77)	(1.83)	(1.81)	(1.77)
Realized commodity hedging loss	(0.16)	(1.23)	(0.52)	(1.07)
Marketing income^(1)	1.23	0.28	1.31	0.28
Net operating costs^(2)	(6.00)	(6.56)	(6.12)	(6.42)
Transportation costs	(3.01)	(1.78)	(2.63)	(1.95)
Operating netback^(3)	15.06	14.06	15.88	14.39
General & administrative ("G&A")	(1.39)	(1.23)	(1.45)	(1.31)
Other income	-	-	-	0.22
Financing costs on long-term debt	(2.84)	(2.67)	(2.85)	(2.55)
Adjusted funds flow^(3)	10.83	10.16	11.58	10.75
Drilling Activity
Gross wells	1	0	8	0
Working interest wells	1.0	0.0	8.0	0.0
Success rate, net wells (%)	100	-	100%	-

Notes:
(1)	Marketing income was recognized from the monetization of forward physical sales contracts offset by the cost of committed natural gas transportation that was not available during the period.
(2)	Net operating costs are calculated as gross operating costs less processing revenue.
(3)	Non-IFRS Measure.  Operating netback equals petroleum and natural gas sales including realized hedging gains and losses on commodity contracts, marketing income, less royalties, net operating costs and transportation costs calculated on a boe basis.  Operating netback and adjusted funds flow netback do not have a standardized measure prescribed by IFRS, and therefore may not be comparable with the calculations of similar measures for other companies.  See "Non-IFRS Measures" contained within Crew's MD&A.

FINANCIAL Overview

Positive Impacts from Increased Condensate and Total Liquids Weighting

• Production of 22,865 boe per day for the quarter was 3% lower than the same period in 2018, and 2% lower than Q1 2019, with the decreases being attributable to voluntary dry gas shut-ins due to weak pricing, a third-party pipeline outage triggering a full shut down of the Septimus and West Septimus ("Greater Septimus") area production of approximately 19,500 boe per day for six days, and natural declines on Lloydminster production.
  
  
• Condensate production averaged 3,127 bbls per day, an increase of 36% over Q2 2018 and 19% over Q1 2019, with total liquids production increasing to 31% of total volumes, higher than the 26% weighting in Q2 2018 and 28% in Q1 2019. Condensate contributed 38% to Crew's total sales in Q2 2019, compared with 32% in Q2 2018 and 26% in Q1 2019.
  
  
• Greater Septimus production averaged 19,564 boe per day in Q2 2019, an increase of 3% over 18,953 boe per day in Q2 2018 and on par with Q1 2019 volume, despite the pipeline outage and related shut down.

AFF per Share Driven by Liquids and Condensate Production

• AFF in Q2 2019 was $22.5 million ($0.15 per diluted share), 7% higher on a per share basis than the same period in 2018, primarily due to higher condensate production and a lower realized hedging loss. For the first half of 2019, Crew's AFF of $48.3 million or $0.32 per diluted share was in line with the same period in 2018.
  
  
• Quarter-over-quarter, AFF was 13% lower than Q1 2019, primarily attributable to weaker natural gas and ngl prices and higher transportation costs. These inputs were partially offset by lower net operating costs.

Quarter-over-Quarter Improvement in Liquids Volumes and Pricing

• Q2 2019 petroleum and natural gas sales decreased 7% compared to Q1 2019 primarily the result of a substantial drop in natural gas prices quarter-over-quarter. This was partially offset by increased condensate production and improved pricing for condensate and heavy crude oil.
  
  
• Petroleum and natural gas sales during Q2 2019 and for the first half of the year decreased 5% and 6%, respectively, relative to the same periods in 2018, mainly as a result of the lower production combined with lower realized light crude oil, condensate, and ngl prices in 2019 relative to the same periods in 2018.
  
  
• Quarter-over-quarter, Crew's realized light crude oil and condensate price increased 8% and 11%, respectively, approximating the 10% increase in the Canadian dollar denominated West Texas Intermediate ("WTI") benchmark price. WTI prices were bolstered by geo-political concerns arising over Iran's nuclear sanctions and military activity in the strategic Strait of Hormuz oil shipping channel.
  
