CALGARY, ALBERTA–(Marketwired – May 8, 2017) – 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, 2017, along with an updated independent Montney Resource Evaluation. Our Financial Statements and Notes, as well as Management’s Discussion and Analysis (“MD&A”) for the three month period ended March 31, 2017 are available on Crew’s website and filed on SEDAR.
- Production for the quarter averaged 23,231 boe per day, 4% higher than the previous quarter primarily attributable to an 8% increase in liquids-rich natural gas production from northeast British Columbia (“NE BC”).
- Funds from operations totaled $27.7 million in the first quarter, more than double the same period in 2016, and increased 125% on a per share basis to $0.18 per share from $0.08 per share in Q1 2016.
- Benchmark prices increased for all products resulting in stronger revenues, while our continued focus on cost control contributed to operating netbacks that averaged $17.16 per boe compared to $9.13 per boe in the first quarter of 2016.
- At our liquids-rich Septimus and West Septimus (“Greater Septimus”) area, operating costs were 25% lower than Q1 2016 at $3.34 per boe while transportation costs were 24% lower at $1.67 per boe, contributing to an operating netback of $19.41 per boe.
- Crew closed a $300 million senior debt financing in March, 2017 and exited the quarter undrawn on our re-confirmed $235 million bank credit facility, affording the Company ample financial flexibility to execute on our longer-term, Montney-focused development strategy.
- In NE BC, drilled 11 wells and completed five wells, and at Lloydminster, drilled four wells and completed two wells, and currently have an inventory of 20 drilled and uncompleted wells, 18 of which are in Greater Septimus and Groundbirch.
- Continued the advancement of Crew’s Montney development plan with site work on the West Septimus facility expansion to 120 mmcf per day and the acquisition of 10 contiguous sections of surface rights that will accommodate the planned Groundbirch facility and the drilling of a minimum of 150 wells.
- Subsequent to the end of the quarter, we entered into an Agreement of Purchase and Sale for the disposition of non-core assets in the Goose area of NE BC comprised of approximately 18,400 net acres of undeveloped land with no production or assigned reserves for $49 million (subject to certain closing adjustments and costs). The transaction is expected to close prior to the end of the second quarter, subject to customary closing conditions.
- Updated Crew’s independent Montney Resource Evaluation which reflected a 2% increase to the risked Best Estimate Economic Contingent Resource (“ECR”) assessment to 9.2 TCFE and a modest increase to the Total Petroleum Initially In Place (“TPIIP”) estimate to 112.2 TCFE (prior to the Goose disposition). Continued annual increases in our resource estimate demonstrates the value in Crew’s ongoing Montney-focused drilling and development strategy to realize significant long-term value through reserves additions from this massive resource.
|FINANCIAL & OPERATING HIGHLIGHTS:|
($ thousands, except per share amounts)
March 31, 2017
March 31, 2016
|Petroleum and natural gas sales||57,298||36,343|
|Funds from operations(1)||27,719||11,714|
|Net income /(loss)||8,056||(6,795||)|
|Exploration and Development expenditures||75,164||17,763|
|Property acquisitions (net of dispositions)||(352||)||956|
|Net capital expenditures||74,812||18,719|
March 31, 2017
Dec. 31, 2016
|Working capital deficiency(2)||8,588||10,006|
|Senior Unsecured Notes||293,046||147,329|
|Total Net Debt||301,634||245,371|
|Current Debt Capacity(3)||535,000||385,000|
|Common Shares Outstanding (thousands)||147,127||146,812|
|(1)||Funds from operations 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. Funds from operations is used to analyze the Company’s operating performance and leverage. Funds from operations does not have a standardized measure prescribed by International Financial Reporting Standards 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.|
|(2)||Working capital deficiency includes cash and cash equivalents plus accounts receivable less accounts payable and accrued liabilities.|
|(3)||Current Debt Capacity reflects the newly approved bank facility of $235 million plus $300 million in senior unsecured notes outstanding.|
March 31, 2017
March 31, 2016
|Light crude oil (bbl/d)||530||303|
|Heavy crude oil (bbl/d)||1,857||2,799|
|Natural gas liquids (bbl/d)||3,363||3,359|
|Natural gas (mcf/d)||104,887||104,224|
|Total (boe/d @ 6:1)||23,231||23,832|
|Average prices (1)|
|Light crude oil ($/bbl)||59.74||37.34|
|Heavy crude oil ($/bbl)||42.93||20.45|
|Natural gas liquids ($/bbl)||45.71||25.95|
|Natural gas ($/mcf)||3.54||2.34|
|Oil equivalent ($/boe)||27.40||16.76|
|(1)||Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.|
March 31, 2017
March 31, 2016
|Realized commodity hedging gain/(loss)||(0.39||)||2.21|
|Operating netback (1)||17.16||9.13|
|Interest on long-term debt||(2.41||)||(1.98||)|
|Funds from operations||13.25||5.39|
|Working interest wells||15.0||4.0|
|Success rate, net wells (%)||93||%||100||%|
|(1)||Operating netback equals petroleum and natural gas sales including realized hedging gains and losses on commodity contracts less royalties, operating costs and transportation costs calculated on a boe basis. Operating netback and funds from operations netback do not have a standardized measure prescribed by International Financial Reporting Standards 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.|
During the first three months of 2017, activity levels increased across the Western Canadian Sedimentary Basin in response to frozen ground conditions and an improved commodity price environment. This resulted in a tight supply-demand dynamic for field services, particularly reservoir stimulation. Crew was able to complete five of a planned ten wells in the quarter and as a result underspent our forecasted first quarter budget by deferring these operations until after spring break up. Our production of 23,231 boe per day was at the lower end of our guidance range for the quarter and is reflective of these service delays. Work on the expansion of our West Septimus facility to double throughput capacity continued in the quarter, and is currently ahead of schedule, with commissioning of the expanded facility currently planned for the fourth quarter of 2017.
