Crew Energy Inc. Announces First Quarter 2014 Financial and Operating Results and Updates Its Montney Resource Evaluation

Crew Energy Inc. Announces First Quarter 2014 Financial and Operating Results 
and Updates Its Montney Resource Evaluation 
CALGARY, ALBERTA -- (Marketwired) -- 05/07/14 --   Crew Energy Inc.
("Crew" or the "Company") (TSX: CR) of Calgary, Alberta is pleased to
present its operating and financial results for the three month
period ended March 31, 2014. 
Highlights  


 
 
--  Funds from operations in the first quarter increased 52% over the first
    quarter of 2013 and 8% over the prior quarter to $51.8 million while the
    funds from operations netback increased by 40%; 
--  Funds from operations per diluted share increased 50% over the first
    quarter of 2013 and increased 5% over the previous quarter to $0.42 per
    share; 
--  First quarter production was previously announced on April 9, 2014 and
    averaged 28,021 boe per day, an 8% increase over the same period in 2013
    and a 2% decrease from the previous quarter; 
--  Operating netbacks improved 55% over the first quarter of 2013 to $28.49
    per boe, before risk management losses, as a result of improved
    commodity prices and lower costs; 
--  Operating costs per boe decreased 6% over the same period in 2013 to
    $11.35 per boe; 
--  Crew completed and tied-in two wells at Septimus that are producing into
    the Company's gathering system averaging 1,200 boe per day and 1,180 boe
    per day (16% ngl); 
--  The Company updated its Montney Resource Evaluation which increased 20%
    to 109 TCFE of Total Petroleum Initially in Place ("TPIIP") and the
    Contingent Resource increased 44% to 5.0 TCFE; 
--  Crew added strategic production, reserves, land and infrastructure in
    northeast British Columbia acquiring 1,400 boe per day of production,
    8.5 million boe of proved plus probable reserves, 75 net sections of
    Montney rights and over 130 kilometers of pipelines and 6,000 hp of
    field compression for $105 million; 
--  Subsequent to the quarter end, Crew announced the disposition of
    approximately 7,000 boe per day of production concentrated in the Deep
    Basin area of Alberta, 254,000 net acres of land and 60.4 million boe of
    proved plus probable reserves for $222 million in cash plus
    approximately 400 boe per day of heavy oil production. 
 
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                                                Three months   Three months 
                                                       ended          ended 
Financial                                          March 31,      March 31, 
($ thousands, except per share amounts)                 2014           2013 
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Petroleum and natural gas sales                      130,368         91,267 
Funds from operations (note 1)                        51,810         34,188 
  Per share                                                                 
    - basic                                             0.43           0.28 
    - diluted                                           0.42           0.28 
Net loss                                            (129,693)       (22,047)
  Per share                                                                 
    - basic                                            (1.07)         (0.18)
    - diluted                                          (1.07)         (0.18)
 
Exploration and Development expenditures              66,140         65,252 
Property acquisitions (net of dispositions)          102,532         14,663 
                                              ------------------------------
Net capital expenditures                             168,672         79,915 
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                                                       As at          As at 
                                                   March 31,   December 31, 
Capital Structure ($ thousands)                         2014           2013 
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Working capital deficiency (note 2)                   53,121         40,098 
Net assets held for sale (note 3)                   (231,677)             - 
Bank loan                                            301,212        197,688 
                                              ------------------------------
                                                     122,656        237,786 
Senior unsecured notes                               145,785        145,623 
                                              ------------------------------
Total net debt                                       268,441        383,409 
 
Bank facility after closing of the Alberta Gas                              
 Disposition                                         350,000        420,000 
Common Shares Outstanding (thousands)                121,679        121,635 
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Notes:  


 
 
(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 charges. 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.              
(2)  Working capital deficiency shown above includes accounts receivable    
     less accounts payable and accrued liabilities.                         
(3)  Net assets held for sale reflects the amounts reclassified from        
     property, plant and equipment and decommissioning obligations for the  
     assets less liabilities associated with the Alberta Gas Disposition as 
     described below.                                                       
 