  
• Crew's heavy crude oil realized price increased 36% compared to Q1 2019, primarily in response to the Alberta Government's oil curtailment program. The realized price for ngl decreased 31% compared to Q1 2019, primarily due to price declines for propane and butane at Conway, the primary U.S. pricing market for the majority of Crew's ngl production.
  
  
• Crew's realized natural gas price for Q2 2019 was 32% lower than Q1 2019, as natural gas prices across North America declined as a result of continued production growth and reduced weather-related demand. Crew's diversified natural gas marketing portfolio partially offset the market weakness with 66% of the Company's sales exposed to U.S. pricing points. This resulted in a corporate wellhead price of $2.34 per mcf, compared to the Canadian benchmark AECO 5A price of $1.03 per mcf.
  
  
• Marketing income for the quarter was $2.6 million or $1.23 per boe compared to $2.9 million or $1.40 per boe in Q1 2019, and $0.6 million or $0.28 per boe in Q2 2018, reflecting the monetization of the Company's Dawn transport contract and Malin sales contract.

Lower Net Operating Costs Bolster Operating Netbacks

• Corporate operating netbacks in Q2 2019 and first half 2019 averaged $15.06 per boe and $15.88 per boe, respectively, an improvement of 7% and 10% over the same periods in 2018. Compared to Q1 2019, operating net backs decreased 10% as a result of lower commodity prices and higher transportation costs, offset by lower operating costs.
  
  
• Cash costs per boe for Q2 increased 2% relative to Q1 2019, which reflects higher transportation costs per boe, offset by lower royalties and net operating costs per boe. Compared to the same period in 2018, cash costs per boe increased due to higher transportation, financing and G&A costs per boe, offset by lower royalties and net operating costs per boe.
  
  
• Q2 and first half 2019 net operating costs and net operating costs per boe decreased relative to the same periods in 2018, as a result of a decline in Tower and Lloydminster production, areas which have higher operating costs per boe. Quarter-over-quarter net operating costs were down 4% due to the seasonal decline in field operating costs.
  
  
• Transportation costs in Q2 2019 and the first half of 2019 increased compared to Q1 2019, and the corresponding periods in 2018, as the Company works to provide further diversified market opportunities for its natural gas production. Further transportation costs were added in April 2018 with the introduction of new service on the NGTL system, and in April 2019 with the addition of fees associated with third party ownership of the sales pipeline between West Septimus and the Saturn meter station.

Q2 Capital Expenditures In-Line with Guidance

• Exploration and development capital expenditures in Q2 were $14.0 million, or $10.7 million net after the impact of a non-core disposition of $3.3 million during the period. Year-to-date in 2019, Crew has invested $50.1 million in net capital expenditures, with the majority directed to drilling and development opportunities within the Company's UCR area.
  
  
• Approximately $7.8 million of our Q2 capital was allocated to drilling and completion activities in the UCR area, including drilling one (1.0 net) ERH well with a lateral length of 3,050 metres on Crew's 3-32 pad along with finalizing the completion and equipping of eight (8.0 net) wells. Crew directed $3.3 million to Montney well site development, facilities and pipelines and $2.9 million to land, seismic and other miscellaneous expenditures.

Ongoing Focus on Balance Sheet Strength

• Net debt of $353.4 million was 3% lower than at the end of Q1 2019 due to the Company's 2019 capital expenditure program being weighted to higher first quarter spending.
  
  
• The Company's debt is comprised of $300 million of term debt with no financial maintenance covenants or repayment required until 2024, as well as a $235 million credit facility that was 25% drawn after adjusting for a working capital deficiency of approximately $9.7 million at quarter end.
  
  
• Crew's credit facility was renewed during Q2, with no changes to the borrowing base of $235 million, no financial maintenance covenants, and access to the full borrowing base value.
  
  
• Further work on optimizing the asset portfolio in Q2 2019 contributed to the $3.3 million disposition of 2.7 (2.0 net) sections of non-core assets having no production or reserves assigned, with proceeds directed to debt reduction and maintaining a healthy financial position.