We continued to move forward on Crew’s long term growth plan by successfully closing a $300 million senior note financing, which has a 6.5% coupon and a term through March, 2024. This financing has positioned Crew with $535 million of total credit capacity and enhances our ability to manage through continued commodity price volatility for an extended period. Upon the closing of this financing, we repaid the balance on our $235 million credit facility, resulting in an undrawn bank facility, and after the end of the quarter, the credit facility was approved for extension at the same level. Subsequent to quarter end, we entered into an agreement to dispose of our non-core Goose property in NE BC for proceeds of approximately $49 million. Upon closing, which is expected prior to the end of the second quarter, we will have monetized a portion of our asset base that was not within Crew’s long-term development horizon.
MONTNEY RESOURCE EVALUATION UPDATE
Crew is pleased to report the results of its annual updated independent Montney resource evaluation conducted by Sproule Associates Ltd. (“Sproule”) on our principal NE BC Montney lands including Septimus, West Septimus, Groundbirch / Monias, Attachie and Tower as well as other minor NE BC Montney lands, effective December 31, 2016 (the “Resource Evaluation”). Sproule performed detailed mapping across the evaluated areas which included section by section estimates of reservoir parameters, such as pressure, temperature, porosity, and water saturation, which make up the TPIIP determination. At 112.2 TCFE, Crew’s TPIIP estimate provides the Company with significant opportunities to continue increasing the current ECR estimates plus add reserves with further drilling. Crew’s risked best estimate ECR on natural gas increased 3% to 7.7 Tcf, natural gas liquids (“ngl”) risked best estimate ECR was 1% higher at 227 million barrels, while our crude oil risked best estimate ECR decreased by 2 million bbls to 21 million bbls. All numbers referenced from the Resource Evaluation are prior to the pending disposition of Crew’s Goose asset.
The updated Resource Evaluation demonstrates the significant potential of our lands, offering multiple years of future running room and significant value creation opportunities. Although the play remains in its early stages of development, with new and enhanced drilling and completions techniques, Crew and other area operators continue to further delineate and de-risk the potential of this massive play and demonstrate results from the Montney that continue to improve.
Crew’s first quarter funds from operations of $27.7 million was consistent with the previous quarter but 137% higher than the first quarter of 2016, reflecting stronger year over year commodity prices, and operating and transportation costs that were 17% and 9% lower, respectively. We continue to see compelling returns from Greater Septimus, where our first quarter operating netback from the area was $19.41 per boe compared to $17.16 per boe corporately, reflecting the strong economics and returns generated in our core Montney operating areas.
Crew’s realized light oil price improved by 60% in the first quarter of 2017 over the first quarter of 2016, while our heavy oil price increased 110% and our ngl prices were 76% higher than the same period in 2016. Improved first quarter oil and ngl prices were the result of improved world oil prices prompted by OPEC’s (Organization of Petroleum Exporting Countries) decision to limit production in the first half of 2017 in order to reduce global inventories. This action stabilized world oil prices late in 2016 resulting in a 50% improvement in Crew’s Canadian dollar denominated WTI benchmark price. Higher oil prices also supported stronger demand and pricing for the condensate, propane and butane that make up Crew’s ngl mix. Crew’s realized natural gas price increased 51% over Q1 of 2016 as a result of stronger North American natural gas prices. Natural gas prices were supported by lower supply related to reduced capital investment and lower inventories resulting from warmer 2016 summer weather, liquefied natural gas exports from the U.S. gulf coast and increased U.S. exports to Mexico.
First quarter 2017 capital expenditures totaled $75 million which included the drilling of eleven Montney wells and four heavy oil wells. Operations during the quarter also included the completion of five Montney wells and two heavy oil wells. Drilling and completion expenditures for the quarter were $10 million lower than budgeted as a lack of available completion services restricted the first quarter program to five of a planned ten Montney completions. During the quarter we also continued with the expansion of our West Septimus facility from 60 mmcf per day to 120 mmcf per day. Major equipment fabrication was ahead of schedule resulting in $14.1 million charged to the expansion which represents an additional $5 million of capital accrual towards the project in the quarter.
Consistent with our efforts to maintain a strong balance sheet, control costs, and ensure liquidity to execute our strategy, on May 1, 2017 Crew entered into a new arrangement resulting in the replacement of one of the partners in our Septimus Gas Processing Complex (comprised of the Septimus and West Septimus facilities). This new arrangement will not impact Crew’s current 28% ownership or operatorship of the complex, while the other remaining partner retains a 22% ownership and the new partner a 50% ownership. This change to the arrangement will save the Company approximately $1 million per year on processing costs associated with the current complex further reducing overall Greater Septimus operating costs. As part of this arrangement, the new partner has agreed to fund 50% of the current West Septimus facility expansion. Crew has retained the option to buy both partners’ interest in these facilities at future dates.
