Paramount Resources Ltd. 2012 Results - Record Reserves Growth

Paramount Resources Ltd. 2012 Results - Record Reserves Growth 
P + P reserves up 239%, Conventional P + P reserves up 64%  
New Musreau Deep Cut Facility on-budget and on-schedule 
CALGARY, ALBERTA -- (Marketwire) -- 03/08/13 -- Paramount Resources
Ltd. (TSX:POU) -    
OVERVIEW 
Reserves and Principal Properties 


 
--  Total proved and probable reserves increased 239 percent to 179.9 MMBoe,
    with conventional reserves increasing 64 percent to 86.8 MMBoe
    (replacement ratio of six times) and probable oil sands bitumen reserves
    increasing 93.1 MMBoe.  
--  Conventional proved reserves increased 43 percent year-over-year to 50.9
    MMBoe, after production of 7.3 MMBoe and dispositions of 3.4 MMBoe
    (replacement ratio of three times). 
--  Conventional proved and probable finding and development costs,
    excluding facilities and gathering system construction costs, decreased
    50 percent to $12.18 per Boe and for the Kaybob COU decreased 24 percent
    to $10.31 per Boe. 
--  Natural gas and NGLs sales volumes increased approximately 20 percent
    despite downstream processing and transportation constraints which
    impacted the Company's operations in the second half of the year. 
--  The Company's new 45 MMcf/d refrigeration facility at Musreau (the
    "Musreau Refrig Facility") has been operating near capacity since being
    re-commissioned in March. 
--  Operating expenses decreased 14 percent to $9.58 per Boe in 2012
    compared to $11.20 per Boe in 2011 due to the sale of higher cost US
    properties and processing cost savings from the Company's Musreau Refrig
    Facility. 
--  Construction of the Company's wholly-owned 200 MMcf/d deep cut facility
    at Musreau (the "Musreau Deep Cut Facility") commenced in the third
    quarter of 2012 following the receipt of regulatory approval. The
    project continues to be on-schedule, with commissioning expected to
    commence by the end of the third quarter of 2013. 
--  Advance drilling for the deep cut facility expansions at Musreau and
    Smoky continued. The Company currently has an inventory of 43 (35 net)
    Kaybob Deep Basin wells with estimated first month deliverability
    exceeding 225 MMcf/d (185 MMcf/d net) of raw gas. 
--  In February 2013, the Company closed the sale of
 substantially all of
    its remaining US properties for cash proceeds of US$22.5 million,
    subject to closing adjustments. Since 2011, the Company has realized
    aggregate cash proceeds of approximately US$130 million on the sale of
    its US properties, significantly in excess of their carrying value. 

 
Strategic Investments 


 
--  Paramount drilled and completed its first horizontal shale gas
    exploration well at Patry in Northeast British Columbia in March 2013.
    In order to further evaluate well performance, the Company plans to
    bring the well on production by the end of 2013.  
--  Paramount's wholly-owned subsidiary, Cavalier Energy Inc. ("Cavalier
    Energy"), recorded 93.1 million barrels of probable bitumen reserves
    with an NPV10 of $379 million following its regulatory applications for
    the initial 10,000 Bbl/d phase of the Hoole Grand Rapids development. 
--  Fox Drilling completed the construction of two new walking drilling
    rigs, which will drill on multi-well pad sites in the Kaybob COU. 

 
Corporate 


 
--  To fund the Company's growth initiatives, Paramount raised over $700
    million in aggregate cash proceeds in 2012, including over $400 million
    from equity offerings, the sale of investments and non-core oil and gas
    properties and $300 million from the notes offering. 
--  At February 28, 2013, Paramount had cash balances of $109.2 million and
    its $300 million credit facility was undrawn. 
 
Financial and Operating Highlights(1)(2)                                    
--------------------------------------------------------------------------- 
($ millions, except as noted)                                               
                              Three months ended                            
                                     December 31     Year ended December 31 
----------------------------------------------------------------------------
                          2012     2011 % Change     2012     2011 % Change 
----------------------------------------------------------------------------
FINANCIAL                                                                   
Petroleum and natural                                                       
 gas sales                54.6     63.3      (14)   197.1    241.7      (18)
Funds flow from                                                             
 operations               17.7     26.1      (32)    58.1     96.2      (40)
 Per share - diluted                                                        
  ($/share)               0.20     0.33      (39)    0.67     1.23      (46)
Net income (loss)       (151.8)  (209.9)      28    (61.9)  (232.0)      73 
 Per share - basic and                                                      
  diluted ($/share)      (1.69)   (2.54)      33    (0.71)   (2.96)      76 
Exploration and                                                             
 development                                                                
 expenditures            166.8    144.1       16    523.1    465.7       12 
Investments in other                                                        
 entities - market                                                          
 value(3)                                           704.8  1,077.3      (35)
Total assets                                      2,037.0  1,725.7       18 
Net debt(4)                                         701.4    513.4       37 
Common shares                                                               
 outstanding                                                                
 (thousands)                                       89,932   85,500        5 
----------------------------------------------------------------------------
OPERATING                                                                   
Sales volumes                                                               
 Natural gas (MMcf/d)    104.1     91.5       14     98.5     81.6       21 
 NGLs (Bbl/d)            2,110    1,620       30    1,873    1,542       21 
 Oil (Bbl/d)             1,213    2,356      (49)   1,620    2,291      (29)
 Total (Boe/d)          20,674   19,223        8   19,917   17,426       14 
Average realized price                                                      
 Natural gas ($/Mcf)      3.45     3.62       (5)    2.72     4.04      (33)
 NGLs ($/Bbl)            61.23    78.08      (22)   67.10    79.56      (16)
 Oil ($/Bbl)             79.72    93.25      (15)   83.16    87.00       (4)
 Total ($/Boe)           28.70    35.80      (20)   27.04    38.00      (29)
                                                                            
Net wells drilled                                                           
 (excluding oil sands                                                       
 evaluation)                 8       13      (38)      34       48      (29)
Net oil sands                                                               
 evaluation wells                                                           
 drilled                     -        -        -        1       27      (96)
----------------------------------------------------------------------------
RESERVES(5)                                                                 
Proved and probable                                                         
 Natural gas (Bcf)                                  323.7    244.1       33 
 Light and medium crude oil (MBbl)                  2,128    6,573      (68)
 NGLs (MBbl)                                       30,761    5,760      434 
                                                 ------------------         
 Total Conventional (MBoe)                         86,842   53,015       64 
 Oil sands bitumen (MBbl)                          93,091        -      100 
                                                 ------------------         
 Total Company (MBoe)                             179,933   53,015      239 
                                                 ------------------         
                                                 ------------------         
Conventional F&D cost before facilities                                     
 expenditures (proved and probable) ($/Boe)         12.18    24.19      (50)
Conventional reserves replacement (proved and                               
 probable)                                            599%     193%         
NPV10 future net revenue before tax                                         
 Proved                                             455.9    611.4      (25)
 Proved and probable                              1,259.3    832.2       51 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Readers are referred to the advisories concerning non-GAAP measures and 
 oil and gas definitions in the Advisories section of this document.        
(2) Amounts include the results of discontinued operations. Refer to page   
 seven of Paramount's Management's Discussion and Analysis for the year     
 ended December 31, 2012.                                                   
(3) Based on the period-end closing prices of publicly traded enterprises   
 and the book value of the remaining investments.                           
(4) Net debt is a non-GAAP measure, it is calculated and defined in the     
 Liquidity and Capital Resources section of Paramount's Management's        
 Discussion and Analysis for the year ended December 31, 2012.              
(5) Working interest reserves before royalty deductions. Net present values 
 were determined using forecast prices and costs and do not represent fair  
 market value.                                                              
                                                                            
REVIEW OF OPERATIONS(1)                                                     
                                        2012              2011 % Change
-----------------------------------------------------------------------
Sales Volumes                                                          
 Natural gas (MMcf/d)                   98.5              81.6      21 
 NGLs (Bbl/d)                          1,873             1,542      21 
 Oil (Bbl/d)                           1,620             2,291     (29)
                           ------------------------------------        
 Total (Boe/d)                        19,917            17,426      14 
                           ------------------------------------        
                                                                       
                                                               % Change
Netbacks ($ millions)(2)           ($/Boe)(3)        ($/Boe)(3)in $/Boe
 Natural gas revenue          98.2      2.72   120.2      4.04     (33)
 NGLs revenue                 46.0     67.10    44.8     79.56     (16)
 Oil revenue                  49.3     83.16    72.7     87.00      (4)
 Royalty and sulphur                                                   
  revenue                      3.6         -     4.0         -         
---------------------------------------------------------------        
 Petroleum and natural gas                                             
  sales                      197.1     27.04   241.7     38.00     (29)
 Royalties                   (16.5)    (2.27)  (22.1)    (3.47)    (35)
 Operating expense and                                                 
  production tax             (69.9)    (9.58)  (71.3)   (11.20)    (14)
 Transportation              (21.8)    (2.98)  (20.5)    (3.23)     (8)
---------------------------------------------------------------        
Netback                       88.9     12.21   127.8     20.10     (39)
 Financial commodity                                                   
  contract settlements        (0.1)    (0.02)    0.2      0.03    (167)
 Insurance settlement          6.2      0.85       -         -     100 
---------------------------------------------------------------        
Netback including commodity                                            
 & insurance settlements      95.0     13.04   128.0     20.13     (35)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
(1) Amounts include the results of discontinued operations. Refer to   
 page seven of Paramount's Management's Discussion and Analysis for    
 the year ended December 31, 2012.                                     
(2) Readers are referred to the advisories concerning non-GAAP         
 measures and oil and gas definitions in the Advisories section of     
 this document.                                                        
(3) Natural gas revenue shown per Mcf.                                 