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                                                Three months   Three months 
                                                       ended          ended 
                                                   March 31,      March 31, 
Operations                                              2014           2013 
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Daily production (note 1)                                                   
  Princess and other oil (bbl/d)                       3,298          4,936 
  Lloydminster oil (bbl/d)                             6,128          5,441 
  Natural gas liquids (bbl/d)                          3,435          2,984 
  Natural gas (mcf/d)                                 90,959         75,597 
  Oil equivalent (boe/d @ 6:1)                        28,021         25,961 
Average prices (notes 1 & 2)                                                
  Princess and other oil ($/bbl)                       81.81          64.36 
  Lloydminster oil ($/bbl)                             69.50          50.61 
  Natural gas liquids ($/bbl)                          64.59          54.43 
  Natural gas ($/mcf)                                   5.84           3.42 
  Oil equivalent ($/boe)                               51.69          39.06 
Netback ($/boe)                                                             
  Revenue                                              51.69          39.06 
  Realized commodity hedging loss                      (3.47)         (0.55)
  Royalties                                           (10.63)         (7.41)
  Operating costs                                     (11.35)        (12.03)
  Transportation costs                                 (1.22)         (1.25)
                                              ------------------------------
  Operating netback (note 3)                           25.02          17.82 
  G&A                                                  (2.13)         (1.99)
  Interest on long-term debt                           (2.36)         (1.19)
                                              ------------------------------
  Funds from operations                                20.53          14.64 
 
Drilling Activity                                                           
  Gross wells                                             21             39 
  Working interest wells                                19.0           36.8 
  Success rate, net wells                                100%           100%
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Notes: 


 
 
(1)  Princess, Alberta oil (20 degree to 26 degree API oil) has historically
     been classified as medium or conventional oil. Effective December 31,  
     2012 Crew's reserves attributable to its Princess property have been   
     classified as heavy oil to accord with definitions in the royalty      
     regulations in Alberta. Princess and other oil production and pricing  
     are shown separately from Lloydminster heavy oil volumes for clarity   
     and comparison with historical classification.                         
(2)  Average prices are before deduction of transportation costs and do not 
     include gains and losses on financial instruments.                     
(3)  Operating netback equals petroleum and natural gas sales including     
     realized hedging gains and losses on commodity based financial         
     instruments 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.              