On March 14, 2017, Crew closed an offering of $300 million aggregate principal amount of 6.5% senior unsecured notes due March 14, 2024. Proceeds from the note offering were partially used to redeem Crew’s $150 million, 8.375% senior unsecured notes due 2020, with the excess proceeds used to repay indebtedness under our credit facility and for the continued development of our Montney assets. Successful completion of this offering enhances Crew’s liquidity and financial flexibility. Total net debt at the end of the quarter was $301.6 million, including working capital deficiency and our new $300 million ($293.0 million net of deferred financing costs) 6.5% senior unsecured notes that have a seven year term with repayment due in March of 2024. The Company also recently completed our annual bank facility review with the facility renewed at the same level of $235 million. The pending disposition of our non-core Goose asset will further contribute to our flexibility and add cash to our balance sheet.
TRANSPORTATION, MARKETING & HEDGING
Crew’s realized natural gas price has outperformed the benchmark indices for the last six quarters, which demonstrates the value of our active marketing and hedging program, diversified sales markets as well as the 19% higher heat content of our natural gas over industry standards. One of the many advantages of our Montney land base is that we are situated with access to all three major export pipeline systems which provides substantial market and operational optionality. During the first quarter, our natural gas sales portfolio was allocated 45% to Chicago City Gate, 26% to AECO, 19% to Alliance ATP and 10% to Station 2. Crew will continue to plan for processing and transportation diversification that is timed to coincide with our longer term growth strategy, and afford us the ability to access new markets. Our transportation arrangement on the Spectra pipeline increased from 13 mmcf per day to 30 mmcf per day effective April 1, 2017. In the second quarter of 2018, we also secured 60 mmcf per day of capacity on the TransCanada pipeline system (“TCPL”), affording improved market diversity for natural gas from our Greater Septimus and Groundbirch areas. In mid-2019, we have also secured an additional 60 mmcf per day of firm capacity on the TCPL system.
In the interests of managing our commodity price risk and exposure, Crew continued to systematically add 2017 and 2018 hedges during the first quarter. For the balance of 2017, Crew’s total natural gas hedged position is approximately 50% of our forecast 2017 gas sales at a transportation-adjusted equivalent price of $2.92 per gj, which when adjusting for the higher heat content of Crew’s gas, equates to $3.62 per mcf. For liquids, we have approximately 50% of our 2017 light oil and natural gas liquids sales hedged at an average price of CDN$68.17 per bbl.
NE BC Montney – Greater Septimus Overview
During the first quarter, Crew continued to focus on drilling and completions activities primarily at our Greater Septimus area, while advancing our West Septimus facility expansion. We directed the majority of our first quarter capital to our Greater Septimus, including $14.1 million allocated to the doubling of our West Septimus processing facility from 60 mmcf per day to 120 mmcf per day. In addition, Crew drilled ten (10.0 net) Montney wells and completed three (3.0 net) Montney wells of our budgeted eight well Greater Septimus completions program in the quarter.
Crew continued to see efficiency improvements in the first quarter as the first five wells drilled off the 4-22 pad achieved a record low average 12.6 drilling days per well at an average well cost of $1.5 million, contributing to strong capital efficiencies and supporting returns. Following up on the success of our first two ultra condensate-rich wells, we spud the first well on a six well pad directly offsetting the 7-30 wells which continue to exceed expectations.
Late in 2016, industry activity increased significantly in NE BC, particularly the demand for reservoir stimulation services. All industry participants, including Crew, have been subject to scheduling challenges with service companies. The delays Crew experienced with completions in turn delayed new production volumes coming on-stream in the quarter. These delays reduced capital expenditures for completions by approximately $10 million in Q1 relative to our budget, which were partially offset by the West Septimus facility expansion running ahead of schedule.
Crew’s geographic location in the Montney has typically provided year round access to conduct our drilling and completions operations, or at worst, resulted in modest delays during spring break-up. For the first time in Crew’s operational history in the Montney, we were forced to completely shut down these activities in the middle of April. This year’s spring break up was a ‘perfect storm’ of an initial spring thaw, complicated by a significant period of cool, snowy weather which led to extremely poor road conditions and resultant road bans. Given the circumstances, and an emphasis on prioritizing our capital efficiencies, Crew has adjusted our operational plan to incorporate an extended spring break-up period during which no drilling or completions activity will be undertaken until June. Crew currently has three drilling rigs sitting on Crew leases, a significant inventory of 18 wells drilled and uncompleted in NE BC and has made arrangements to secure necessary equipment and services to complete the wells once access to our well sites is available.
|Production & Drilling||Q1
|Average Daily Production (boe/d)||17,440||17,307||18,592||17,131||18,149|
|Wells drilled (gross / net)||10 / 10.0||8 / 7.7||8 / 7.0||–||4 / 4.0|
($ per boe)
|Realized commodity hedge (loss)/gain||(0.41||)||(0.39||)||1.11||3.24||1.34|
First quarter production at Greater Septimus averaged 17,440 boe per day, representing approximately 76% of the Company’s total production volumes. Greater Septimus operating netbacks of $19.41 per boe were the highest in the past five quarters, due to increased revenue, and supported by low operating costs of $3.34 per boe and $1.67 per boe transportation costs, which have been kept stable despite inflationary pressures as industry activity levels increase.
Crew’s ultra condensate-rich area is the Company’s new focus for development at Greater Septimus. Results from area wells at the 7-30 pad are compelling in the current environment, including C7-30 which has produced 70,000 bbls of condensate in 220 days on production with an average condensate gas ratio (“CGR”) of 187 bbls per mmcf, and B7-30 which has produced 40,000 bbls of condensate over 165 days with an average CGR of 133 bbls per mmcf.