 
Paramount's natural gas and NGLs sales volumes increased 21 percent
in 2012 as the Company completed the first phase of its Kaybob Deep
Basin expansion with the re-commissioning of the Musreau Refrig
Facility at the end of the first quarter. New production was also
added at Valhalla in the Grande Prairie COU, where the gathering and
compression system was expanded. 
The ability of Paramount to maximize production through its natural
gas firm-capacity and Company-owned facilities in 2012, including the
Musreau Refrig Facility and Valhalla gathering and compression
system, was impacted by various third party downstream disruptions
and capacity constraints (the "Third Party Disruptions"), which
reduced sales volumes at times by up to 6,000 Boe/d. The Third Party
Disruptions mainly related to reduced throughput at third party NGLs
de-ethanization and fractionation facilities at Fort Saskatchewan,
which resulted in the apportionment of available processing capacity.
The Third Party Disruptions were also caused by NGLs and natural gas
pipeline takeaway constraints and scheduled and unscheduled downtime
at third party natural gas processing facilities. The Company
estimates that average sales volumes in the second half of 2012 were
reduced by approximately 3,000 Boe/d. Sales volumes in December 2012
and January 2013 were constrained to approximately 22,000 Boe/d. 
Oil sales volumes decreased 29 percent to 1,620 Bbl/d in 2012
compared to 2,291 Bbl/d in 2011, primarily because of the second
quarter US property disposition and natural declines in other areas. 
Petroleum and natural gas sales revenue in 2012 decreased $44.6
million compared to 2011 as a result of lower realized prices and the
US property disposition. Operating costs decreased $1.4 million
compared to 2011 primarily due to the disposition of the US
properties, partially offset by higher operating expenses from
continuing operations. 


 
Kaybob                                                                      
 

 
                                            2012              2011 % Change 
----------------------------------------------------------------------------
Sales Volumes                                                               
  Natural gas (MMcf/d)                      59.5              44.5       34 
  NGLs (Bbl/d)                               924               868        6 
  Oil (Bbl/d)                                 62                72      (14)
                              ------------------------------------          
  Total (Boe/d)                           10,910             8,361       30 
                              ------------------------------------          
Exploration and Development                                                 
 Expenditures ($ millions)                                                  
  Exploration, drilling,                                                    
   completions and tie-ins                 200.7             171.2       17 
  Facilities and gathering                 161.8              91.6       77 
                              ------------------------------------          
                                           362.5             262.8       38 
                              ------------------------------------          
                                  Gross      Net    Gross      Net          
                              ------------------------------------          
Total Land Holdings (sections)      788      446      792      441          
Wells Drilled                        27     21.2       28     18.3          
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
The Kaybob corporate operating unit ("COU") operates in West Central
Alberta, where its core properties are in the Deep Basin at Musreau,
Smoky and Resthaven. Paramount has assembled extensive multi-zone
mineral rights to 788 (446 net) sections, with the primary formations
of interest being the Montney and various Cretaceous horizons.
Depending on the formation, well densities of eight or more wells per
section per formation are anticipated to be required to recover the
resources in place, representing a multi-decade inventory of drilling
locations. 
Paramount continues to execute the large-scale development of its
Deep Basin lands that will materially increase production volumes and
cash flow. The Company's drilling activities are currently focused on
the Montney, Dunvegan, and Falher formations, which are high
pressure, liquids rich, tight gas formations with large reserves
potential. These plays continue to generate robust rates of return in
the current low natural gas price environment because of the high
liquids content in these formations. 
The Company achieved significant reserves growth in 2012 as a result
of its development activities in the Kaybob Deep Basin. Further
increases in reserves are expected as facilities expansions are
completed and development drilling continues. 
To support the accelerated development of Paramount's Deep Basin
lands, the Company constructed its wholly-owned 45 MMcf/d Musreau
Refrig Facility, is building a 200 MMcf/d deep cut processing
facility at Musreau and is participating in the deep cut expansion of
the non-operated Smoky facility, which together will more than triple
Paramount's current gas processing capacity to over 300 MMcf/d. The
Company has also entered into long-term agreements to transport,
de-ethanize and fractionate NGLs streams that will be produced from
these new facilities, and has entered into a long-term ethane sales
agreement with a petrochemical company. 
Operations 
Average daily sales volumes in the Kaybob COU during 2012 were 10,910
Boe/d, an increase of 30 percent compared to 2011. Sales volumes in
the first quarter of 2012 were impacted by the fourth quarter 2011
electrical component failure at the Musreau Refrig Facility. The
re-commissioning of the facility was completed in March 2012, and
average sales volumes increased to 12,236 Boe/d in the second
quarter. Sales volumes in the second half of the year were reduced as
a result of the previously described Third Party Disruptions. By the
middle of September, production across the Kaybob COU was curtailed
to less than 6,500 Boe/d, including a temporary reduction in
throughput at the Musreau Refrig Facility to 10 MMcf/d. Sales volumes
reached 13,500 Boe/d in November following the partial resolution of
Third Party Disruptions.  
Between December 2012 and February 2013, Kaybob COU sales volumes
have ranged between 11,500 Boe/d and 13,500 Boe/d as operations
continue to be impacted by Third Party Disruptions. Based on the
current NGLs constraints and projections of capacity for the
remainder of 2013, production is expected to be within the current
range until the expansion of a third-party NGLs pipeline is
completed, Paramount secures additional fractionation capacity and
the Musreau Deep Cut Facility is brought on-stream. The Kaybob COU
has approximately 28,000 Boe/d of first year production behind pipe
which will be brought on-stream when the Musreau and Smoky deep cut
expansions are on-stream. 
After the start-up of the Musreau Refrig Facility, operating costs
for the Kaybob COU were reduced to approximately $5.00 per Boe,
before deducting processing income. The Musreau Refrig Facility
provides significant savings to the Company through the elimination
of third-party processing fees. The Kaybob COU's per unit operating
costs are expected to further decrease with the commissioning of the
Musreau Deep Cut Facility, as fixed costs will be applied over
significantly larger production volumes. In the third quarter,
Paramount received a $6.2 million settlement in respect of a business
interruption insurance claim related to the electrical equipment
failure at the Musreau Refrig Facility in December 2011. 
Paramount has completed the first phase of its Deep Basin expansion
with the re-commissioning of the Musreau Refrig Facility. The next
major milestone will be the start-up of the Musreau and Smoky deep
cut facilities, which will represent a major step change for
Paramount, as Kaybob COU sales volumes are expected to increase more
than four times 2012 levels by the end of 2014. 
Musreau Deep Cut Facility 
Paramount's wholly-owned Musreau Deep Cut Facility is designed to
capture incremental volumes of NGLs from the Company's Deep Basin
liquids rich gas production that would otherwise be sold as slightly
higher heat content natural gas. The incremental liquids are captured
by cooling the natural gas stream sufficiently to change the phase of
the components from a gas to a liquid and then separating these
streams using gravity. Liquids yields from the facility will vary
depending on the liquids content of the gas being processed and the
temperature to which Paramount cools the gas stream, among other
factors. 
Construction of the Musreau Deep Cut Facility commenced in the third
quarter of 2012 following the receipt of regulatory approval. Site
preparation is complete and piling and concrete work continues. Major
equipment, including compressors, generators and storage vessels, are
being delivered to the facility site over the course of the winter so
that construction can continue through break-up. Paramount has
awarded the structural steel contract and anticipates awarding the
mechanical contracts shortly, with electrical and instrumentation
contracts to follow. The project continues to be on-schedule and
in-line with budget, with approximately $100 million incurred to
December 31, 2012 and an additional $80 million budgeted for 2013 to
complete construction.  
Paramount is currently developing its commissioning plan.
Commissioning of the facility is expected to begin towards the end of
the third quarter of 2013 and span approximately two months, a
process which involves testing and calibrating the individual
components and control systems, purging vessels and piping, and
pressure testing the system.  
Paramount has secured a long-term firm service arrangement for the
transportation of NGLs produced from its Kaybob area facilities
commencing in December 2013. The Company has also entered into a
long-term firm service arrangement with a midstream company for the
de-ethanization and fractionation of NGLs volumes commencing in April
2014. The Company is working on procuring interruptible NGLs
fractionation capacity for the period between the planned December
2013 start-up of the Musreau Deep Cut Facility and the commencement
of the long-term firm service fractionation arrangement.  
Kaybob COU sales volumes are expected to increase to approximately
30,000 Boe/d over the first few months after startup, as the
operations team optimizes the facility's equipment and processes.
Volumes initially processed through the Musreau Deep Cut Facility
will be primarily from leaner Cretaceous wells in which Paramount's
working interest generally ranges from 50 percent to 100 percent.
Ethane is expected to remain in the gas stream until the midstream
company completes an expansion of its de-ethanization facilities,
which is scheduled to be operational in the second half of 2014. By
late-2014, Kaybob COU sales volumes are expected to increase by over
four times 2012 levels once a greater proportion of liquids-rich, 100
percent working interest Montney wells are flowing through the
Musreau Deep Cut Facility, the expansion of the third party
de-ethanization facility is completed and the Smoky Deep Cut Facility
is on-stream. 
The Company continues to advance its project to construct an amine
processing train at the Musreau Deep Cut Facility, which will provide
the capability to treat sour gas production at the facility instead
of at well sites. This enhancement is expected to cost approximately
$50 million, and will decrease equipping costs by over $1 million per
well and reduce ongoing well operating costs. Design work for the
amine facility has been completed and long lead-time components have
been ordered. The amine processing train is scheduled to be on-stream
in the first half of 2014, and will not impact the start-up of the
Musreau Deep Cut Facility. 
Smoky Deep Cut Facility 
Paramount continues to participate in the deep cut expansion of the
non-operated processing facility at Smoky (the "Smoky Deep Cut
Facility"). The Company will have a 20 percent interest in the
expanded facility, an increase from its 10 percent interest in the
existing 100 MMcf/d dew point facility. The Smoky Deep Cut Facility
will initially have 200 MMcf/d of capacity upon start-up, increasing
to 300 MMcf/d through the later installation of an incremental 100
MMcf/d of compression. As a plant owner, Paramount has the option at
any time to request installation of the additional compression, which
would bring the Company's total owned capacity in the facility to 60
MMcf/d. Construction work commenced at the site in the third quarter
of 2012 with the installation of pilings and foundations. NGLs
bullets and compressors have been delivered and a significant portion
of the major equipment is expected to be delivered prior to break-up,
with the remaining components to be delivered later this year. The
expansion is scheduled to be commissioned in the third quarter of
2014. Paramount's share of the Smoky Deep Cut Facility expansion
costs is expected to total $65 million, of which approximately $30
million has been incurred to December 31, 2012. 
Kaybob Processing Capacity 
Upon completion of the Musreau Deep Cut Facility and the Smoky Deep
Cut Facility, Paramount expects to have over 300 MMcf/d of net owned
and third party firm-service processing capacity in the Deep Basin,
estimated to be capable of yielding over 73,000 Boe/d of sales
volumes when fully utilized. This capacity will be used to process
Paramount's production as well as third-party unavoidably commingled
volumes for a fee. Paramount currently has access to an incremental
10 to 12 MMcf/d of interruptible processing capacity and will
continue to utilize such capacity in addition to its owned and
firm-service capacity where available. The Company's current and
future owned and firm-service processing capacity in the Deep Basin
is as follows: 


