Crew Energy Inc. Announces First Quarter 2019 Financial and Operating Results

CALGARY, May 2, 2019 /CNW/ - Crew Energy Inc. (TSX: CR) ("Crew" or the "Company") is pleased to announce our operating and financial results for the three month period ended March 31, 2019.  Crew's Financial Statements and Notes, as well as Management's Discussion and Analysis ("MD&A") for the three month period ended March 31, 2019 are available on Crew's website and filed on SEDAR at www.sedar.com. 

Q1 2019 HIGHLIGHTS

• Production of 23,222 boe per day: Volumes were 4% higher than the previous quarter supported by stronger Greater Septimus production of 19,535 boe per day that was 6% higher than the previous quarter due to robust production from newly completed Ultra Condensate Rich ("UCR") wells.
  
  
• Stable Adjusted Funds Flow ("AFF"): Q1 AFF totaled $25.8 million or $0.17 per fully diluted share, compared to Q4 2018 AFF of $23.7 million or $0.16 per fully diluted share, reflecting increased liquids production, including condensate growth and stronger overall liquids pricing.
  
  
• Continued Focus on Montney Condensate Growth: Q1 condensate volumes averaged 2,617 bbls per day, an increase of 7% over Q4 2018. Total liquids represented 28% of average quarterly volumes and contributed 44% to Crew's petroleum and natural gas sales for the quarter.
  
  
• Strong UCR Well Results from 15-20 Pad: Early results from four "B" zone wells and one "C" zone well on our 15-20 pad at Greater Septimus continue to support further development and capital allocation in the UCR area. After 45 days of production, the four "B" zone wells produced an average of 1,211 boe per day comprised of 3,336 mcf per day of sales gas, 538 bbls per day of condensate and 117 bbls per day of propane and butane.
  
  
• Positive Early Results from 4-21 Pad in UCR Transition Zone: After 20 days of flow back, the six (6.0 net) "B" zone wells were producing at restricted rates averaging 1,374 boe per day comprised of 4,830 mcf per day of sales gas, 400 bbls per day of condensate and 169 bbls per day of propane and butane at an average flowing casing pressure of approximately 8,900 kPa.
  
  
• Strong Operational Execution with Capital Spending Below Guidance: Exploration and development capital expenditures in the quarter totaled $55.2 million, lower than our forecast guidance of between $60 and $70 million. Crew drilled seven (7.0 net) and completed eight (8.0 net) wells in our UCR area at West Septimus and recompleted six (6.0 net) heavy oil wells at Lloydminster. After incorporating $17.5 million in proceeds from a disposition and minor acquisition during the period, net capital expenditures were $39.3 million.
  
  
• Longest Laterals Drilled in Company History: Four extended reach horizontal ("ERH") UCR wells were drilled in Q1 with lateral lengths over 3,000 metres and per lateral metre drilling costs that were 35% lower than costs realized in 2017.
  
  
• Realized Natural Gas Prices Again Outperformed Benchmark: Q1 average realized natural gas prices of $3.45 per mcf were 21% higher than Q1 2018 and outperformed the AECO 5A benchmark of $2.62 per mcf by 32%, driven by Crew's high heat content natural gas and exposure to diversified sales hubs and markets.
  
  
• Financial Flexibility Maintained: Quarter end net debt of $361.5 million includes $300 million of term debt due in 2024 with no financial maintenance covenants and 17% drawn on the Company's $235 million credit facility (excluding working capital deficiency).

Financial & Operating Highlights:

FINANCIAL ($ thousands, except per share amounts)			Three months ended Mar. 31, 2019	Three months ended Mar. 31, 2018
Petroleum and natural gas sales			55,451	59,427
Adjusted Funds Flow^(1)			25,771	26,373
Per share  - basic			0.17	0.18
- diluted			0.17	0.17
Net income			6,186	4,148
Per share  - basic			0.04	0.03
- diluted			0.04	0.03
Exploration and Development expenditures			55,241	33,921
Property acquisitions (net of dispositions)			(15,924)	(10,007)
Net capital expenditures			39,317	23,914
Capital Structure ($ thousands)			As at Mar. 31, 2019	As at Dec. 31, 2018
Working capital deficiency (surplus)^(2)			26,283	(11,984)
Bank loan			40,065	59,904
			66,348	47,920
Senior Unsecured Notes			295,130	294,885
Total Net Debt			361,478	342,805
Current Debt Capacity^(3)			535,000	535,000
Common Shares Outstanding (thousands)			150,554	151,730

Notes:
(1)	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)	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.