Three new well completions at Septimus in late 2016 have resulted in record well performance at an all-in average well cost of $3.8 million. Over a 123 day period, the wells each produced 0.8 bcf of natural gas with a well head condensate yield of 19 bbls per mmcf and have continued to produce at a current average rate of 4.7 mmcf per day per well.
NE BC Montney – Groundbirch overview
Crew spud the first of two delineation wells at Groundbirch that will employ the latest completion technology as part of further delineating our significant Groundbirch resource (which represents 18.7 TCFE of TPIIP in our Resource Evaluation) and in preparation for development drilling in 2018 as part of our long-term growth plan. The Company also acquired ownership of 10 sections of surface rights at Groundbirch on which we have planned the construction of a gas plant and associated Montney development of a minimum of 150 wells. Ownership is expected to reduce surface lease costs, improve access and timing of operations, provide access to a major rail line for potential trans-load capability in addition to providing access to proprietary gravel for lease and road maintenance and construction.
NE BC Montney – Tower overview
Crew’s Montney Tower area continues to represent significant future development opportunity for the Company as crude oil prices strengthen. We realized increased oil production at Tower in Q1 as a result of successfully completing two light oil wells in the fourth quarter of 2016 and two light oil wells in the first quarter of 2017. These four wells were drilled in 2014 prior to the collapse in oil prices, and were designed to be completed using plug and perf technology, which has been the predominant completion technique within the light oil window of the Montney relative to the then available open-hole completion technology. The first two wells have been on production for 60 and 80 days at average rates of 365 and 600 boe per day, with 53% and 64% liquids, respectively. The second two wells were completed late in the first quarter and achieved average rates of 445 and 520 boe per day, with 55% and 58% liquids over 35 and 60 days, respectively. In both sets of wells, the stronger of the two was placed in Crew’s “Upper B” interval of the upper Montney while the other two wells tested the deeper Montney “C” stratigraphic interval of the upper Montney. All four wells presently flow without the aid of artificial lift. Crew has also undertaken the first stage of facility modifications to install gas lift which we believe will allow us to further optimize fluid production rates from these wells.
Lloydminster, AB/SK overview
At Lloydminster, Crew drilled four (4.0 net) oil wells including two dual-leg horizontal wells, completed two (2.0 net) wells and recompleted four (3.5 net) oil wells in the quarter. Production at our Lloydminster heavy oil property averaged 1,865 boe per day in the first quarter of 2017 which reflects minimal impact from the drilling and completion operations, and is part of the Company’s plan to maintain heavy oil production in the range of 2,000 boe per day. The two completions were vertical wells in the Swimming area (Sparky formation) and the Wildmere area (Colony formation). The wells were placed on production in early March and by mid-April were producing at a combined average rate of 220 bbls of oil per day. Crew’s two dual leg horizontal wells also located in the Swimming area are expected to be completed when road ban restrictions are removed.
Crew has assembled a sizeable and uniquely situated land base of 474 net sections (prior to the impact of the pending Goose disposition) which offers exposure to condensate-rich natural gas and light oil. The intrinsic value of Crew’s acreage coupled with owned and operated facilities and infrastructure, firm transportation arrangements, a diversified marketing strategy, a strong balance sheet and a returns-focused strategy provide the foundation for long-term profitable growth and value creation. Under our current plan, we expect to exit 2017 in a strong financial position with an estimated debt to annualized fourth quarter 2017 funds from operations ratio of 1.5 times. Given these strengths, we believe our share price does not always reflect the underlying value of Crew’s assets and as such, the Company intends to apply to implement a normal course issuer bid (“NCIB”) through the facilities of the Toronto Stock Exchange (the “TSX”) and alternative Canadian trading platforms, pursuant to which Crew would have the ability to repurchase, from time to time, our outstanding shares for cancellation. This NCIB is expected to commence later in May following application being made to, and approved by, the TSX and will terminate one year later.
Exiting the first quarter, Crew has an inventory of 18 drilled but uncompleted wells that we intend to complete in order to bring on new volumes, and will continue to time our completions to ensure new volumes come on-stream with the commissioning of our West Septimus facility expansion. In the interests of creating value for our shareholders, we remain focused on return-on-capital in the development of our assets. Crew’s activity levels can be scaled back in a weak market to preserve our valuable reserves. We believe in the potential of our Montney assets, and are excited by the results from the ultra condensate-rich area which offers attractive economics in the current environment. Additional improvements in well results will be pursued through enhanced completions, while striving to improve operational efficiencies. With stronger financial liquidity, proceeds from the pending sale of Goose and the $300 million note offering, we are well positioned to continue executing our Montney focused strategy over the near and longer-term.
We have revised our capital planning based on the previously referenced delays, with our projected second quarter capital program reduced by approximately $30 million to between $25 and $35 million. Production additions will be heavily weighted to the fourth quarter, concurrent with the commissioning of our West Septimus plant expansion. Also, during the second quarter of 2017, the third-party McMahon gas processing facility will be shut down for an estimated 21 days, which will impact Crew’s volumes by approximately 900 boe per day in the second quarter. This shut down, combined with the production delays caused by the extended spring break-up, results in second quarter 2017 production estimates of approximately 20,000 to 21,000 boe per day. We anticipate that Q3 and Q4 2017 production will average between 24,500 to 26,500 boe per day, and 29,500 to 31,500 boe per day, respectively, spending approximately $100 million in the last half of 2017. Accordingly, our 2017 annual production guidance is reduced by 4% to 24,000 to 26,000 boe per day, with a positive impact to our forecast 2017 exit rate, which is increasing to over 31,000 boe per day while our $200 million capital budget remains unchanged.