 
                                                Net         Net
                                  Gross   Paramount   Paramount
                                Raw Gas     Raw Gas       Sales
                               Capacity    Capacity Capacity(1)
---------------------------------------------------------------
                               (MMcf/d)    (MMcf/d)     (Boe/d)
Current Processing Capacity                                    
---------------------------                                    
Musreau Refrig Facility              45          45       8,600
Resthaven Facility                   20          10       2,000
Smoky Facility                      100          10       2,500
Kakwa Facility                       40           4         720
Firm Contracted Capacity             10          10       1,800
---------------------------------------------------------------
Subtotal - Current Capacity         215          79      15,620
---------------------------------------------------------------
                                                               
Future Processing Capacity                                     
---------------------------                                    
Musreau Deep-Cut Facility           200         200      50,000
Smoky Deep-Cut Facility             200          30       7,500
---------------------------------------------------------------
Subtotal - Future Capacity   
       400         230      57,500
---------------------------------------------------------------
                                                               
Projected Total                     615         309      73,120
---------------------------------------------------------------
---------------------------------------------------------------
(1) Estimated                                                  

 
To see the map associated with this release, click the following
link: http://media3.marketwire.com/docs/para_graph1.pdf 
Kaybob Drilling Activity 
During 2012, Paramount was active drilling and completing wells in
the Deep Basin, continuing to build production deliverability in
preparation for the start-up of the new Musreau and Smoky deep cut
facilities. The Company drilled 27 (21.2 net) wells in 2012,
including 7 (6.0 net) horizontal Montney formation wells and
completed 17 (13.1 net) wells, including 9 (8.0 net) Montney
formation wells. The initial flow rates and NGLs content continue to
be consistent with expectations, further confirming well performance
profiles. 
The Company's producing Falher formation wells have on average
performed in accordance with the anticipated type curve below:
http://media3.marketwire.com/docs/307pou_graph2.pdf  
NGLs transportation and fractionation capacity constraints have
temporarily limited Paramount's ability to bring on Montney formation
wells due to their higher liquids content. The Company has continued
to drill and complete Montney wells in advance of the Musreau and
Smoky deep cut facilities expansions and test results from the latest
wells continue to be consistent with earlier wells, further
confirming expected recoveries from this formation. The following
table summarizes test results for Montney formation wells rig
released in 2011 and 2012: 


 
                                              Test Results(1)               
                               ---------------------------------------------
Location                            Avg. Rate    Pressure(2)       Duration 
----------------------------------------------------------------------------
                                      (MMcf/d)          (PSI)          (Hrs)
Musreau                                  11.6          2,029              6 
Musreau                                   8.6          1,006             20 
Musreau                                   6.1          1,159              2 
Musreau                                   6.6          2,068             64 
Musreau                                  12.4          2,067              1 
Smoky                                     4.1            584              4 
Smoky                                    10.9          3,454             56 
Musreau                                   9.0          2,455              1 
Musreau                                  11.0          2,248             31 
Musreau                                   6.5          2,373             36 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Test rates represent the average rate of gas-flow during post clean-up  
 production tests up the largest choke setting. All wells were stimulated   
 using frac oil and substantially all fluids recovered during the test      
 periods were load fluids. As a result, fluid volumes recovered during the  
 tests have not been disclosed. Pressure transient analyses and well-test   
 interpretations have not been carried out for these wells and as such,     
 data should be considered to be preliminary until such analysis or         
 interpretation has been done. Test results are not necessarily indicative  
 of long-term performance or of ultimate recovery.                          
(2) Average flow-back casing pressure for the duration of the test.         

 
The Company has varying rights to multiple formations within its 788
(446 net) section Kaybob COU land position, including 391 (240 net)
sections of Cretaceous rights and 229 (195 net) sections of Montney
rights. Having rights to multiple formations allows the Company to
evaluate shallower formations while drilling deeper wellbores
targeting deeper rights. Prospective shallower zones can be completed
in addition to the deeper reservoirs to increase total recoveries
from individual locations. The Company has received approval to drill
up to five Montney formation wells per section on six sections and is
preparing to file applications on additional lands. It is anticipated
that well densities of eight or more wells per section per formation
will be required to fully recover the resources. 
Paramount's experience over the past few years in the Deep Basin has
allowed the Company to achieve cost reductions in drilling and
completion operations through improved drilling and fracturing
techniques and improved logistics with multi-well pad sites. The
Company has been successful in reducing drilling time for Falher
formation wells to approximately 30 days from 40 days in 2010.
Drilling time for the deeper Montney formation wells has been reduced
to approximately 45 days from over 80 days in the early part of 2011.
With the cost of each drilling day averaging approximately $75,000,
the reduction in drilling days alone has resulted in significant cost
savings. The Company has also reduced completion costs by improving
pumping techniques, optimizing frac sizing and spacing, recycling the
frac oil, and negotiating lower rates for services, equipment and
completion fluids. 
During the fourth quarter of 2012, the Company finished equipping the
wells on its first five-well pad at Musreau. Three (2.5 net) Montney
formation wells and two (1.5 net) Falher formation wells were
drilled, completed, equipped and tied-in for aggregate gross costs of
approximately $45 million, including the cost of site sweetening
packages for the Montney wells. Average gross raw gas test rates for
the five wells totalled approximately 55 MMcf/d over the final 24
hours of their test periods, with flowing pressures averaging 2,500
PSI. 
Multi-well pad sites will increasingly be used to develop Paramount's
Deep Basin lands, where drilling and completion operations are
performed on multiple wells thereby minimizing mobilization and
de-mobilization costs and reducing equipping and tie-in costs by
using common facilities. The Company plans to utilize its two new
built-for-purpose walking rigs to drill on its multi-well pad sites
beginning in the second quarter of 2013. These rigs have the ability
to move across the lease with drill pipe standing in the derrick so
that pad wells are drilled in sequence with minimal downtime between
wells. Completion operations on pad sites allow the Company to
produce back energized oil from a fracture stimulation, recycle the
fluid and re-inject it into the next well, saving the cost of
transporting and purchasing new frac oil. 
Paramount currently has five drilling rigs working in the Deep Basin,
which continue to add to the Company's inventory of wells that will
feed the Musreau and Smoky deep cut facilities. The Company plans to
drill up to an additional 40 wells during 2013, approximately 50
percent of which will target the Montney formation. The 2013 drilling
program includes eight pad sites that are expected to account for 32
of the planned 40 wells.  
The following table summarizes the status of Kaybob Deep Basin wells
that have been drilled and are awaiting production as of February 28,
2013, the estimated remaining capital required to complete these
wells, and their anticipated production and sales volumes: 


 
                                                      Total
                                                  Remaining
                                  Wells       Capital (net)
                            -------------------------------
                               Gross     Net               
                            -------------------------------
                                               ($ millions)
Shut-in due to capacity                                    
 constraints                       9       8              -
Tied-in, capable of                                        
 producing                        10       7              -
Completed, awaiting tie-in        14      12             20
Drilled, awaiting completion      10       8             51
-----------------------------------------------------------
                                  43      35             71
-----------------------------------------------------------
-----------------------------------------------------------
 
                                           Estimated               Estimated
                                         Net Raw Gas               Net Sales
                                       Production(1)              Volumes(2)
                            ------------------------------------------------
                             First Month  First Year First Month  First Year
                            ------------------------------------------------
                                (MMcf/d)    (MMcf/d)     (Boe/d)     (Boe/d)
Shut-in due to capacity                                                     
 constraints                          23          11       6,400       3,100
Tied-in, capable of                                                         
 producing                            54          25      14,900       7,000
Completed, awaiting tie-in            59          29      19,000       9,200
Drilled, awaiting completion          52          28      17,000       9,100
----------------------------------------------------------------------------
                                     188          93      57,300      28,400
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on the Company's 4.9 Bcf type curve for Falher wells and 3.7 Bcf  
 type curve for Montney wells.                                              
(2) Based on processing through a deep cut facility.                        