Operations			Three months ended Mar. 31, 2019	Three months ended Mar. 31, 2018
Daily production
Light crude oil (bbl/d)			226	316
Heavy crude oil (bbl/d)			1,608	1,747
Condensate (bbl/d)			2,617	2,699
Other natural gas liquids (bbl/d)			2,014	1,792
Natural gas (mcf/d)			100,542	116,312
Total (boe/d @ 6:1)			23,222	25,939
Average prices ^(1)
Light crude oil ($/bbl)			61.04	68.20
Heavy crude oil ($/bbl)			44.25	36.09
Condensate ($/bbl)			62.17	73.82
Other natural gas liquids ($/bbl)			10.89	24.81
Natural gas ($/mcf)			3.45	2.85
Oil equivalent ($/boe)			26.53	25.46

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

			Three months ended Mar. 31, 2019	Three months ended Mar. 31, 2018
Netback ($/boe)
Petroleum and natural gas sales			26.53	25.46
Royalties			(1.85)	(1.72)
Realized commodity hedging loss			(0.88)	(0.93)
Marketing income^(1)			1.40	0.29
Net operating costs^(2)			(6.25)	(6.29)
Transportation costs			(2.26)	(2.11)
Operating netback ^(3)			16.69	14.70
General & administrative ("G&A")			(1.51)	(1.39)
Other income			-	0.43
Financing costs on long-term debt			(2.86)	(2.44)
Adjusted funds flow			12.32	11.30
Drilling Activity
Gross wells			7	0
Working interest wells			7.0	0.0
Success rate, net wells (%)			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)	Oerating 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

Production Above Guidance

• Volumes for the quarter averaged 23,222 boe per day, above our projected volume range for the period of 22,000 to 23,000 boe per day, as a result of strong early performance from the eight West Septimus UCR wells completed during the quarter.
  
  
• Greater Septimus production averaged 19,535 boe per day in Q1 2019, an increase of 6% over the 18,447 boe per day in Q4 2018.
  
  
• Production for the quarter was impacted by several wells at West Septimus being shut-in for the majority of January and February to accommodate the completion of the final two wells on the 15-20 pad and six wells on the 4-21 pad. Production was also negatively impacted due to the 17 day unplanned shut down of the McMahon gas plant which processes the Company's non-Montney gas in northeast British Columbia.
  
  
• The addition of the eight newly completed wells described above showed strong results in March, which helped to offset lower production volumes in January and February.

Pricing Environment Impacts Revenue

• First quarter 2019 petroleum and natural gas sales increased 9% over the previous quarter as a result of higher quarter-over-quarter liquids production, led by a 7% increase in condensate production. First quarter revenue was also bolstered by stronger liquids pricing, which reflects higher prices for condensate and heavy crude oil offset by weaker natural gas and natural gas liquids ("ngl") pricing.
  
  
• Liquids prices for the quarter benefited from the Alberta Government's mandated oil production curtailment that took 325,000 bbls per day of Alberta supply out of the market, effective January 1, 2019. Despite slightly weaker benchmark pricing for Canadian dollar denominated WTI, which declined 6% compared to the fourth quarter of 2018, pricing for Western Canadian Select ("WCS") and Canadian condensate delivered at Edmonton increased 126% and 13% respectively, over the prior quarter.
  
  
• Crew's realized natural gas price decreased by 9% compared to the previous quarter, as the Company's weighting of natural gas sold into the US Chicago and NYMEX markets increased from 55% to 61% in Q1 2019 compared to Q4 2018, while the prices received for delivering into those markets declined 18% and 13%, respectively.
  
  
• Marketing income for the quarter increased to $2.9 million or $1.40 per boe from $2.1 million or $1.03 per boe in Q4 2018 and reflects the net revenue received for monetarization of the Company's Dawn transport contract and Malin sales contract, offset by unutilized demand charges for natural gas pipeline capacity that was not accessed until March 2019.

Liquids Production and Prices Improve AFF

• Crew's AFF in Q1 2019 totaled $25.8 million ($0.17 per diluted share), an increase of 9% over the prior quarter, attributable to higher liquids production and pricing, combined with higher marketing income. These were partially offset by higher net operating and transportation costs and a larger hedging loss. Crew's AFF declined 2% compared to the same period in 2018, mainly due to lower production.
  