OVERVIEW 
Crew continued to execute on its corporate strategy in the first
quarter culminating in the closing of two separate transactions that
resulted in the Company acquiring certain strategic Montney liquids
rich natural gas properties in northeast British Columbia for
approximately $105 million (the "Montney Acquisition"). The acquired
assets include 75 net sections of land that are either contiguous
with existing Crew land or increase Crew's working interest in joint
interest lands. The acquired lands include production of 1,400 boe
per day of predominantly natural gas production and 8.5 million boe
of proved plus probable reserves. Subsequent to the end of the first
quarter, Crew entered into an agreement to sell certain petroleum and
natural gas assets including approximately 7,000 boe per day of 75%
natural gas production and 60.4 mmboe of proved plus probable
reserves focused primarily in the Deep Basin of Alberta (the "Alberta
Gas Disposition"). Consideration for the Alberta Gas Disposition will
include approximately $222 million in cash, before closing
adjustments, plus approximately 400 bbls per day of heavy oil
production. This disposition is scheduled to close on or about May
30, 2014, subject to satisfaction of customary industry closing
conditions. In conjunction with the announcement of these
transactions, the Company increased its 2014 capital budget to $285
million with the incremental $39 million directed exclusively to the
Company's Montney resource development and an acceleration of Crew's
Montney five year growth plan. 
As previously announced, Crew's first quarter production averaged
28,021 boe per day as the severe winter weather along with an unusual
number of wells temporarily shut-in due to third party drilling
operations in the Lloydminster area impacted volumes by approximately
1,000 boe per day. Toward the end of March, the majority of the
Company's 21 (19.0 net) wells drilled in the quarter came on
production resulting in the Company achieving field estimated
production rates of 30,400 boe per day in the month of April
(inclusive of the 1,400 boe per day acquired at the end of March)
consistent with budget expectations. During the first quarter,
exploration and development capital expenditures were $66.1 million
allocated $35.0 million to the northeast British Columbia Montney,
$15.4 million to Princess Mannville development, $13.8 million to
Lloydminster and $1.9 million to the Deep Basin and Other Alberta
areas. 
FINANCIAL 
Crew's first quarter funds from operations increased 8% over the
prior quarter and 52% over the same period in 2013 to $51.8 million
or $0.42 per diluted share. The Company's funds from operations
benefited from stronger oil and natural gas pricing experienced
during the quarter that were partially offset by a $8.7 million
realized loss on the Company's risk management program. The Company's
$130 million first quarter net loss was impacted by realized and
unrealized losses of $27.8 million incurred on the Company's risk
management program and a non-cash impairment charge of $153.5 million
on assets related to the Alberta Gas Disposition that have been
reclassified as held for sale. 
An extended cold winter across North America has reduced natural gas
storage levels to 52% below last year's level and 55% below the five
year gas storage average level. Natural gas prices continue to
reflect the reduced storage levels as the Company's realized natural
gas price increased 53% over the previous quarter to average $5.84
per mcf for the first quarter of 2014. Oil prices strengthened during
the quarter as the discount for Canadian heavy oil, measured as the
Western Canadian Select ("WCS") price differential to West Texas
Intermediate ("WTI"), narrowed to average CDN$25.55 per bbl as
compared to CDN$33.89 for the previous quarter. A number of positive
catalysts provided support for the increase in WCS oil prices
including increased crude-by-rail exports and increased rail loading
facilities and expansions scheduled for 2014.  
The Company's hedging strategy is focused on protecting against
significant declines in commodity prices that would negatively impact
the funds from operations needed to fund the Company's on-going
capital program. Strengthening commodity prices have significantly
affected Crew's realized and unrealized losses from its risk
management program in the first quarter of 2014. In the first
quarter, the Company incurred a realized hedging loss of $8.7 million
or $3.47 per boe as compared to $1.3 million or $0.55 per boe in the
same period in 2013. During the first quarter of 2014, the Company
also incurred unrealized losses on financial instruments of $19.0
million.  
The Company had a successful first quarter exploration and
development program which saw Crew spend $66.1 million focusing on
development of liquids rich natural gas from the Montney formation at
Septimus. Quarter-end net debt totaled $268 million which included a
reclassification of the Alberta Gas Disposition assets from property,
plant and equipment to current assets held for sale. Following the
closing of the Alberta Gas Disposition, the Company's bank facility
will be renewed at $350 million.  
OPERATIONS UPDATE 
Septimus/Tower, British Columbia 
Crew achieved the fourth consecutive quarter of production growth at
Septimus with average production of 10,140 boe per day and a March
average of 10,650 boe per day as new wells in the quarter were
brought on during the month and with the Septimus gas plant running
at 95% to 102% of projected capacity. With sub-$5 per boe operating
costs, an attractive and improving royalty structure and improved
pricing, the operating netback at Septimus has increased 62% to
$29.42 per boe compared to the first quarter of 2013 levels. The
Company projects that an annual capital program of $40 to $50 million
is required to maintain the Septimus gas plant at capacity and
combined with the current pricing environment this would result in
$40 to $50 million of annual free cash flow being generated from this
first phase of Crew's Montney development. Future economics have been
further enhanced with the announcement of a second tier to the
British Columbia Deep Well Credit Program effective April 1, 2014.
Based on this addition to the program the majority of Crew's Montney
liquids rich natural gas drilling program will now qualify resulting
in an increased NPV10 of approximately $0.8 million per well. 
During the quarter, Crew conducted a second production test on the
Montney oil exploration well drilled in the fourth quarter of 2013
located 11 kilometers northwest of the Company's existing Montney oil
production. Following an 80 day shut in period, the well was brought
back on production for an 11 day test during which it produced an
average of 540 barrels of oil per day and 1.1 mmcf per day of natural
gas for a total average rate of 723 boe per day. The well is expected
to be tied into Crew's gathering system in the third quarter. The
Company is planning to begin drilling its first well of a six well
pad at Tower in June. 
At Septimus, Crew drilled five (5.0 net) horizontal wells in the
quarter with two of the wells on production at 6 to 8 mmcf per day as
of the end of the quarter. With the evolution of the Company's
development strategy to pad drilling to capture additional cost
efficiencies, Crew is currently drilling the third well on a six well
pad which is expected to be completed in the third quarter and will
be brought on production following the planned turnaround at the
Septimus gas plant in August. A second rig is operating in the
Groundbirch area where the Company is drilling the second well on a
two well pad. These wells are expected to be completed and tested in
the third quarter along with one of the Attachie wells drilled in
2013. Crew also began ordering major equipment for the second
Septimus facility anticipated to be on stream mid-2015 with a
designed capacity of 60 mmcf per day of raw gas. 
Lloydminster, Alberta/Saskatchewan 
At Lloydminster, Crew drilled nine (7.6 net) oil wells and
recompleted 16 (15.1 net) wells for $10.8 million. Production for the
quarter averaged 6,150 boe per day and the Company is expecting to
maintain production in the 6,000 boe per day range throughout the
year with total capital expenditures of $35 million.  
Princess, Alberta 
During the first quarter, production at Princess averaged 3,950 boe
per day as the majority of the wells in the Company's first quarter
drilling program came on production early in the second quarter.
Current production is approximately 4,500 boe per day based on field
estimates with new wells still being optimized. Crew drilled six (6.0
net) wells with total capital expenditures of $14 million including
well optimizations. The first quarter drilling program targeted new
Mannville opportunities on the Company's Crown acreage and represents
the first phase of delineation of a number of these lands. Crew is
projecting to maintain production in the 4,000 to 4,500 boe per day
range throughout the year as the Company continues to delineate its
Mannville acreage. 
Deep Basin, Alberta 
Crew's Deep Basin and other minor Alberta properties produced an
average of 7,220 boe per day during the quarter. Crew has announced
an agreement to sell these assets pursuant to the Alberta Gas
Disposition with an anticipated closing date of May 30, 2014. 
OUTLOOK 
With the announced Alberta Gas Disposition, the Company revised
forecasted 2014 average production to 25,500 to 26,500 boe per day
and forecasts to exit the year at 26,000 to 27,000 boe per day,
subject to closing the disposition on May 30, 2014. Exploration and
development capital expenditures are now budgeted at $285 million, a
$39 million increase over the previous budget. Net debt after closing
of the transaction is forecasted to be approximately $280 million. 
For the remainder of 2014, Crew plans to: 