 
Once the Musreau Deep Cut Facility is fully operational and the
ramp-up of production volumes is complete, the Company estimates that
approximately 20 new wells will be required each year to keep the
facility operating at capacity. 
The Kaybob COU's focus in 2013 is to complete the construction of the
Musreau Deep Cut Facility and maximize production volumes through
available capacity. The Company is ready for significant growth. With
production volumes ramping-up as the Musreau and Smoky deep cut
facilities are brought on-stream, Paramount will begin to realize
returns on its Deep Basin drilling and infrastructure investments. 


 
                                                                            
Grande Prairie                                                              
                                         2012          2011    % Change 
------------------------------------------------------------------------
Sales Volumes                                                           
  Natural gas (MMcf/d)                   20.9          16.0          31 
  NGLs (Bbl/d)                            749           505          48 
  Oil (Bbl/d)                             307           393         (22)
                               ----------------------------             
  Total (Boe/d)                         4,536         3,568          27 
                               ----------------------------             
Exploration and Development                                             
 Expenditures ($ millions)                                              
  Exploration, drilling,                                                
   completions and tie-ins               69.5         106.4         (35)
  Facilities and gathering               32.9          49.6         (34)
                               ----------------------------             
                                        102.4         156.0         (35)
                               ----------------------------             
                                 Gross    Net  Gross    Net             
                               ----------------------------             
Total Land Holdings (sections)     577    379    629    430             
Wells Drilled                       10    6.7     22   15.0             
------------------------------------------------------------------------
------------------------------------------------------------------------

 
The Grande Prairie COU operates in the Peace River Arch area of
Alberta. Core producing areas include Valhalla and Karr-Gold Creek.
Average daily sales volumes in the Grande Prairie COU during 2012
were 4,536 Boe/d, an increase of 27 percent compared to 2011. Fourth
quarter 2012 sales volumes averaged 5,243 Boe/d, after being
curtailed as a result of the Third Party Disruptions between August
and October. 
Increases in 2012 sales volumes were primarily from Valhalla. The
Company's gathering and compression system was expanded to 24 MMcf/d
in the second quarter and additional wells were brought on-stream.
The Company drilled six (4.3 net) wells in Valhalla in 2012 targeting
the Montney and Doig formations. These wells were completed and
tied-in during the year, along with wells drilled in 2011. 
Karr-Gold Creek is located approximately 20 kilometers north of the
Kaybob COU's Musreau development. Activities in 2012 focused on
exploration of the middle and upper Montney reservoirs and continued
efforts to improve the performance of the Company's previously
completed lower Montney formation wells. Paramount's middle and upper
Montney land position at Karr-Gold Creek of approximately 180 (148
net) sections exhibits similar geological reservoir and fluid
characteristics to competitors' offsetting lands, and the Company's
Montney holdings in the Musreau / Resthaven area. 
In the third quarter of 2012, the Company completed a previously
drilled middle Montney well at Karr-Gold Creek, which was brought-on
production during the first quarter of 2013. A new well targeting the
middle Montney formation was drilled in the fourth quarter of 2012,
was completed in the first quarter of 2013 and will be tied-in during
the third quarter. Test results from these wells have exceeded
forecasts, confirming Paramount's interpretation that the Kaybob
middle/upper Montney play extends northwest onto the Karr lands,
adding significant resources to Paramount's future development base
in the Deep Basin. 
Results of the performance enhancement program for the Company's
lower Montney wells at Karr-Gold Creek have not been consistent with
expectations. While recoveries from some wells improved modestly,
others wells are unchanged and Third Party Disruptions impacted the
project for a significant portion of the year. This program will not
be continued in 2013. 
Exploration and development activities in the Grande Prairie COU will
include the drilling, completion and tie-in of middle Montney wells
at Karr-Gold Creek. The Company anticipates the existing inventory of
producing and behind pipe wells at Valhalla will be sufficient to
maintain production volumes at the current level throughout 2013,
subject to the availability of NGLs transportation and fractionation
capacity. 


 
Southern(1)                                                             
                                                                        
                                         2012          2011    % Change 
------------------------------------------------------------------------
Sales Volumes                                                           
  Natural gas (MMcf/d)                    9.8          10.8          (9)
  NGLs (Bbl/d)                            171           150          14 
  Oil (Bbl/d)                           1,016         1,483         (31)
                               ----------------------------             
Total (Boe/d)                           2,814         3,424         (18)
                               ----------------------------             
Exploration and Development                                             
 Expenditures ($ millions)                                              
  Exploration, drilling,                                                
   completions and tie-ins               23.0          14.9          51 
  Facilities and gathering                2.7           4.7         (43)
                               ----------------------------             
                                         25.7          19.6          29 
                               ----------------------------             
                                 Gross    Net  Gross    Net             
                               ----------------------------             
Total Land Holdings (sections)     627    432    708    489             
Wells Drilled                        4    2.2     22   12.0             
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Amounts include the results of discontinued operations. Refer to    
 page seven of Paramount's Management's Discussion and Analysis for the 
 year ended December 31, 2012.                                          

 
In May 2012, Summit closed the sale of all of its operated properties
in North Dakota and all of its Montana properties for cash proceeds
of approximately US$70 million. This disposition included
approximately 900 Boe/d of production and 42 net sections of land.
During the first quarter of 2013, Summit closed the sale of its
non-operated joint venture operations and lands in North Dakota for
aggregate gross proceeds of US$22.5 million, subject to closing
adjustments. This disposition included approximately 200 Boe/d of
p
roduction and undeveloped land. With the closing of these
transactions, substantially all of Paramount's US assets and
operations have been sold. 
Combined with the 2011 sale of undeveloped land in the United States
for US$40 million, approximately US$130 million in cash proceeds has
been realized from the sale of US properties, significantly in excess
of the book value of these assets. 
Southern COU sales volumes decreased 18 percent to 2,814 Boe/d in
2012 compared to 3,424 Boe/d in 2011, mainly as a result of the
disposition of the operated US properties in May. Wells drilled in
2012 include three (2.2 net) wells in Harmattan in southern Alberta,
one of which was completed and is scheduled to be brought-on
production in the second quarter of 2013. 
Plans for the Southern COU's properties in 2013 consist primarily of
routine maintenance and production optimization programs. 


 
                                                                            
Northern                                                                    
                                         2012          2011    % Change 
------------------------------------------------------------------------
Sales Volumes                                                           
  Natural gas (MMcf/d)                    8.3          10.3         (19)
  NGLs (Bbl/d)                             29            19          53 
  Oil (Bbl/d)                             235           343         (31)
                               ----------------------------             
  Total (Boe/d)                         1,657         2,073         (20)
                               ----------------------------             
Exploration and Development                                             
 Expenditures ($ millions)                                              
  Exploration, drilling,                                                
   completions and tie-ins               21.2          21.8          (6)
  Facilities and gathering                6.9           3.4         103 
                               ----------------------------             
                                         28.1          25.2           9 
                               ----------------------------             
                                 Gross    Net  Gross    Net             
                               ----------------------------             
Total Land Holdings (sections)     962    690    959    592             
Wells Drilled                        3    3.0      2    2.0             
------------------------------------------------------------------------
------------------------------------------------------------------------

