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. 

                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                Three months   Three months 
                                                       ended          ended 
Financial                                          March 31,      March 31, 
($ thousands, except per share amounts)                 2014           2013 
----------------------------------------------------------------------------
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 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                       As at          As at 
                                                   March 31,   December 31, 
Capital Structure ($ thousands)                         2014           2013 
----------------------------------------------------------------------------
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 
----------------------------------------------------------------------------
----------------------------------------------------------------------------



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.                                                       
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                Three months   Three months 
                                                       ended          ended 
                                                   March 31,      March 31, 
Operations                                              2014           2013 
----------------------------------------------------------------------------
                                                                            
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%
----------------------------------------------------------------------------
----------------------------------------------------------------------------



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.



----------------------------------------------------------------------------
Natural Gas Resource Categories (1)(2)(3)                                Tcf
----------------------------------------------------------------------------
Total Petroleum Initially In Place (TPIIP)                              60.6
Discovered Petroleum Initially In Place (DPIIP)                         26.1
Undiscovered Petroleum Initially In Place (UPIIP)                       34.5
----------------------------------------------------------------------------
(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.             
                                                                            
----------------------------------------------------------------------------
Oil Resource Categories (1)(2)(3)(4)                                  Mmbbls
----------------------------------------------------------------------------
Total Petroleum Initially In Place (TPIIP)                             8,052
Discovered Petroleum Initially In Place (DPIIP)                        1,363
Undiscovered Petroleum Initially In Place (UPIIP)                      6,689
----------------------------------------------------------------------------
(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.        
                                                                            
----------------------------------------------------------------------------
                                                                        Best
Reserves and Contingent Resources (1)(2)(3)(6)(7)                   Estimate
----------------------------------------------------------------------------
                                                                            
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
----------------------------------------------------------------------------
(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.               
                                                                            
----------------------------------------------------------------------------
                                                                        Best
Prospective Resources (1)(2)(5)(6)                                  Estimate
----------------------------------------------------------------------------
                                                                            
Natural gas (Tcf)                                                        6.3
Natural gas liquids (Mmbbls) (3)(4)                                    254.4
Oil (Mmbbls)                                                            14.4
----------------------------------------------------------------------------
(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.


FOR FURTHER INFORMATION PLEASE CONTACT: 
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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