 
 
--  Continue to develop and delineate our Montney resource which is now over
    109 TCFE of TPIIP and 5.0 TCFE of Contingent Resource; 
--  Apply new and evolving drilling and completion technologies to improve
    Expected Ultimate Recoveries and initial production rates; 
--  Invest in Montney production infrastructure which is estimated at $35
    million in 2014 in addition to pre-drilling the majority of the 18 wells
    planned to initially fill the new 60 mmcf per day facility; 
--  Evaluate the Montney potential at Crew's Attachie, Groundbirch and
    Tower, British Columbia properties; 
--  Continue to high-grade our asset base and consolidate acreage in the
    Montney in northeast British Columbia; 
--  Maintain aggregate production levels at Lloydminster and Princess with
    free funds from operations to be distributed to our Montney growth
    initiatives. 

Our 2014 capital program has positioned the Company with an expanded
resource and drilling inventory, important infrastructure as well as
land that is strategic to our future growth plans. Crew's five year
growth plan anticipates the construction of facilities to process 240
mmcf per day of natural gas and 10,000 bbls per day of light oil with
targeted exit 2018 Montney production of approximately 45,000 boe per
day. 
We would like to thank our employees and Board of Directors for their
steadfast commitment to Crew's success and our shareholders for their
continued support. We are excited about our prospects and future and
look forward to reporting our second quarter operating and financial
results in August.  
NORTHEAST BRITISH COLUMBIA MONTNEY RESOURCE EVALUATION 
The following discussion in "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" for additional cautionary language,
explanations and discussion and "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". The discussion includes reference to TPIIP, DPIIP, UPIIP
and Contingent Resources per the Sproule Associates Ltd. ("Sproule")
Resources Evaluation effective as at April 30, 2014, prepared in
accordance with the Canadian Oil and Gas Evaluation Handbook ("COGE
Handbook"). Unless indicated otherwise in this news release, all
references to Contingent and Prospective Resource volumes are Best
Estimate Contingent and Prospective Resource volumes. 
Sproule was engaged to conduct an updated independent Montney
resource evaluation of Crew's 452 net Montney sections located in
Northeast British Columbia ("NEBC") (the "Evaluated Areas") effective
as of April 30, 2014 (the "Resource Evaluation"). The Resource
Evaluation confirms the development and resource potential on the
Company's land base providing us with significant opportunities to
add reserves above the current booked reserves and to increase the
current Contingent Resource. The commodity diversity of Crew's NEBC
Montney assets allow us to navigate through commodity price cycles
given the range of Crew's Montney landholdings with exposure to
liquids rich gas, crude oil and dry natural gas (gas containing
greater than 95% methane). The Resource Evaluation reaffirms Crew's
belief in the considerable potential that exists to further increase
our current reserve base, highlighting the world class potential of
the NEBC Montney. 
TPIIP in the Montney "gas window" increased to 60.6 TCF from 44.6 TCF
due to the Montney Acquisition completed in the first quarter. The
Resource Evaluation also included recognition of Crew's lands in the
Montney "oil window" where Crew has 138 net sections. On the oil
bearing lands, TPIIP increased from 7.8 billion barrels of oil to 8.1
billion barrels of oil. The tight Montney oil potential is in the
early stages of development and requires additional data to realize
the recoverable potential of these lands. The continued improvement
of technology and the early results are very encouraging to the
recovery of this vast resource. 
The Resource Evaluation that is presented below and the results we
have had at Septimus to date highlight the quality of the lands that
Crew has successfully acquired over the past six years. With the
improved economics of this play and the visibility of continued
development of infrastructure in the Septimus corridor we are
committed to continue to pursue opportunities in this region and it
is our intent to aggressively exploit the 60.6 TCF and 8.1 billion
barrels of TPIIP on our acreage in order to grow production, reserves
and cashflow into the future.  
The following tables summarize the results of the Resource
Evaluation. 