 
Sales volumes in the Northern COU were 1,657 Boe/d in 2012, 20
percent lower than 2011, as a result of natural declines at Cameron
Hills and Bistcho and second quarter processing disruptions at the
Bistcho plant.  
Paramount's initial well at Birch in Northeast British Columbia was
brought on-stream in December 2012 following the completion of
modifications to surface facilities. Two additional wells drilled in
2012 have been completed and tied-in. The Company has 3 MMcf/d of raw
gas processing capacity at Birch, and is currently working to
optimize production from these wells. In the third quarter, Paramount
drilled a vertical evaluation well at Birch to evaluate the lower
Montney formation and preserve surrounding mineral rights. 
In March 2013, Paramount sold its properties in the Bistcho area of
Alberta and the Cameron Hills area of the Northwest Territories for
approximately $9 million, subject to closing adjustments. Average
sales volumes for these properties were approximately 1,000 Boe/d in
2012. 
STRATEGIC INVESTMENTS 
SHALE GAS 
Paramount's shale gas holdings encompass approximately 260 (220 net)
sections in the Liard Basin and the Horn River Basin in Northeast
British Columbia and the Northwest Territories, including
approximately 180 net sections with potential from the Besa River
shale gas formation.  
To see a map of the Liard Basin, click the following link:
http://media3.marketwire.com/docs/307pou_map2.pdf 
Paramount drilled and completed its first horizontal shale gas
exploration well at Patry in Northeast British Columbia. The well was
drilled to a vertical depth of approximately 3,400 meters with a
horizontal bore of approximately 1,200 meters, and was completed with
a 10-stage fracture stimulation in the Besa River formation in early
March 2013 that included the injection of approximately 120,000
barrels of completion fluids.  
The well commenced flowing on clean-up in the first week of March
2013 and continues to recover the completion fluids. Over the first
69 hours of metered gas flow, natural gas rates ranged between 5
MMcf/d and 14 MMcf/d on clean-up and completion fluid recoveries
averaged approximately 4,000 Bbl/d at flowing tubing pressures of
11,000 to 35,000 kPa up 114.3 mm tubing.  During the last 24 hours of
that period, natural gas rates averaged 7 MMcf/d at an average
flowing tubing pressure of approximately 11,500 kPa and completion
fluid recovery was approximately 2,800 Bbl/d. As a pressure transient
analysis or well test interpretation has not been carried out at this
time, the flow-back data provided should be considered preliminary.
In addition, this data is not necessarily indicative of long-term
performance or ultimate recovery. 
The Company is working to confirm that all 10 stages of the fracture
stimulation are open and contributing.  In order to further evaluate
well performance, the Company plans to tie the Patry well into
existing pipeline infrastructure located within two miles of the well
site and plans to bring the well on production by the end of 2013. 
The Company re-commenced drilling operations on its initial shale gas
evaluation well at Dunedin in February 2013 after drilling operations
were suspended there in the spring of 2012 due to warm weather.
Paramount plans to drill this well to the intended vertical depth of
approximately 4,500 meters at which point it will evaluate further
plans to complete the vertical wellbore and/or drill a horizontal
leg. This activity is expected to extend the mineral rights
surrounding the well location for an additional decade and provide
information useful for future development. 
CAVALIER ENERGY INC.   
Cavalier Energy is designed to be a focused, self-funding entity,
which was created in 2011 as a wholly-owned subsidiary of Paramount
to execute the development of the Company's oil sands and carbonate
bitumen assets. Cavalier Energy holds over 300 sections, representing
approximately 200,000 net acres of Crown leases in the Western
Athabasca region of Alberta. 
Hoole Grand Rapids  
The initial focus of Cavalier Energy is to develop the Grand Rapids
formation in its 100 percent owned in-situ oil sands leases in the
Hoole area of Alberta (the "Hoole Project"). The Hoole Project is 10
kilometers northeast of Wabasca-Desmarais, Alberta. Since 2004,
approximately $60 million has been invested through land
acquisitions, stratigraphic drilling, engineering studies, and
environmental field programs to bring this asset to the development
stage. 
In 2012, Cavalier Energy focused its efforts on recruiting its
leadership team and developing the project strategy, including the
project size, use of technologies and execution approach. These
actions provided the necessary information for the regulatory
application and the company's development strategy. 
In November 2012, Cavalier Energy submitted regulatory applications
for the initial 10,000 Bbl/d phase of the Hoole Grand Rapids
development ("Hoole Grand Rapids Phase 1") to the Energy Resources
Conservation Board ("ERCB") and Alberta Environment and Sustainable
Resource Development ("AESRD"). Cavalier Energy anticipates
regulatory approvals to be received in the first half of 2014.
Construction of Hoole Grand Rapids Phase 1 is dependent upon the
receipt of regulatory approvals, sanctioning by the Board of
Directors, and securing funding. 
During 2013, Cavalier Energy plans to complete the front end
engineering and design work for Hoole Grand Rapids Phase 1 along with
geotechnical work and the drilling of additional source water and
disposal wells. Estimated costs of these activities totalling $15
million are expected to be funded with drawings on Cavalier Energy's
$40 million credit facility. 
In January 2013, Cavalier Energy received an updated independent
evaluation of the Hoole Project, effective December 31, 2012, from
the Company's independent reserves evaluators. The evaluation
ascribed 93 million barrels of probable reserves with a net present
value (discounted at 10 percent) of $379 million to Hoole Grand
Rapids Phase 1, which covers approximately two sections of the Hoole
Project. Over and above the aforementioned reserves, the evaluation
ascribed 719 million barrels of economic contingent resources (best
estimate) with a net present value (discounted at 10 percent) of
$1.949 billion to the remaining approximate 54 sections of the Hoole
Project (the "Remaining Hoole Leases") within the Grand Rapids
formation. The updated estimates and reclassification of Hoole
Project volumes from economic contingent resources to probable
reserves follows Cavalier Energy's November 2012 regulatory
applications. 
The reserves assigned to Hoole Grand Rapids Phase 1 are summarized in
the Reserves section of this document. Results of the evaluation of
the Remaining Hoole Leases are as follows: 


 
                                                               NPV of Future
                                                                         Net
                                                       Economic  Revenue(1) 
                                                     Contingent  (discounted
Classification/Level of Certainty(1)      DEBIP(1) Resources(1)      at 10%)
----------------------------------------------------------------------------
                                        (MMBbl)(2)   (MMBbl)(2)        ($MM)
High Estimate                                1,656          903        2,982
Best Estimate                                1,469          719        1,949
Low Estimate                                 1,167          511          946
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) See Oil Sands Resource Notes in the Advisories section of this document.
(2) MMBbl means millions of barrels.                                        

 
Future Exploration Portfolio  
Cavalier Energy holds 128,000 acres of mineral rights located on the
Grosmont Carbonate Trend. Industry peers have begun to explore this
resource and have constructed pilot projects to refine extraction
technologies. Cavalier Energy is monitoring industry developments and
will develop future plans for its holdings based on the results of
these pilot projects.  
Cavalier Energy acquired 36 sections of land at Eagles Nest in early
2012. The property is prospective for oil sands bitumen in the
McMurray and Wabiskaw formations and seismic data is currently being
evaluated to validate mapping and plan additional seismic and
drilling activities.  
FOX DRILLING INC. 
Fox Drilling Inc. ("Fox Drilling") now owns five triple-sized rigs in
Canada, including two new built-for-purpose walking rigs and a rig
previously owned by Paramount Drilling U.S. that was moved in the
fourth quarter of 2012 from the United States. Fox Drilling's two
original rigs drilled on the Company's lands in Alberta throughout
2012. The two new walking drilling rigs will be deployed on
multi-well pad sites in the Kaybob COU's Deep Basin development. Fox
Drilling's rigs are designed to drill the deep horizontal wells that
industry is currently focusing on in the Deep Basin of Alberta.  
INVESTMENTS IN OTHER ENTITIES 


 
Market                                                                      
 Value(1)                                                                   
As at December                                                              
 31                         2012                           2011             
----------------------------------------------------------------------------
                 Shares                         Shares                      
                (000's) ($ millions)($/share)  (000's) ($ millions)($/share)
              --------------------------------------------------------------
Trilogy Energy                                                              
 Corp.                                                                      
 ("Trilogy")     19,144 $      557.3    29.11   24,144 $      907.1    37.57
MEG Energy                                                                  
 Corp.            3,700        112.6    30.44    3,700        153.8    41.57
MGM Energy                                                                  
 Corp.           54,147         13.5     0.25   43,834         10.6     0.24
Other(2)                        21.4                            5.8         
----------------------------------------------------------------------------
Total                   $      704.8                   $    1,077.3         
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on the period-end closing price of publicly traded investments and
 book value of remaining investments.                                       
(2) Includes investments in other public and private corporations.          

 
In January 2012, Paramount closed the sale of 5.0 million of its
non-voting Trilogy shares for net cash proceeds of $181.7 million,
recognizing a gain of $157.2 million. 
CORPORATE 
In the fourth quarter of 2012, the revolving period and maturity date
of the Company's $300 million credit facility was extended to
November 30, 2013 and November 30, 2014, respectively, with all other
material terms of the credit facility remaining unchanged. 
To fund the Company's growth initiatives, Paramount raised over $700
million in aggregate cash proceeds in 2012, including over $400
million from equity offerings, the sale of investments and non-core
oil and gas properties and $300 million from the notes offering.  
OUTLOOK 
Paramount plans to invest approximately $500 million in its Principal
Properties in 2013, excluding land acquisitions and capitalized
interest, primarily focused on the Kaybob COU's Deep Basin
development. Construction of the Musreau Deep Cut Facility is
scheduled to be completed in the fourth quarter and construction of
the third-party Smoky Deep Cut Facility will continue into 2014. In
preparation for the start-up of the deep cut facilities, the Company
plans to drill and complete up to 40 new wells in Kaybob in 2013.
Budgeted activities also include the drilling, completion and tie-in
of middle Montney wells at Karr-Gold Creek. 
The Company plans to invest approximately $50 million in its
Strategic Investments in 2013, directed towards drilling and
completions in the Liard Basin and continued pre-development work for
oil sands projects within Cavalier Energy. 
Average sales volumes in January 2013 were constrained to
approximately 22,000 Boe/d and increased to approximately 23,500
Boe/d in the last week of February 2013. Paramount's ability to
maximize production through its Company-owned and firm-service
contracted capacity will likely continue to be impacted by downstream
NGLs processing and transportation constraints until the fourth
quarter of 2013.  
Sales volumes for the first three quarters of 2013 are expected to
range between 21,000 Boe/d and 25,000 Boe/d, after giving effect to
the first quarter property dispositions, depending upon the
availability of downstream NGLs transportation and processing
capacity. Sales volumes are expected to increase in the fourth
quarter once the expansion of a third-party NGLs pipeline is
completed, additional fractionation capacity is secured and the
Musreau Deep Cut Facility is on-stream.  
After the Musreau Deep Cut Facility starts up in late-2013, the
Company will have owned and firm-service contracted natural gas
processing capacity of 279 MMcf/d, which will increase to over 300
MMcf/d in 2014 with the addition of the Smoky Deep Cut Facility.
Sales volumes are expected to increase to over 50,000 Boe/d by
late-2014 as facility processes are optimized and the new long-term
NGLs processing contracts come into effect.  
FOURTH QUARTER REVIEW 
Operating Results  
Sales Volumes 