  
• Corporate operating netbacks in Q1 2019 averaged $16.69 per boe, a 14% improvement over the same period in 2018 and 5% over the prior quarter. Improvements relative to Q1 2018 and Q4 2018 reflect a higher liquids weighting, stronger commodity pricing and higher marketing income, offset by higher cash costs and relative to Q4 2018, an increased hedging loss.
  
  
• Cash costs and cash costs per boe increased in Q1 2019 compared to the prior quarter, mainly due to increased royalties, net operating and transportation costs, offset by lower G&A costs. Relative to Q1 2018, cash costs declined due to lower overall production while on a per boe basis, cash costs increased due to higher royalties and transportation costs, offset by lower net operating and G&A costs.
  
  
• Net operating cost and net operating costs per boe in the first quarter increased over the previous quarter as a result of the re-activation of higher cost heavy crude oil production that had been shut-in during Q4 2018 due to extremely low WCS pricing. Additionally, extremely cold weather experienced in Western Canada early in 2019 contributed to higher first quarter net operating costs.
  
  
• With higher natural gas production from the Greater Septimus area in Q1 2019 relative to Q4 2018, Crew moved more volumes to higher priced markets which incur a higher per unit cost. This resulted in increased transportation costs in the first quarter of 2019 relative to the prior quarter.

Q1 Capital Expenditures Below Guidance

• Q1 2019 net capital expenditures totaled $39.3 million, including $55.2 million in exploration and development expenditures and $17.5 million of gross proceeds related to the sale of non-core land with no associated reserves or production, which was partially offset by a tuck-in acquisition for approximately $1.6 million.
  
  
• Approximately $49.0 million of our Q1 capital was allocated to drilling and completion activities, with $3.4 million spent on Montney well site development, facilities and pipelines and $2.8 million directed to land, seismic and other miscellaneous items.
  
  
• In the first quarter of 2019, Crew drilled seven (7.0 net) and completed eight (8.0 net) wells in our UCR area at West Septimus and recompleted six (6.0 net) heavy crude oil wells at Lloydminster.

Net Debt Reflects Modest Draws on Bank Facility and Working Capital Deficiency

• March 31, 2019 net debt of $361.5 million was 5% higher than year end 2018 due to the Company's 2019 capital expenditure program being weighted to higher first quarter spending. Annual capital spending is forecast to approximate AFF resulting in minimal expected change to year over year net debt.
  
  
• 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 28% drawn after adjusting for a working capital deficiency of approximately $26.3 million at quarter end.

Transportation, Marketing & HEDGING

Diversified Market Access Provides Strategic Benefit

• Crew strategically chose to monetize the inherent value in our Dawn and Malin market exposure in Q1 2019, realizing marketing income of $3.3 million. The Company has further elected to monetize the value inherent in these contracts for Q2 2019 and will recognize approximately $2.5 million of associated marketing income for the second quarter.
  
  
• For 2019, our average natural gas sales exposure is currently expected to be approximately 54% to Chicago, 17% to NYMEX, 7% to Dawn, 8% to Alliance ATP, 5% to Malin, 4% to Station 2 and 5% to AECO 5A.
  
  
• During Q1 2019, Crew began shipping natural gas through the Company's new West Septimus to TCPL Saturn meter station sales pipeline system. This allowed Crew to benefit from the spike in AECO pricing that occurred during the quarter due to the extreme cold weather experienced across Western Canada.

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
• 7,500 mmbtu per day of Dawn gas at C$3.55 per mmbtu
• 10,000 mmbtu per day of NYMEX gas at US$2.95 per mmbtu

• 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
• 500 bbls per day of WCS for the first half of 2019 at an average price of C$52.93 per bbl
• 250 bbls per day of WCS for Q4 2019 at C$56.20 per bbl
• 250 bbls per day of WCS differential at C$25.75 per bbl for the first half of 2019
• 500 bbls per day of WCS differential at C$25.23 per bbl for the second half of 2019
• 250 bbls per day of differentials at US$12.25 per bbl for Q2 2019
• 250 bbls per day of differentials at US$17.25 per bbl for Q3 2019

OPERATIONS & AREA Overview

NE BC Montney - Greater Septimus

• Development drilling continued in the UCR region at West Septimus with five wells rig released in Q1. Four of the wells were ERH wells with lateral lengths over 3,000 metres. Progressive changes to fluid systems, drill bits, and downhole assemblies has enabled a 35% reduction in the cost per lateral metre drilled relative to the same costs incurred in 2017.
  