 
 
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Natural Gas Resource Categories (1)(2)(3)                                Tcf
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Total Petroleum Initially In Place (TPIIP)                              60.6
Discovered Petroleum Initially In Place (DPIIP)                         26.1
Undiscovered Petroleum Initially In Place (UPIIP)                       34.5
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(1)  All volumes in table are company gross and raw gas volumes.            
(2)  Sproule's analysis identified four intervals in the Montney consisting 
     of one interval in the Upper Montney and three intervals in the Lower  
     Montney.                                                               
(3)  Crew's acreage was divided into six (6) areas in the "gas window". Crew
     owns 276 net sections in the gas window at April 30, 2014.             
 
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Oil Resource Categories (1)(2)(3)(4)                                  Mmbbls
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Total Petroleum Initially In Place (TPIIP)                             8,052
Discovered Petroleum Initially In Place (DPIIP)                        1,363
Undiscovered Petroleum Initially In Place (UPIIP)                      6,689
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(1)  All volumes in table are company gross.                                
(2)  The oil volumes are quoted as Stock Tank Barrels ("STB").              
(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 "oil window".    
     Crew owns 138 net sections in the oil window at April 30, 2014.        
 
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                                                                        Best
Reserves and Contingent Resources (1)(2)(3)(6)(7)                   Estimate
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Natural gas (Tcf)                                                           
  Reserves (3)                                                           0.5
  Contingent Resources                                                   4.0
 
Natural gas liquids (Mmbbls) (4)(5)                                         
  Reserves (3)                                                          14.7
  Contingent Resources                                                 160.7
 
Oil (Mmbbls)                                                                
  Reserves (3)                                                           0.4
  Contingent Resources                                                  10.9
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(1)  All DPIIP other than cumulative production, reserves, and Contingent   
     Resources has been categorized as unrecoverable at this time.          
(2)  All volumes in table are company gross and sales volumes.              
(3)  For reserves, the volume under the heading Best Estimate are proved    
     plus probable reserves as at December 31, 2013.                        
(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)  Contingent Resources includes an 85% development factor.               
 
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                                                                        Best
Prospective Resources (1)(2)(5)(6)                                  Estimate
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Natural gas (Tcf)                                                        6.3
Natural gas liquids (Mmbbls) (3)(4)                                    254.4
Oil (Mmbbls)                                                            14.4
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(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 it will be commercially viable to produce   
     any of the resources.                                                  
(6)  Prospective Resources includes an 85% development factor.              