 
                                 Three months ended December 31             
                    --------------------------------------------------------
                           Natural Gas (MMcf/d)                NGLs (Bbl/d) 
                    --------------------------------------------------------
                         2012     2011 % Change      2012     2011 % Change 
----------------------------------------------------------------------------
Kaybob                   63.3     50.8       25       901      901        - 
Grande Prairie           23.5     19.4       21     1,008      480      110 
Southern                  9.0     11.1      (19)      150      191      (21)
Northern                  8.3      9.9      (16)       51       23      122 
----------------------------------------------------------------------------
Continuing Ops          104.1     91.2       14     2,110    1,595       32 
Discontinued Ops            -      0.3     (100)        -       25     (100)
----------------------------------------------------------------------------
Total                   104.1     91.5       14     2,110    1,620       30 
----------------------------------------------------------------------------
 
                                 Three months ended December 31             
                    ------------------------------------------------------- 
                                    Oil (Bbl/d)               Total (Boe/d) 
                    --------------------------------------------------------
                         2012     2011 % Change      2012     2011 % Change 
----------------------------------------------------------------------------
Kaybob                     64       62        3    11,501    9,437       22 
Grande Prairie            317      333       (5)    5,243    4,048       30 
Southern                  566      687      (18)    2,223    2,741      (19)
Northern                  266      410      (35)    1,707    2,068      (17)
----------------------------------------------------------------------------
Continuing Ops          1,213    1,492      (19)   20,674   18,294       13 
Discontinued Ops            -      864     (100)        -      929     (100)
----------------------------------------------------------------------------
Total                   1,213    2,356      (49)   20,674   19,223        8 
----------------------------------------------------------------------------

 
Netback - Continuing Operations 


 
Three months ended December 31                    2012                 2011 
----------------------------------------------------------------------------
                                            ($/Boe)(1)           ($/Boe)(1) 
  Natural gas                          33.1       3.45      30.4       3.62 
  NGLs                                 11.9      61.23      11.4      77.98 
  Oil                                   8.9      79.72      13.4      97.02 
  Royalty and sulphur revenue           0.7          -       1.0          - 
----------------------------------------------------------------------------
Petroleum and natural gas sales        54.6      28.70      56.2      33.38 
  Royalties                            (4.5)     (2.38)     (4.4)     (2.61)
  Operating expense                   (17.9)     (9.41)    (19.3)    (11.45)
  Transportation                       (5.5)     (2.91)     (5.1)     (3.03)
----------------------------------------------------------------------------
Netback                                26.7      14.00      27.4      16.29 
  Financial commodity contract                                              
   settlements                          0.7       0.38       0.3       0.18 
----------------------------------------------------------------------------
Netback including financial                                                 
 commodity contract settlements        27.4      14.38      27.7      16.47 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Natural gas revenue shown per Mcf.                                      

 
Paramount's fourth quarter average sales volumes were 20,674 Boe/d in
2012, an increase of 13 percent over the fourth quarter of 2011.
Natural gas sales volumes increased in the Kaybob COU as a result of
new production from wells producing through the Company's new Musreau
Refrig Facility. Sales volumes also increased at Valhalla in the
Grande Prairie COU where a new gathering and compression system was
commissioned in the first quarter of 2012. Sales volumes in the
Southern and Northern COUs decreased due to natural declines. 
Fourth quarter 2012 petroleum and natural gas sales were $54.6
million, a decrease of $1.6 million from the fourth quarter of 2011,
as a 14 percent decrease in average realized prices more than offset
the 13 percent increase in sales volumes.  
Natural gas and NGLs sales volumes in the fourth quarter of 2012 were
reduced due to Third Party Disruptions, which required Paramount to
restrict NGLs recovery rates and curtail production in the Kaybob and
Grande Prairie COUs. The Company estimates that average sales volumes
in the fourth quarter were reduced by approximately 3,000 Boe/d as a
result, including reduced liquids yields as the Company
preferentially flowed lower liquids content wells. Sales volumes in
December 2012 and January 2013 were constrained to approximately
22,000 Boe/d.  
Operating expenses decreased $1.4 million in the fourth quarter of
2012 compared to the prior year, as higher operating costs related to
the new Musreau Refrig Facility and new wells brought-on production
were more than offset by the impact of higher processing income and
lower third party processing fees. Operating costs per Boe decreased
to $9.41 in the fourth quarter of 2012 compared to $11.45 in the
fourth quarter of 2011. The per-unit decrease is primarily due to a
higher proportion of sales from the Kaybob COU, which has per unit
operating costs of approximately $5.00 per Boe before accounting for
the impact of third party processing income. Operating expenses in
the fourth quarter include the cost of seasonal maintenance in the
Northern COU at remote locations.  
Net Loss 


 
Three months ended December 31                              2012       2011 
----------------------------------------------------------------------------
Netback                                                     26.7       27.4 
Gain (loss) on financial commodity contracts                 0.6       (7.7)
General and administrative                                  (4.0)      (4.0)
Stock-based compensation                                    (7.0)      (6.2)
Depletion and depreciation                                (183.1)    (271.7)
Exploration and evaluation                                 (13.8)      (7.2)
Gain (loss) on sale of property, plant and equipment        (1.8)       3.0 
Interest expense                                           (11.6)      (8.6)
Other expenses                                              (0.8)      (0.9)
Loss from equity-accounted investments                      (0.4)      (1.0)
Other income                                                 3.8        3.5 
Tax Recovery                                                39.6       62.6 
----------------------------------------------------------------------------
Loss from continuing operations                           (151.8)    (210.8)
Discontinued Operations, net of tax                            -        0.9 
----------------------------------------------------------------------------
Net Loss                                                  (151.8)    (209.9)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Paramount recorded a loss from continuing operations of $151.8
million for the three months ended December 31, 2012 compared to a
loss from continuing operations of $210.8 million in the same period
of 2011.  
Significant factors contributing to the change are shown below: 


 
                                                               Three months 
                                                                      ended 
                                                                December 31 
                                                                            
Loss from continuing operations - 2011                               (210.8)
----------------------------------------------------------------------------
  Lower depletion, depreciation and impairment mainly due                   
   to lower write-downs of petroleum and natural gas                        
   properties and goodwill                                             88.6 
  Gain on financial commodity contracts compared to a loss                  
   in 2011                                                              8.3 
  Lower income tax recovery in 2012                                   (23.0)
  Higher exploration and evaluation expense                            (6.6)
  Loss on sale of property, plant and equipment compared                    
   to a gain in 2011                                                   (4.8)
  Higher interest in 2012 due to higher debt levels                    (3.0)
  Other                                                                (0.5)
----------------------------------------------------------------------------
Loss from continuing operations - 2012                               (151.8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Funds Flow from Operations(1) 


 
Three months ended December 31                               2012    2011(2)
----------------------------------------------------------------------------
Cash from operating activities                              (13.2)       7.2
Change in non-cash working capital                           27.2       14.9
Geological and geophysical expenses                           1.0        1.9
Asset retirement obligations settled                          2.7        2.1
----------------------------------------------------------------------------
Funds flow from operations                                   17.7       26.1
----------------------------------------------------------------------------
Funds flow from operations ($/Boe)                           9.29      14.73
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Refer to the advisories concerning non-GAAP measures in the Advisories  
 section of this document.                                                  
(2) Includes the results of discontinued operations.                        

 
Funds flow from operations decreased by $8.4 million in the fourth
quarter of 2012 compared to the same period in 2011, primarily as a
result the sale of the US properties, which generated $4.0 million of
funds flow from operations in the fourth quarter of 2011, and higher
interest expense. 
RESERVES 
Conventional 
Paramount achieved strong conventional reserves additions in 2012,
driven by the Company's Deep Basin development in the Kaybob COU. The
Company's conventional proved and probable reserves at December 31,
2012 increased 64 percent to 86.8 MMBoe compared to 53.0 MMBoe at
December 31, 2011, after production of 7.3 MMBoe and dispositions of
4.4 MMBoe, with a proved and probable reserves replacement ratio of
599 percent. Proved reserves increased 43 percent to 50.9 MMBoe at
December 31, 2012 from 35.7 MMBoe at December 31, 2011, with a proved
reserves replacement ratio of 336 percent. 
Hoole Oil Sands Bitumen 
Incremental to the conventional reserves additions, the Company
recorded 93.1 MMBbl of probable bitumen reserves additions related to
Cavalier Energy's 10,000 barrel per day oil sands development planned
for the Hoole Grand Rapids. These reserves volumes were recognized
following Cavalier Energy's November 2012 regulatory applications for
project approval to the ERCB and AESRD. 
Reserves Summary 
Paramount's reserves for the year ended December 31, 2012 were
evaluated by McDaniel & Associates Consultants Ltd., the Company's
independent reserves evaluator, and prepared in accordance with
National Instrument 51-101 definitions, standards and procedures. The
Company's working interest reserves and before tax net present value
of future net revenues as of December 31, 2012 using forecast prices
and costs are as follows: 