Transportation, Marketing & HEDGING

Diversified Market Access Provides Strategic Benefit

• In Q2 and first half 2019, Crew elected to monetize our Dawn and Malin market exposure, realizing marketing income of $2.6 million and $5.5 million, respectively. Crew has further elected to monetize these contracts for Q3 2019, resulting in approximately $1.8 million of marketing income to be realized in the quarter.
  
  
• For the second half of 2019, our average natural gas sales exposure is currently expected to be approximately 55% to Chicago, 17% to NYMEX, 8% to Alliance ATP, 7% to Dawn, 5% to Malin, 5% to Station 2 and 3% to AECO 5A.

Natural Gas & Liquids Hedging

• Crew's natural gas hedges currently include:
• 25,000 mmbtu per day of Chicago gas at C$3.53 per mmbtu for 2019
• 7,500 mmbtu per day of Dawn gas at C$3.55 per mmbtu for 2019
• 10,000 mmbtu per day of NYMEX gas at US$2.95 per mmbtu for 2019
• 7,500 mmbtu per day of Chicago gas at C$3.40 per mmbtu for 2020
  
  
• For liquids, Crew has the following hedges in place:
• 1,874 bbls per day of WTI at an average price of C$75.99 per bbl for 2019
• 250 bbls per day of WCS for Q4 2019 at C$56.20 per bbl
• 250 bbls per day of differentials at US$17.25 per bbl for Q3 2019
• 500 bbls per day of WCS differential at C$25.23 per bbl for the second half of 2019
• 750 bbls per day of WTI at an average price of C$79.12 per bbl for 2020

OPERATIONS & AREA Overview

NE BC Montney - Greater Septimus

• During Q2 2019, Crew completed drilling one net ERH well with a lateral length of 3,050 metres on the 3-32 pad in our UCR area at West Septimus.  
  
  
• Results from wells on our 15-20 pad in the UCR area at Greater Septimus have remained strong and offer compelling returns.  The four "B" zone wells produced average sales of 1,021 boe per day comprised of 43% condensate and 11% ngl over 120 days on production.    
• At Crew's 4-21 pad in the UCR transition zone, results have also exceeded internal type well expectations for West Septimus.  The wells are being produced at restricted rates and have produced average sales of 1,042 boe per day over 90 days on production, including 28% condensate and 13% ngl. 
  
  
• As a result of the outperformance of these condensate-rich wells at Greater Septimus, Crew has been able to optimize our commodity mix and during Q2, effectively mitigated the impact of the six-day pipeline shut-down affecting approximately 19,500 boe per day of production along with our continued shut-in of dry gas. 
  
  
• During the pipeline outage, Crew accelerated Septimus facility maintenance work originally planned for 2020 and implemented further debottlenecking measures which are expected to improve the long-term efficiency of our operations. 

Greater Septimus
Production & Drilling	Q2 2019	Q1 2019	Q4 2018	Q3 2018	Q2 2018
Average daily production (boe/d)	19,594	19,535	18,447	19,240	18,953
Wells drilled (gross / net)	1 / 1.0	6 / 6.0	6 / 6.0	4 / 4.0	-
Wells completed (gross / net)	-	8 / 8.0	3 / 3.0	-	2 / 1.6
Operating Netback	Q2	Q1	Q4	Q3	Q2
($ per boe)	2019	2019	2018	2018	2018
Revenue	22.20	25.61	26.53	22.83	22.70
Royalties	(1.27)	(1.56)	(1.58)	(1.15)	(1.35)
Realized commodity hedge gain (loss)	0.28	(0.74)	(1.79)	(2.01)	(1.32)
Marketing income ^(1)	1.43	1.66	1.23	0.34	0.34
Net operating costs^(2)	(4.46)	(4.65)	(4.51)	(4.61)	(4.71)
Transportation costs	(2.81)	(1.73)	(1.35)	(1.22)	(1.40)
Operating netback^(3)	15.37	18.59	18.53	14.18	14.26

Notes:
(1)	Marketing income was recognized from the monetization of forward physical sales contracts offset by the cost of committed natural gas transportation.
(2)	Net operating costs are calculated as gross operating costs less processing revenue.
(3)	Non-IFRS Measure.  Operating netback equals petroleum and natural gas sales including realized hedging gains and losses on commodity contracts, marking income, less royalties, net operating costs and transportation costs calculated on a boe basis. Operating netback does not have a standardized measure prescribed by IFRS, and therefore may not be comparable with the calculations of similar measures for other companies.  See "Non-IFRS Measures" contained within Crew's MD&A.