Based upon the foregoing analysis and Crew's expertise in the Montney
formation in NEBC, it is expected that significant additional
reserves will be developed in the future with continued drilling
success on currently undeveloped Montney acreage together with
further development, completion refinements and improved economic
conditions. Additional drilling, completion, and test results are
required before Crew can commit to development and these contingent
resources can be converted to reserves and a larger component of
Prospective Resources is converted to Contingent Resource. 
The Prospective Resources have not been risked for chance of
discovery. There is no certainty that any portion of the Prospective
Resources will be discovered. There is no certainty that it will be
commercially viable to produce any portion of the Prospective (if
discovered) or Contingent Resources. The Contingent Resource
contingencies are identified as economic or non-technical, there are
no technical contingencies. Crew anticipates that a large portion of
the Contingent Resources will be economically viable to develop.
Significant positive factors are historic drilling success and
production history on the more fully developed Montney acreage,
abundant well log and production test data. Potential negative
factors include lack of long term production history over the
majority of Crew lands, lack of infrastructure, potential for
variations in the quality of the Montney formation where minimal well
data currently exists, access to the substantial amount of capital
which would be required to develop the resources, low commodity
prices that would curtail the economics of development and the future
performance of wells, regulatory approvals, access to the required
services at the appropriate cost and topographic or surface
restrictions. 
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.  
Possible Reserves are those additional reserves that are less certain
to be recovered than probable reserves. It is unlikely that the
actual remaining quantities recovered will exceed the sum of the
estimated proved plus probable plus possible 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. Contingencies may
include such factors as economic, legal, environmental, political and
regulatory matters or a lack of markets. It is also appropriate to
classify as Contingent Resources the estimated discovered recoverable
quantities associated with a project in the early evaluation stage. 
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, 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, 2013 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 news release contains references to estimates of proved plus
probable reserves attributed to the assets acquired by the Company
pursuant to the Montney Acquisition. Such reserves reflect Company
internally estimated "gross" reserves prepared by a qualified
reserves evaluator effective December 31, 2013 in accordance with the
definitions and provisions contained in the COGE Handbook. Estimates
of proved plus probable reserves contained herein attributed to the
assets being disposed of pursuant to the Alberta Gas Disposition
reflect "gross" reserves assigned by the Company's independent
reserves evaluator, Sproule Associates Limited, effective December
31, 2013.  
This news release contains references to estimates of oil and gas
classified as TPIIP, DPIIP, UPIIP and Contingent Resources in the
Montney region in northeastern British Columbia which are not, and
should not be confused with, oil and gas reserves. See "Definitions
of Oil and Gas Resources and Reserves". TPIIP, DPIIP and UPIIP have
been estimated using a zero percent porosity cutoff. 
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 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 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". 
Cautionary 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: completion of
the Alberta Gas Disposition and the timing thereof and anticipated
benefits to be derived therefrom; the effect of the Alberta Gas
Disposition on continuing operations and plans to expand the 2014
capital program on a post-transaction basis; forecasted net debt
after closing of the Alberta Gas Disposition; the volume and product
mix of Crew's oil and gas production; production estimates including
2014 forecast average and exit productions; the recognition of
significant resources under the heading "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 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 amount
and timing of capital projects including anticipated timing of the
new Septimus facility; the total future capital associated with
development of reserves and resources; and methods of funding our
capital program, including possible non-core asset divestitures and
asset swaps. In this news release reference is made to the Company's
five year growth plan including future processing capacity in
Northeast British Columbia and a 2018 Montney production target of
45,000 boe per day which are not estimates or forecasts of rates that
may actually be achieved. Such information reflects internal
projections used by management for the purposes of making capital
investment decisions and for internal long range planning and budget
preparation. Accordingly, undue reliance should not be placed on
same. 
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 all conditions to closing of
the Alberta Gas Disposition are satisfied or waived; 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; 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 assigned to 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 discovery 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. 
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 a 6:1 conversion basis may
be misleading as an indication of value. 
Crew is an oil and gas exploration and production company whose
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, 2014 and 2013 will be filed on
SEDAR at www.sedar.com and are available on the Company's website at
www.crewenergy.com. 
Contacts:
Crew Energy Inc.
Dale Shwed
President and C.E.O.
(403) 231-8850
dale.shwed@crewenergy.com 
Crew Energy Inc.
John Leach
Senior Vice President and C.F.O.
(403) 231-8859
john.leach@crewenergy.com 
Crew Energy Inc.
Rob Morgan
Senior Vice President and C.O.O.
(403) 513-9628
rob.morgan@crewenergy.com
www.crewenergy.com
 
 
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