 
                                    Gross Proved and Probable Reserves(1)   
                                --------------------------------------------
                                         Light &                            
                                          Medium  Natural                   
                                  Natural  Crude      Gas                   
                                      Gas    Oil  Liquids  Bitumen     Total
                                                                            
                                                                            
                                --------------------------------------------
Reserves Category                   (Bcf) (MBbl)   (MBbl)   (MBbl) (MBoe)(2)
----------------------------------------------------------------------------
Conventional                                                                
Proved                                                                      
  Developed Producing               143.3  1,416    4,198        -    29,501
  Developed Non-producing            37.6    123    3,695        -    10,090
  Undeveloped                        21.0      -    7,769        -    11,266
----------------------------------------------------------------------------
Total Proved                        201.9  1,540   15,662        -    50,857
Total Probable                      121.8    588   15,099        -    35,985
----------------------------------------------------------------------------
Total Proved and Probable                                                   
Conventional                        323.7  2,128   30,761        -    86,842
----------------------------------------------------------------------------
                                                                            
Oil Sands Bitumen                                                           
Total Proved                            -      -        -        -         -
Total Probable                          -      -        -   93,091    93,091
----------------------------------------------------------------------------
Total Proved and Probable                                                   
Bitumen                                 -      -        -   93,091    93,091
----------------------------------------------------------------------------
                                                                            
Total Company                                                               
Total Proved                        201.9  1,540   15,662        -    50,857
Total Probable                      121.8    588   15,099   93,091   129,076
----------------------------------------------------------------------------
Total Proved and Probable           323.7  2,128   30,761   93,091   179,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Columns may not add due to rounding.                                    
(2) Refer to the oil and gas measures and definitions in the Advisories     
 section of this document.                                                  
(3) The estimated net present values disclosed in this document do not      
 represent fair market value. Revenues and expenditures were calculated     
 based on McDaniel's forecast prices and costs as of January 1, 2013.       
 
                                             Before Tax Net Present 
                                                        Value(1)(3) 
                                        ----------------------------
                                                       ($ millions) 
                                                                    
                                                      Discount Rate 
                                        --------------------------- 
        Reserves Category                      0%      10%      15% 
        ------------------------------------------------------------
        Conventional                                                
        Proved                                                      
          Developed Producing                 472      382      349 
          Developed Non-producing             122       72       57 
          Undeveloped                          55        2      (14)
        ------------------------------------------------------------
        Total Proved                          649      456      392 
        Total Probable                        774      424      3
34 
        ------------------------------------------------------------
        Total Proved and Probable                                   
        Conventional                        1,422      880      726 
        ------------------------------------------------------------
                                                                    
        Oil Sands Bitumen                                           
        Total Proved                            -        -        - 
        Total Probable                      2,065      379      140 
        ------------------------------------------------------------
        Total Proved and Probable                                   
        Bitumen                             2,065      379      140 
        ------------------------------------------------------------
                                                                    
        Total Company                                               
        Total Proved                          649      456      392 
        Total Probable                      2,839      803      474 
        -----------------------------------------------------------=
        Total Proved and Probable           3,487    1,259      866 
        ------------------------------------------------------------
        ------------------------------------------------------------
        (1) Columns may not add due to rounding.                    
        (2) Refer to the oil and gas measures and definitions in    
         the Advisories section of this document.                   
        (3) The estimated net present values disclosed in this      
         document do not represent fair market value. Revenues and  
         expenditures were calculated based on McDaniel's forecast  
         prices and costs as of January 1, 2013.                    

 
December 31, 2012 reserves include 10.1 MMBoe of proved developed
non-producing ("PDNP") reserves, mainly related to wells in the
Kaybob COU that have been drilled and are expected to come on-stream
once the deep cut facilities expansions are completed. Proved
undeveloped ("PUD") reserves totalling 11.3 MMBoe are mainly related
to certain of the locations that the Kaybob COU expects to drill over
the next year. PDNP and PUD reserves are expected to be reclassified
to proved developed producing reserves once the Musreau Deep Cut
Facility is substantially complete and the undeveloped locations are
drilled. 
Future development costs totalling $110 million in respect of
estimated costs to complete the Musreau Deep Cut Facility and Smoky
Deep Cut Facility were deducted in determining the future net revenue
of Paramount's total proved reserves; $56 million of which was
deducted from PDNP reserves values and $54 million of which was
deducted from PUD reserves values. 
Conventional Reserves 
The following table summarizes future development costs deducted in
the calculation of future net revenue from conventional reserves: 


 
                                                  Future Development Costs -
                                                                Undiscounted
                                                 ---------------------------
                                           Before                           
                                              Tax           Wells &         
                                   Total NPV10(1)   Plants    Other    Total
                               ---------------------------------------------
                                  (Mboe)    ($MM)    ($MM)    ($MM)    ($MM)
Proved Developed Producing        29,501      382        -        -        -
Proved Developed Non-Producing    10,090       72       56       21       77
Proved Undeveloped                11,266        2       54      118      172
----------------------------------------------------------------------------
Total Proved                      50,857      456      110      139      249
Total Probable                    35,985      424        -      158      158
----------------------------------------------------------------------------
Total Proved and Probable         86,842      880      110      297      407
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The estimated net present values disclosed in this document do not      
 represent fair market value. Revenues and expenditures were calculated     
 based on McDaniel's forecast prices and costs as of January 1, 2013.       

 
Reserves Reconciliation 


 
                                                         Proved Reserves(1) 
                                     ---------------------------------------
                                       Natural   Oil and                    
                                           Gas   NGLs(2)   Bitumen    Total 
                                     ---------------------------------------
                                         (Bcf)    (MBbl)    (MBbl)(MBoe)(3) 
----------------------------------------------------------------------------
January 1, 2012                          162.0     8,673         -   35,666 
Extensions & discoveries                  74.4     9,058         -   21,464 
Technical revisions                       (1.3)    3,205         -    2,997 
Economic factors                             -         -         -        - 
Acquisitions                               6.9       242         -    1,395 
Dispositions                              (4.1)   (2,700)        -   (3,376)
Production                               (36.1)   (1,278)        -   (7,290)
----------------------------------------------------------------------------
December 31, 2012                        201.9    17,202         -   50,857 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Columns and rows may not add due to rounding.                           
(2) Light and medium crude oil and natural gas liquids.                     
(3) Refer to the oil and gas measures and definitions in the Advisories     
 section of this document.                                                  
 
                                            Proved and Probable Reserves(1) 
                                     ---------------------------------------
                                       Natural   Oil and                    
                                           Gas   NGLs(2)   Bitumen    Total 
                                     ---------------------------------------
                                         (Bcf)    (MBbl)    (MBbl)(MBoe)(3) 
----------------------------------------------------------------------------
January 1, 2012                          244.1    12,333         -   53,015 
Extensions & discoveries                 148.8    21,167    93,091  139,058 
Technical revisions                      (31.9)    3,801         -   (1,517)
Economic factors                          (4.5)       (2)        -     (749)
Acquisitions                               9.0       318         -    1,820 
Dispositions                              (5.7)   (3,450)        -   (4,406)
Production                               (36.1)   (1,278)        -   (7,290)
----------------------------------------------------------------------------
December 31, 2012                        323.7    32,889    93,091  179,933 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Columns and rows may not add due to rounding.                           
(2) Light and medium crude oil and natural gas liquids.                     
(3) Refer to the oil and gas measures and definitions in the Advisories     
 section of this document.                                                  

 
Finding and Development Costs 
Paramount's finding and development ("F&D") costs per barrel are
summarized below. The total F&D capital includes costs and changes in
future development costs relating to major facilities and gathering
system projects. 


 
                                                               2012 F&D Cost
                                      Including Major Facilities & Gathering
                      ------------------------------------------------------
                                        FDC    Total F&D     Reserves       
                         Costs(1)  Change(1)   Capital(1) Additions(2)   F&D
                             $MM        $MM          $MM        MMBoe  $/Boe
                                                                            
PROVED                                                                      
Total Company              526.0      211.2        737.1         24.5  30.14
 Kaybob                    362.5      223.0        585.5         21.4  27.35
 Total Conventional        523.1      211.2        734.2         24.5  30.02
                                                                            
PROVED & PROBABLE                                                           
Total Company              526.0    1,871.5      2,397.4        136.8  17.53
 Kaybob                    362.5      378.5        740.9         45.5  16.29
 Total Conventional        523.1      331.9        854.9         43.7  19.56
 Oil Sands Bitumen           2.9    1,539.6      1,542.5         93.1  16.57
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 (1) The aggregate of the exploration and development costs incurred in the 
  most recent financial year and the change during that year in estimated   
  future development costs generally will not reflect total finding and     
  development costs related to reserve additions for that year.             
 (2)Refer to the oil and gas measures and definitions in the Advisories     
  section of this document.                                                 
 
                                    3-Year Average F&D
                      --------------------------------
                                                3-Year
                            2011      2010     Average
                           $/Boe     $/Boe       $/Boe
                                                      
PROVED                                                
Total Company              42.29     29.10       33.15
 Kaybob                    27.06     19.63       26.41
 Total Conventional        41.57     27.45       32.61
                                                      
PROVED & PROBABLE                                     
Total Company              37.58     28.50       19.63
 Kaybob                    21.56     16.30       17.27
 Total Conventional        36.92     26.91       23.80
 Oil Sands Bitumen             -         -       16.71
------------------------------------------------------
------------------------------------------------------
 (1) The aggregate of the exploration and development 
  costs incurred in the most recent financial year and
  the change during that year in estimated future     
  development costs generally will not reflect total  
  finding and development costs related to reserve    
  additions for that year.                            
 (2)Refer to the oil and gas measures and definitions 
  in the Advisories section of this document.         