Other NE BC Montney

• Tower: Production at Tower averaged 592 boe per day in Q2 2019, reflecting the impact of production being shut-in for offset fracturing during the period. Crew continues to evaluate the relative economics of Tower development as well as reviewing encouraging nearby Lower Montney well results.
  
  
• Monias: Activity at Monias during Q2 was directed to preparing for the completion in Q3 of one horizontal Montney delineation well that was drilled in Q1, approximately 18 km to the northwest of our West Septimus UCR core area.
  
  
• Attachie: Of Crew's 92 net sections of land in this area, approximately 44 net sections are situated within the liquids-rich hydrocarbon window. Given the positive results generated by offsetting operators, a lease retention well was drilled in January of 2019.
  
  
• Oak / Flatrock: In this liquids-rich gas area, Crew has over approximately 60 (52 net) sections of land, and the Company plans to continue monitoring industry activity and offsetting well results.

AB / SK Heavy Oil - Lloydminster

• During Q2, activity at Lloydminster included the recompletion of six (6.0 net) heavy crude oil wells which contributed to average production of 1,722 bbls per day of heavy crude oil, a 7% increase over the prior quarter. Relative to Q2 2018, heavy crude oil volumes were approximately 11% lower due to limited capital investment in the area.
  
  
• WCS pricing differentials continued to improve through Q2 and contributed to operating netbacks at Lloydminster which averaged $24.93 per boe. To maximize profitability, Crew will continue to evaluate forward pricing for WCS for the purposes of optimizing the execution timing of a three (3.0 net) multilateral horizontal drilling program.

OUTLOOK

Condensate and Liquids Trending Higher

• The ongoing evolution of Crew's drilling and completion design has improved efficiencies and contributed to condensate ratios trending higher while overall volumes remain stable.
  
  
• The Company's emphasis on UCR drilling along with our goal of improving margins is meeting with success. Condensate volumes in Q2 increased 36% year-over-year while Crew's average condensate price of $68.96 per bbl was materially higher than the average corporate realized price per boe of $24.77.

Low Base Declines at Septimus Supports Sustainability

• At Septimus, Crew is successfully generating an operating netback that exceeds maintenance capital requirements for the area. As a result of Crew's investment in the area, production declines for Septimus are approaching 12%, representing similar performance attributes to a tight conventional reservoir rather than an unconventional reservoir. Crew plans to replicate the development success and free cash flow generation realized at Septimus within our UCR area, which has over 135 potential drilling opportunities¹, representing over ten years of highly economic future growth at Crew's current pace of development.

^1	See "Information Regarding Disclosure on Oil and Gas, Operational Information and Non-IFRS Measures".

Significant Optionality Maintained

• With access to all three major export pipelines, proximity to the Coastal GasLink Pipeline, and our ability to produce natural gas or liquids, Crew's land base is ideally positioned to capitalize on an LNG project that could have demand for up to 25% of current Western Canada natural gas production.
• Year-to-date, Crew has sold approximately $20.75 million of assets and continues to explore opportunities to divest or monetize the value of certain assets not being actively developed in the current environment.

Net Capital Expenditures to Remain in Line with AFF

• Crew's 2019 capital expenditure budget is expected to range between $95 and $105 million. Average volumes are forecast between 22,000 to 23,000 boe per day, with a steady focus on increasing the weighting of higher valued condensate and liquids within Crew's production portfolio.
  
  
• For Q3 2019, production is expected to average between 22,000 and 23,000 boe per day on capital expenditures between $18 and $22 million. Quarterly volume forecasts incorporate the Company's planned deferral of dry gas production that is exposed to weak spot gas prices in Western Canada. Activity during Q3 will focus on the completion of one Montney well, water handling initiatives, as well as building out leases and infrastructure to prepare for the next phase of drilling and completions.
  