We are very pleased to have secured additional financial flexibility, and have a high-quality asset base that only continues to improve with time and technology. We would like to thank our employees and Board of Directors for their commitment to Crew, and our shareholders for their ongoing support through ongoing market challenges.
A summary of Crew’s operational and financial highlights are as follows:
|2017 Average production(1)||24,000 – 26,000 boe/d|
|2017 Exit production(1)||>31,000 boe/d|
|Total proved + probable reserves(2)||324 MMboe|
|Total proved + probable BT NPV10(2)||$2 billion|
|Resource TPIIP(3)||112.2 TCFE|
|Montney potential drilling locations(4)||5,782|
|2017 Capital program(1)||$200 MM|
|Net debt(5)||$301.6 MM|
|Exit 2017 net debt / funds from operations(1)||~1.5x|
|Basic shares outstanding(5)||147.1 MM|
|Tax pools(5)||approx. $1 billion|
|(1) Forecast. See “Forward Looking Information and Statements”|
|(2) Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests). Information presented herein in respect of reserves and related information is based on our independent reserves evaluation for the year ended December 31, 2016 prepared by Sproule Associates Limited (“Sproule”) details of which were provided in our press release issued on February 9, 2017.|
|(3) As per the Resource Evaluation as at December 31, 2016 prepared by Sproule in accordance with the NI 51-101 and current COGE Handbook guidelines|
|(4) Potential drilling locations are the total number of risked Contingent (2,071) and Prospective (3,355) resource locations as identified in Crew’s year end independent Resource Evaluation plus the 2P booked locations (356) as identified in the independent reserves evaluation for the year ended December 31, 2016, both of which were prepared in accordance with the COGE Handbook provisions and NI 51-101|
|(5) As at March 31, 2017|
DECEMBER 31, 2016 RESOURCE EVALUATION
The following discussion in “Crew Northeast British Columbia Montney Resource Evaluation” is subject to a number of cautionary statements, assumptions and risks as set forth therein. See “Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information” at the end of this release for additional cautionary language, explanations and discussion, and see “Forward-looking Information and Statements” for a statement of principal assumptions and risks that may apply. See also “Definitions of Oil and Gas Resources and Reserves” in this news release. The discussion includes reference to TPIIP, DPIIP and ECR as per the Resource Evaluation as at December 31, 2016, prepared in accordance with the NI 51-101 and current COGE Handbook guidelines. Unless otherwise indicated in this news release, all references to ECR and prospective volumes are Best Estimate ECR and Best Estimate prospective volumes, respectively. All information referenced in the Resource Evaluation is prior to the pending disposition of Crew’s Goose area, expected to close in the second quarter of 2017.
In accordance with NI 51-101 Crew’s contingent resources have been subclassified into specified project maturity subclasses. Those that apply to Crew’s resources include “development pending”, “development on hold”, and “development not viable”. Sproule considers the ‘development pending’ and ‘development on hold’ project maturity subclasses to be economic and are therefore included in ECR. The economic status of the ‘development not viable’ project maturity subclass is undetermined and is therefore not included in the ECR reported. The “development not viable” sub-classification represented less than 2% of the sum of all three sub-classifications on a BOE basis, and accordingly, has not been considered to be material for reporting purposes. Crew does not have any resources within the “development unclarified” subclass.
CREW NORTHEAST BRITISH COLUMBIA MONTNEY RESOURCE EVALUATION
The Montney formation in NE BC has been identified as a world-class unconventional resource play with the potential for significant volumes of recoverable resources. The area includes dry gas, liquids-rich gas and light oil development opportunities, with Crew having access to all three hydrocarbon windows. It is one of the largest and lowest cost liquids-rich natural gas resource plays in North America and Crew’s land base comprises 300,000 net acres, ideally situated in some of the most prospective parts of the play, with good access to infrastructure and multiple egress options.
Sproule was engaged to conduct an updated independent Montney resource evaluation of Crew’s principal lands in the NE BC Montney region including Septimus, West Septimus, Groundbirch/Monias, Attachie, Tower and other minor NE BC Montney lands (the “Evaluated Areas”) effective as of December 31, 2016, and based on Sproule’s forecast price deck as at December 31, 2016 (the “Resource Evaluation”). The Resource Evaluation highlights the development potential on the Company’s undeveloped land base providing Crew with significant opportunities to progress conversion of Resource to ECR and ultimately to increased reserve bookings over time. Further, the diversity of Crew’s NE BC Montney assets with exposure to liquids-rich gas, crude oil and dry natural gas allows us to effectively navigate through commodity price cycles.
TPIIP for the natural gas-bearing lands in the Evaluated Areas remains unchanged relative to year end 2015 at 64.3 Tcf. Natural gas ECR was evaluated on an unrisked and risked basis in the Resource Evaluation and was subdivided into the Maturity Subclasses of ‘development pending’ and ‘development on hold’. The risked ‘development pending’ natural gas ECR totaled 7.3 Tcf and the risked ‘development on hold’ ECR totaled 0.43 Tcf, which includes 104 bcf of ‘development pending’ natural gas and 26 bcf of ‘development on hold’ natural gas on Crew’s oil-bearing lands.