  
• As Crew's focus continues to be directed largely to our West Septimus area, reduced capital and activity levels at Septimus have allowed the Company to better understand our base decline profile, which is forecast to be moving towards 12%, enhancing the sustainability of our business model.
  
  
• The final two wells on our 15-20 UCR pad at Greater Septimus and all six wells on our 4-21 pad were completed during Q1 2019. Two completions on the 4-21 pad were accelerated into Q1 to minimize downtime and offset the impact of inter-well communication. Early results indicate this strategy was effective as the 15-20 wells have returned to similar productivity levels that were realized prior to the offset completion operations. Cost efficiencies were also captured by simultaneously executing all six of the 4-21 well completions
  
  
• Better than forecasted production rates indicate well design enhancements, are effectively delivering positive results. Early results from wells on our 15-20 pad at Greater Septimus continue to support further development and capital allocation in the UCR area, and after 45 days of production, demonstrated the following: 
• Four "B" zone wells produced average sales of 1,211 boe per day comprised of 3,336 mcf per day of gas, 538 bbls per day of condensate and 117 bbls per day of propane and butane.
• After 45 days of production, one "C" zone delineation well confirmed increasing condensate/gas ratios ("CGR") trending east over our acreage, and produced an average of 923 boe per day comprised of 3,969 mcf per day gas, 162 bbls per day condensate and 99 bbls per day of propane and butane, which represents approximately three times the CGR relative to a "C" zone well drilled 1,000 metres to the west. 
• Early results from Crew's 4-21 pad in the UCR transition zone are also encouraging.  After 20 days of flow back, the six (6.0 net) "B" zone wells were producing at restricted rates averaging 1,374 boe per day of sales, comprised of 4,830 mcf per day of gas, 400 bbls per day of condensate and 169 bbls per day of propane and butane at an average flowing casing pressure of approximately 8,900 kPa.

Greater Septimus

Production & Drilling	Q1 2019	Q4 2018	Q3 2018	Q2 2018	Q1 2018
Average daily production (boe/d)	19,535	18,447	19,240	18,953	20,467
Wells drilled (gross / net)	7 (7.0)	6 (6.0)	4 / 4.0	-	-
Wells completed (gross / net)	8 (8.0)	3 (3.0)	0 / 0	2 / 1.6	9 / 7.7
Operating Netback  ($ per boe)	Q1 2019	Q4  2018	Q3 2018	Q2 2018	Q1 2018
Revenue	25.61	26.53	22.83	22.70	25.40
Royalties	(1.56)	(1.58)	(1.15)	(1.35)	(1.50)
Realized commodity hedge loss	(0.74)	(1.79)	(2.01)	(1.32)	(1.01)
Marketing income ^(1)	1.66	1.23	0.34	0.34	0.37
Net operating costs^(2)	(4.65)	(4.51)	(4.61)	(4.71)	(4.45)
Transportation costs	(1.73)	(1.35)	(1.22)	(1.40)	(1.51)
Operating netback^(3)	18.59	18.53	14.18	14.26	17.30

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)	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 787 boe per day in Q1 2019. Crew continues to evaluate the relative economics of Tower development as well as encouraging nearby Lower Montney well results.
  
  
• Monias: One horizontal Montney delineation well was drilled in Q1 in the Monias area, located approximately 18 km to the northwest of our West Septimus UCR core area.
  
  
• Attachie: Of Crew's 97 sections of land in this area, approximately 45 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.
  
  
• Oak / Flatrock: Drilling activity is gaining momentum for liquids-rich gas in this area where Crew has over 60 sections of land. We will continue to monitor industry activity and offsetting well results from this area.

AB / SK Heavy Oil - Lloydminster

• Q1 heavy oil activity at Lloydminster included the recompletion of six (6.0 net) heavy oil wells, resulting in average production volumes of 1,614 boe per day for the quarter. Production volumes were approximately 8% lower than Q1 2018 due to minimal capital investment in 2018 and shutting in lower margin production in Q4 2018 in response to extremely wide differentials.
  
  
• WCS pricing differentials contracted significantly in the first quarter with Q1 2019 operating netbacks at Lloydminster averaging $13.48 per boe in the period.
  
  
• Crew plans on drilling three (3.0 net) multi-lateral horizontal wells in this area in 2019 should prices be supportive.