  
• Based on our first half capital program, approximately $25 to $35 million is expected to be allocated to the second half program which is planned to approximate AFF.

We thank our employees and directors for their commitment and dedication to the success of Crew, and we thank all of our shareholders and bondholders for their patience and continued support in this challenging operating environment.

Cautionary Statements

Information Regarding Disclosure on Oil and Gas, Operational Information and Non-IFRS Measures

This press release discloses "potential drilling opportunities" in the Company's Greater Septimus area of operations which are comprised of: (i) proved locations; (ii) probable locations; and (iii) unbooked locations.  Proved locations and probable locations are derived from 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.  Of the 135 total potential drilling opportunities identified herein, 29 are proved locations, 53 are probable locations and 53 are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information.  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.  While certain of the unbooked drilling opportunities identified have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are further away from existing wells where management has less information about the characteristics of the reservoir, and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

This press release contains metrics commonly used in the oil and natural gas industry, such as "adjusted funds flow", "operating netbacks", "working capital deficiency (surplus)" and "net debt".  These terms are not defined in IFRS and 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 herein to provide readers with additional information to evaluate the Company's performance, however such metrics should not be unduly relied upon. Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Crew's operations over time.  Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes. See "Non-IFRS Measures" contained within Crew's MD&A for applicable definitions, calculations, rationale for use and reconciliations to the most directly comparable measure under IFRS.

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" 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: as to the execution of Crew's business plan including guidance as to its capital expenditure plans for Q3 and the second half of 2019; as to plans to internally fund its capital program with funds flow generated from Crew's existing business; as to plans to internally fund capital in 2019 with adjusted funds flow; as to the Company's ongoing goal of increasing the overall weighting of condensate in its production mix and associated improvements in realized pricing and operating netbacks for 2019 and beyond;; the estimated volumes, including shut-ins, and product mix of Crew's oil and gas production; production estimates including Q3 and 2019 average production guidance; Crew's forecast base decline profile moving towards 12%; commodity price expectations including Crew's estimates of natural gas pricing exposure and market allocation; Crew's commodity risk management programs including plans for additional hedging in 2019; marketing and transportation plans; future liquidity and financial capacity; future results from operations and operating metrics; potential for lower costs and efficiencies going forward; future development, exploration, acquisition and disposition activities (including drilling, completion and infrastructure plans and associated timing and cost estimates); the amount and timing of capital projects; management's assessment of potential drilling opportunities and possible expansion thereof representing over ten years of economic growth; the Company's potential to capitalize on an LNG project; and future production capacity and corresponding potential for reduced on-stream costs.

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; 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 and environmental matters in the jurisdictions in which Crew operates; 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: 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 the potential for variation in the quality of the Montney formation; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates 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 Annual Information Form).

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.

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 rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long term performance or of ultimate recovery.

BOE equivalent

Barrel of oil equivalents or BOEs may be misleading, particularly if used in isolation.  A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does 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.

Crew is a growth-oriented oil and natural gas producer, committed to pursuing sustainable per share growth through a balanced mix of financially responsible exploration and development complemented by strategic acquisitions.  The Company's operations are primarily focused in the vast Montney resource, situated in northeast British Columbia, and include a large contiguous land base.  Crew's liquids-rich Greater Septimus along with Groundbirch and the light oil area at Tower in British Columbia offer significant development potential over the long-term.  The Company has access to diversified markets with operated infrastructure and access to multiple pipeline egress options.  Crew's common shares are listed for trading on the Toronto Stock Exchange ("TSX") under the symbol "CR".

Financial statements and Notes, as well as Management's Discussion and Analysis for the three and six month periods ended June 30, 2019 and 2018 are filed on SEDAR at www.sedar.com and are available on the Company's website at www.crewenergy.com.

SOURCE Crew Energy Inc.

Dale Shwed, President and CEO; John Leach, Executive Vice President and CFO, Phone: [phone], Email: [email protected]

Related Links

http://www.crewenergy.com