The ECR of our ngl was also evaluated on an unrisked and risked basis in the Resource Evaluation and was subdivided into the Maturity Subclasses of ‘development pending’ and ‘development on hold’. The risked ‘development pending’ ngl ECR totaled 211 MMbbl and risked ‘development on hold’ ngl ECR totaled 16 MMbbl which includes 3 mmbbls of ‘development pending’ ngl and 1 mmbbls of ‘development on hold’ ngl on Crew’s oil-bearing lands.
On the oil-bearing Montney lands, TPIIP increased 1% to 7,979 MMbbl and DPIIP increased 2% to 1,647 MMbbl. Oil ECR was evaluated on an unrisked and risked basis in the Resource Evaluation and was subdivided into the Maturity Subclasses of ‘development pending’ and ‘development on hold’. The risked ‘development pending’ oil ECR totaled 17 MMbbl and risked ‘development on hold’ oil ECR totaled 4 MMbbl.
Risking of the contingent resources included a quantitative assessment of the contingencies applicable to the project including evaluation drilling, corporate commitment and timing of production and development. Risking of the prospective resources included a quantitative assessment of these same factors, as well as a quantitative assessment of the chance of discovery.
The following tables summarize the results of the Resource Evaluation along with comparatives to the December 31, 2015 evaluation using the resource categories set out in the COGE Handbook on a “best estimate” case.
|Conventional Natural Gas Resource Categories (1)(2)(3)(4)(5)(6)||Tcf||Tcf|
|Total Petroleum Initially In Place (TPIIP)||64.3||64.3||0|
|Discovered Petroleum Initially In Place (DPIIP)||35.2||35.2||0|
|Undiscovered Petroleum Initially In Place (UPIIP)||29.1||29.1||0|
|(1)||TPIIP, DPIIP and UPIIP have been estimated using a one percent porosity cut-off in the Resource Evaluation, which means that essentially all gas bearing rock has been incorporated into the calculations.|
|(2)||All volumes in table are Company gross and raw gas volumes.|
|(3)||Sproule’s analysis identified four intervals in the Montney consisting of one interval in the Upper Montney and three intervals in the Lower Montney.|
|(4)||Crew’s acreage was divided into five (5) areas in the “gas window”.|
|(5)||There is uncertainty that it will be commercially viable to produce any portion of the resources.|
|(6)||There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.|
|Light & Medium Crude Oil Resource Categories (1)(2)(3)(4)(5)(6)(7)||Mmbbls||Mmbbls|
|Total Petroleum Initially In Place (TPIIP)||7,979||7,895||1|
|Discovered Petroleum Initially In Place (DPIIP)||1,647||1,613||2|
|Undiscovered Petroleum Initially In Place (UPIIP)||6,332||6,282||1|
|(1)||TPIIP, DPIIP and UPIIP have been estimated using a one percent porosity cut-off in the Resource Evaluation, which means that essentially all oil bearing rock has been incorporated into the calculations.|
|(2)||All volumes in table are Company gross.|
|(3)||The oil volumes are quoted as Stock Tank Barrels (“STB”).|
|(4)||Sproule’s analysis identified four intervals in the Montney consisting of one interval in the Upper Montney and three intervals in the Lower Montney.|
|(5)||Crew’s acreage was divided into five (5) areas in the “oil window”.|
|(6)||There is uncertainty that it will be commercially viable to produce any portion of the resources.|
|(7)||There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.|
|2016 Reserves and Risked and Unrisked ECR(1)(2)(3)(6)(7)(8)||Chance of
|Conventional Natural gas (Bcf)|
|Development Pending ECR||87%||8,388||7,298|
|Development on Hold ECR||85%||500||425|
|NGL (Mmbbls) (4)(5)|
|Development Pending ECR||88%||240||211|
|Development on Hold ECR||84%||19||16|
|Light & Medium Crude Oil (Mmbbls)|
|Development Pending ECR||89%||19||17|
|Development on Hold ECR||80%||5||4|
|(1)||All DPIIP other than cumulative production, reserves, and ECR has been categorized as unrecoverable at this time. A portion of the Unrecoverable DPIIP may in the future be determined to be recoverable and reclassified as contingent resources or reserves as additional technical studies are performed, commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.|
|(2)||All volumes in table are company gross and sales volumes. Reserves and development pending volumes include economic cutoff.|
|(3)||For reserves, the volumes are proved plus probable reserves as at December 31, 2016.|
|(4)||The liquid yields are based on average yield over the producing life of the property.|
|(5)||Liquid yields are unique to each area. They are estimated based on gas composition of gas samples in the area and expected plant recoveries.|
|(6)||There is no certainty that it will be commercially viable to produce any of the resources.|
|(7)||All ECR are risked for the chance of development. For ECR, the chance of development is defined as the probability of a project being commercially viable. In quantifying the chance of development, contingencies that were assessed quantitatively to be less than one in the risking calculation included evaluation drilling, corporate commitment and timing of production and development. The chance of development is multiplied by the unrisked resource volume estimate, which yields the risked volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of development is an uncertain value that should be used with caution.|
|(8)||The economic status of the ‘development not viable’ project maturity subclass is deemed to be undetermined and is therefore not included in the ECR reported, representing, on a risked basis, 125 bcf of conventional natural gas, 2 mmbbls of ngl and 3 mmbbls of light and medium crude oil.|
An estimate of risked Net Present Value (“NPV”) of future net revenue of the development pending contingent resources subclass only is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of Crew proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to chance of development and cannot be classified as reserves until the contingencies are lifted. There is uncertainty that the risked NPV of future net revenue will be realized. The other subclasses of resources are not included in this NPV and therefore this is not reflective of the value of the resource base.