OUTLOOK

Value Creation Strategy Intact

• Crew has assembled an attractive land base with over 280,000 net acres of highly prospective Montney rights in northeast B.C., with proved plus probable reserves of over 401 million boe assigned by Crew's independent reserves evaluator at year end 2018 on only 13% of our Upper Montney lands and less than 1% of our Lower Montney lands¹.
  
  
• Our strategic investment in infrastructure has resulted in Crew having the capacity to produce over 40,000 boe per day through existing facilities, which can significantly reduce future on-stream costs. We remain committed to high grading our portfolio of assets to enhance shareholder value while preserving the material upside in our vast resource base.

Increasing Condensate Production and Margin Expansion

• Crew's focus will continue to reflect our ongoing goal of increasing condensate in our production mix, which is expected to contribute to further improvements in realized pricing and operating netbacks. Under current strip pricing, the UCR wells being drilled by Crew are expected to generate robust internal rates of return ("IRR") of over 70% with over $6.0 million per well of before tax net present value discounted at 10% (NPV10)¹. With over 135 potential drilling opportunities² at Crew's current pace of development, this represents over ten years of highly economic future growth.

Balancing Capital Expenditures with AFF

• Crew is committed to capital discipline with a 2019 capital expenditure budget that is forecast to range between $95 and $105 million and designed to approximate annual AFF. This budget has been structured to support the Company's ability to effectively manage our balance sheet and retain the flexibility to produce average volumes of 22,000 to 23,000 boe per day, while increasing our exposure to higher valued condensate. Net proceeds from the sale of non-core assets in Q1 2019 of $15.9 million were used to reduce net debt, strengthening our financial position.
  
  
• Our Q2 2019 production is expected to range between 22,000 and 23,000 boe per day on capital expenditures between $12 and $18 million, although Crew's productive capacity is higher. The quarterly forecast reflects the Company's planned deferral of dry gas production which is exposed to spot gas prices in Western Canada which are currently very low. Our Q2 activity will largely be directed to continued Montney development, including the equip and tie-in of eight (8.0 net) UCR wells and the workover and recompletion of heavy oil wells which are attracting a wellhead oil price of over C$65 per bbl based on current oil prices.
  
  
• Based on our first half capital program, Crew anticipates directing approximately $28 to $32 million to the second half program, which anticipates two net Montney completions, drilling three multi-lateral heavy oil wells and other minor expenditures.

____________________
^1,2	See "Information Regarding Disclosure on Oil and Gas Reserves, Operational Information and Non-IFRS Measures".

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 Reserves, Operational Information and Non-IFRS Measures

Unless otherwise specified, all reserves volumes and associated net present values of future net revenue for the Company's reserves disclosed in this press release are based on "company gross reserves" using forecast prices and costs and are derived from the Company's independent reserves evaluation prepared by Sproule Associates Ltd. ("Sproule") with an effective date of December 31, 2018 (the "Sproule Report").  The recovery and reserve estimates provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.  It should not be assumed that the estimates of net present value of future net revenues presented herein represent the fair market value of the reserves.  Actual reserves may be greater than or less than the estimates provided.  In relation to the disclosure of estimates for individual wells or properties, such estimates may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.  Estimates provided in respect of NPV10 before tax for Crew's UCR wells at West Septimus are based on Sproule's year-end 2018 type wells for West Septimus. The Company's oil and gas reserves statement for the year ended December 31, 2018 includes complete disclosure of our oil and gas reserves and other oil and gas information prepared in accordance with NI 51-101 and the COGE Handbook, and is contained within our Annual Information Form which is available on our SEDAR profile at www.sedar.com.

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" 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 Q2 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; as to estimates of net present value and expectations that the Company's UCR wells will generate internal rates of return of over 70%; as to the Company's estimates that its UCR wells will pay out in approximately 12 – 18 months at current prices; the estimated volumes, including shut-ins, and product mix of Crew's oil and gas production; production estimates including Q2 and 2019 average production targets; Crew's forecast base decline profile moving towards 12%; commodity price expectations including Crew's estimates of natural gas pricing exposure; 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 representing over ten years of economic growth; 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 Septimus and West Septimus areas ("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 Management's Discussion and Analysis for the three month periods ended March 31, 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 C.E.O., Phone: [phone], John Leach, Senior Vice President and C.F.O., Email: [email protected]

Related Links

http://www.crewenergy.com