|Before-Tax NPV(1) 2016 Risked ECR Development Pending(2)||($ millions)|
|Discounted at 5%||6,447|
|Discounted at 10%||1,997|
|Discounted at 15%||693|
|Discounted at 20%||217|
|(1)||Based on the Resource Evaluation and Sproule’s forecast pricing at December 31, 2016 which is set forth in Crew’s press release dated February 9, 2017.|
|(2)||Risk in the above table is the chance of development. ECR are discovered resources by definition.|
|(3)||There is uncertainty that it will be commercially viable to produce any portion of the resources.|
The estimated cost to fully develop and bring on commercial production of the ‘development pending’ contingent resources for all three product types is approximately $11.2 billion (or approximately $3.0 billion discounted at 10%). The forecasted timeline to bring these resources onto production is between two and 17 years utilizing the same technology in horizontal drilling and multi-stage fracturing that Crew has already proven to be effective in the Montney formation in NE BC.
|Prospective Resources (1)(2)(3)(4)(5)(6)(7)||Chance of
|Conventional Natural Gas (Tcf)||66%||10,311||6,774|
|Light & Medium Crude Oil (MMbbl)||66%||149||98|
|(1)||All UPIIP other than prospective resources has been categorized as unrecoverable at this time.|
|(2)||All volumes in table are company gross and sales volumes.|
|(3)||The liquid yields are based on average yield over the producing life of the property.|
|(4)||Liquid yields are unique to each area. They are estimated based on gas composition of gas samples in the area and expected plant recoveries.|
|(5)||There is no certainty that any portion of the resources will be discovered. If discovered there is no certainty that it will be commercially viable to produce any of the resources.|
|(6)||Prospective resources are risked for the chance of discovery and the chance of development. For prospective resources, the chance of development multiplied by the chance of discovery is defined as the probability of a project being commercially viable. In quantifying the chance of commerciality, factors that were assessed quantitatively to be less than one in the risking calculation included evaluation drilling, corporate commitment and timing of production and development, along with the overall chance of discovery. The chance of commerciality is multiplied by the unrisked prospective resource volume estimate, which yields the risked volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of commerciality is an uncertain value that should be used with caution.|
|(7)||All prospective resources are subclassified as either the ‘prospect’ or ‘lead’ project maturity subclass.|
Resource volumes are estimated using volumetric calculations of the in-place quantities, combined with performance from analog reservoirs. The currently producing assets of Crew and other industry parties in the Montney area of NE BC are used as performance analogs for ECR within Crew’s areas of operations. The evaluation of ECR is based on an independent third party evaluation that assumes all of Crew’s ECR will be recovered using horizontal multi-stage hydraulic fracturing and multi-well pad drilling, which are established technologies.
Based upon the foregoing analysis and resource information, coupled with Crew’s expertise in the NE BC Montney, we anticipate that significant additional reserves will be developed in the future as we achieve continued drilling success on that portion of our Montney acreage which is currently undeveloped. Key positive factors considered in the Resource Evaluation estimates which support Crew’s view that significant additional resources will be recovered include completions enhancements; improved economic conditions; historic drilling success and recoveries on the more fully-developed Montney acreage; abundant well log and production test data; the presence of analogue wells in the area; improving average initial productivity trends; and the application of increased drilling densities. Continuous development through multi-year exploration and development programs and significant levels of future capital expenditures are required in order for additional resources to be recovered in the future.
Our ability to recover additional resources is subject to numerous risks and the key negative factors include minimal well data from the Montney formation in certain intervals; a lack of long-term production history in the Montney; potential for variations in the quality of the Montney formation where minimal well data currently exists; access to capital that would enable us to continue development; low commodity prices which could impact economics; the future performance of wells; regulatory approvals or surface restrictions; lack of infrastructure in certain areas; access to required services at the appropriate cost; overall industry cost structures; and the continued efficacy of fracture stimulation technologies and application. In order for ECR to be converted into reserves, Crew’s management and technical teams must continue to assess commercial production rates, devise firm development plans that incorporate timing, infrastructure and capital commitments. Confirmation of commercial productivity is generally required before the Company can prepare firm development plans and commit required capital for the development of the ECR. With continued development and delineation, some resources currently classified as ECR are expected to be reclassified as Reserves.
A key contingency that prevents the classification of ECR as Reserves is the additional drilling, completions and testing required to confirm viable commercial rates. Sproule assigned ECR beyond those areas which were assigned Reserves but which were within three miles of existing wells, or production tests. Further, a lack of infrastructure in the Evaluated Areas which is required to develop the resources, such as gas gathering, processing and natural gas liquids separation facilities, further impedes the reclassification of ECR to Reserves. In addition to these factors, and the general operational risks facing the oil and gas industry, there are several technical and non-technical contingencies that need to be overcome in order to reclassify ECR to Reserves. These include evaluation drilling, corporate commitment and timing of production and development of the ECR.
There is no certainty that any portion of the prospective resources will be discovered. There is uncertainty that it will be commercially viable to produce any portion of the prospective (if discovered) or contingent resources.
Definitions of Oil and Gas Resources and Reserves
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:
Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
Cumulative Production is the cumulative quantity of petroleum that has been recovered at a given date.
Resources encompasses all petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. “Total resources” is equivalent to “Total Petroleum Initially-In-Place”. Resources are classified in the following categories:
Total Petroleum Initially-In-Place (“TPIIP”) is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.
Discovered Petroleum Initially-In-Place (“DPIIP”) is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable.
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies.
Economic Contingent Resources (“ECR”) are those contingent resources which are currently economically recoverable.
Project Maturity Subclass Development Pending is defined as a contingent resource that has been assigned a high chance of development and the resolution of final conditions for development are being actively pursued.
Project Maturity Subclass Development On Hold is defined as a contingent resource that has been assigned a reasonable chance of development, but there are major non‐technical contingencies to be resolved that are usually beyond the control of the operator.
Project Maturity Subclass Development Unclarified is defined as a contingent resource that requires further appraisal to clarify the potential for development and has been assigned a lower chance of development until contingencies can be clearly defined.
Project Maturity Subclass Development not Viable is defined as a contingent resource where no further data acquisition or evaluation is currently planned and hence there is a low chance of development.
Undiscovered Petroleum Initially-In-Place (“UPIIP”) is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as “prospective resources” and the remainder as “unrecoverable.”
Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.
Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Uncertainty Ranges are described by the Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates for reserves and resources. The Best Estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information
All amounts in this news release are stated in Canadian dollars unless otherwise specified. Throughout this press release, the terms Boe (barrels of oil equivalent), Mmboe (millions of barrels of oil equivalent), and Tcfe (trillion cubic feet of gas equivalent) are used. Such terms when used in isolation, may be misleading. Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE and oil and liquids have been converted to natural gas equivalent on the basis of 1 bbl:6 mcfe. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip, and 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 the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties and without including any royalty interest, unless otherwise stated. Unless otherwise specified, all reserves volumes in this news release (and all information derived therefrom) are based on “company gross reserves” using forecast prices and costs. Our oil and gas reserves statement for the year-ended December 31, 2016 includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, and is contained within our Annual Information Form which is available on our SEDAR profile at www.sedar.com.
This press release contains metrics commonly used in the oil and natural gas industry, such as “operating netback”. Such terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Crew’s performance over time, however, such measures are not reliable indicators of Crew’s future performance and future performance may not compare to the performance in previous periods.
This news release contains references to estimates of oil and gas classified as TPIIP, DPIIP, UPIIP and ECR in the Montney region in NE BC which are not, and should not be confused with, oil and gas reserves. See “Definitions of Oil and Gas Resources and Reserves”.
Projects have not been defined to develop the resources in the Evaluated Areas as at the evaluation date. Such projects, in the case of the Montney resource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints, Crew’s policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view of Crew on oil and gas prices, the results of exploration and development activities of Crew and others in the area and possible infrastructure capacity constraints. As with any resource estimates, the evaluation will change over time as new information becomes available.
Crew’s belief that it will establish significant additional reserves over time with the conversion of DPIIP and prospective resource into contingent resource, contingent resource into probable reserves and probable reserves into proved reserves is a forward looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading “Forward Looking Information and Statements”.
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: the volume and product mix of Crew’s oil and gas production; production estimates including Q2, Q3, Q4 and annual 2017 forecast average production and 2017 exit rate; anticipated closing of the Goose asset disposition and the timing thereof; the volumes and estimated value of Crew’s resources and undeveloped land; the recognition of significant resources under the heading “Crew Northeast British Columbia Montney Resource Evaluation”; future oil and natural gas prices and Crew’s commodity risk management programs; future liquidity and financial capacity; future results from operations and operating metrics; anticipated reductions in operating costs, well costs and G&A expenditures and potential to improve ultimate recoveries and initial production rates; future costs, expenses and royalty rates; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration, acquisition and development activities and related capital expenditures and the timing thereof; the number of wells to be drilled, completed and tied-in and the timing thereof; the potential value of our undeveloped land base; the amount and timing of capital projects including facility expansions, commissioning and the timing thereof; the total future capital associated with development of reserves and resources; methods of funding our capital program, including possible non-core asset divestitures and asset swaps; and our intention to apply to the TSX to implement a normal course issuer bid and the timing thereof.
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: the impact of increasing competition; the general stability of the economic and political environment in which Crew operates; 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 and the adequacy of cash flow to fund its planned expenditures; 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; the ability of Crew to successfully market its oil and natural gas products. There are a number of assumptions associated with the potential of resource volumes and development of the Evaluated Areas including the quality of the Montney reservoir, future drilling programs and the funding thereof, continued performance from existing wells and performance of new wells, the growth of infrastructure, well density per section, and recovery factors and development necessarily involves known and unknown risks and uncertainties, including those identified in this press release.
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; the potential for variation in the quality of the Montney formation; changes in the demand for or supply of Crew’s products; 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 and resource 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 may not necessarily be indicative of long term performance or of ultimate recovery.
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 a 6:1 conversion basis may be misleading as an indication of value.
Crew Energy Inc. is a dynamic, growth-oriented exploration and production company, focused on increasing long-term production, reserves and cash flow per share through the development of our world-class Montney resource. Crew is based in Calgary, Alberta and our shares are traded on The Toronto Stock Exchange under the trading symbol “CR”.
Financial statements and Management’s Discussion and Analysis for the three month period ended March 31, 2017 and 2016 will be filed on SEDAR at www.sedar.com and are available on the Company’s website at www.crewenergy.com.
Crew Energy Inc.
President and C.E.O.
Crew Energy Inc.
Senior Vice President and C.F.O.
Crew Energy Inc.
Senior Vice President and C.O.O.