 
Paramount's F&D costs per barrel, excluding costs and changes in
future development costs related to major facilities and gathering
system projects are summarized below. 


 
                                                               2012 F&D Cost
                                      Excluding Major Facilities & Gathering
                      ------------------------------------------------------
                                      FDC   Total F&D     Reserves          
                        Costs(1) Change(1)  Capital(1) Additions(2)      F&D
                            $MM       $MM         $MM        MMBoe     $/Boe
                                                                            
PROVED                                                                      
  Kaybob                  200.7     112.7       313.4         21.4     14.64
  Total Conventional      310.6     100.9       411.5         24.5     16.82
                                                                            
PROVED & PROBABLE                                                           
  Kaybob                  200.7     268.2       468.9         45.5     10.31
  Total Conventional      310.6     221.6       532.2         43.7     12.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The aggregate of the exploration and development costs incurred in the  
 most recent financial year and the change during that year in estimated    
 future development costs generally will not reflect total finding and      
 development costs related to reserve additions for that year.              
(2) Refer to the oil and gas measures and definitions in the Advisories     
 section of this document.                                                  
 
                               3-Year Average F&D
                      ---------------------------
                                           3-Year
                           2011     2010  Average
                          $/Boe    $/Boe    $/Boe
                                                 
PROVED                                           
  Kaybob                  17.85    15.79    15.67
  Total Conventional      27.70    21.04    20.39
                                                 
PROVED & PROBABLE                                
  Kaybob                  13.57    13.18    11.14
  Total Conventional      24.19    20.76    15.53
-------------------------------------------------
-------------------------------------------------
(1) The aggregate of the exploration and         
 development costs incurred in the most recent   
 financial year and the change during that year  
 in estimated future development costs generally 
 will not reflect total finding and development  
 costs related to reserve additions for that     
 year.                                           
(2) Refer to the oil and gas measures and        
 definitions in the Advisories section of this   
 document.                                       

 
Capital Expenditures 


 
Year ended December 31                                      2012        2011
----------------------------------------------------------------------------
Geological and geophysical                                   6.0         5.5
Drilling, completion and tie-ins                           304.6       303.7
Facilities and gathering                                   212.5       156.5
----------------------------------------------------------------------------
Exploration and development expenditures                   523.1       465.7
Land and property acquisitions                              25.2        38.2
----------------------------------------------------------------------------
Principal Properties                                       548.3       503.9
Strategic Investments(1)                                    82.5        28.0
Corporate                                                    0.4         0.1
----------------------------------------------------------------------------
                                                           631.2       532.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Strategic Investments includes $7.0 million of undeveloped land         
 purchases.                                                                 
                                                                            
LAND                                                                        
As at December 31                            2012                       2011
----------------------------------------------------------------------------
(000's of acres)                          Average                    Average
                                          Working                    Working
                       Gross(1)   Net(2) Interest Gross(1)   Net(2) Interest
----------------------------------------------------------------------------
Undeveloped land          1,685    1,190      71%    1,736    1,225      71%
Acreage assigned                                                            
 reserves                   523      289      55%      574      334      58%
----------------------------------------------------------------------------
Total                     2,208    1,479      67%    2,310    1,559      67%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) "Gross" acres means the total acreage in which Paramount has an         
 interest.                                                                  
(2) "Net" acres means gross acres multiplied by Paramount's working interest
 therein.                                                                   

 
ADDITIONAL INFORMATION 
Advance Notice Requirement for Nominating Directors 
Paramount's board of directors today approved the adoption of Amended
and Restated By-laws of the Corporation ("By-laws") which include an
advance notice requirement ("Advance Notice Requirement") for
shareholders who wish to nominate a person for election as a director
of the Corporation (other than pursuant to a requisition of a
meeting, or a shareholder proposal, made pursuant to the provisions
of the Alberta Business Corporations Act).  
The purpose of the Advance Notice Requirement is to provide
shareholders, directors and management of the Corporation with a
clear framework for nominating directors. Among other things, the
Advance Notice Requirement fixes a deadline by which shareholders
must submit a notice of director nominations to the Corporation prior
to any annual or special meeting of shareholders where directors are
to be elected, and sets out the information that must be included in
the notice for it to be valid. In the case of an annual meeting of
shareholders, notice must be given to the Corporation not less than
30 days nor more than 65 days prior to the date of the annual
meeting; provided, that if the first public announcement of the
meeting is given less than 50 days prior to the meeting date notice
must be given not later than the close of business on the 10th day
following such public announcement. 
In the case of a special meeting of shareholders (which is not also
an annual meeting), notice must be given to the Corporation not later
than the close of business on the 15th day following the first public
announcement of the date of the special meeting. 
Advance notice requirements have been adopted by a number of Canadian
issuers, and the deadlines in Paramount's Advance Notice Requirement
are supported by Institutional Shareholder Services Inc.  
The By-laws (including the Advance Notice Requirement) are effective
immediately. At the annual meeting of shareholders to be held on May
8, 2013, shareholders will be asked to confirm and ratify the
By-laws. A copy of the By-laws will be made available under the
Company's profile at www.sedar.com.  
ABOUT PARAMOUNT 
Paramount Resources Ltd. is a Canadian oil and natural gas
exploration, development and production company with operations
focused in Western Canada. Paramount's common shares are listed on
the Toronto Stock Exchange under the symbol "POU". 
A copy of this press release in PDF format can be obtained at
http://media3.marketwire.com/docs/307pou_pr.pdf. Paramount's
Management's Discussion and Analysis for the year ended December 31,
2012 can be found at http://media3.marketwire.com/docs/307pou_mda.pdf
and the Company's Consolidated Financial Statements for the year
ended December 31, 2012 can be obtained at
http://media3.marketwire.com/docs/307pou_fins.pdf. This information
will also be made available through Paramount's website at
www.paramountres.com and SEDAR at www.sedar.com. 
Paramount's Annual Information Form ("AIF") for the year ended
December 31, 2012, which includes the disclosure and reports relating
to reserves data and other oil and gas information required pursuant
to National Instrument 51-101, will also be made available through
Paramount's website at www.paramountres.com and SEDAR at
www.sedar.com. 
ADVISORIES 
FORWARD-LOOKING INFORMATION 
Certain statements in this document constitute forward-looking
information under applicable securities legislation. Forward-looking
information typically contains statements with words such as
"anticipate", "believe", "estimate", "expect", "plan", "schedule",
"intend", "propose", or similar words suggesting future outcomes or
an outlook. Forward looking information in this document includes,
but is not limited to: 


 
--  expected production and sales volumes and the timing thereof; 
--  exploration, development and strategic investment plans and strategies
    and the anticipated costs, timing, and results thereof; 
--  budget allocations and capital spending flexibility; 
--  the availability and adequacy of facilities to process, de-ethanize,
    fractionate and transport natural gas and NGLs production; 
--  the scope, timing, and cost of proposed new facilities and facilities
    expansions and the expected capacity and benefits of such facilities; 
--  the negotiation and completion of arrangements for the transportation
    and sales of natural gas,  NGLs, and bitumen; 
--  the timing and scope of the anticipated development of oilsands,
    carbonate bitumen, and shale gas assets; 
--  expected drilling programs, well tie-ins, facility construction and
    expansions, completions and the timing, scope and results thereof;    
--  estimated reserves and resources and the undiscounted and discounted
    present value of future net revenues from such reserves and resources
    (including the forecast prices and costs and the timing of expected
    production volumes and future development capital); 
--  future taxes payable or owing; 
--  business strategies and objectives; 
--  sources of and plans for funding Paramount's exploration, development,
    facilities and other expenditures; 
--  acquisition and disposition plans; 
--  operating and other costs and royalty rates; 
--  regulatory applications and the anticipated timing, results and scope
    thereof; and  
--  the outcome and timing of any legal claims, insurance claims, audits,
    assessments and regulatory matters and proceedings. 

 
Such forward-looking information is based on a number of assumptions
which may prove to be incorrect. The following assumptions have been
made, in addition to any other assumptions identified in this
document: 


 
--  future oil, gas, NGLs, and bitumen prices and general economic,
    business, and market conditions; 
--  the ability to obtain required capital, through access to capital
    markets and other means, to finance  exploration and development
    activities and new and expanded facilities; 
--  the ability to obtain equipment, services, supplies and personnel in a
    timely manner and at an acceptable cost to carry out activities; 
--  the ability to market oil, natural gas, NGLs and bitumen successfully to
    current and new customers; 
--  the ability to secure adequate product processing, fractionation,
    transportation and storage;    
--  the ability of Paramount and its industry partners to obtain drilling
    success and production levels consistent with expectations, including
    with respect to anticipated reserves additions and NGLs yields; 
--  the timely receipt of required regulatory approvals; 
--  expected timelines and budgets being met and anticipated results
    achieved, in respect of facilities and infrastructure development; 
--  anticipated rates of return from existing and planned projects relative
    to other opportunities; 
--  estimates of input and labour costs; and 
--  currency exchange and interest rates. 

 
Although Paramount believes that the expectations reflected in such
forward looking information is reasonable, undue reliance should not
be placed on it as Paramount can give no assurance that such
expectations will prove to be correct. Forward-looking information is
based on current expectations, estimates and projections that involve
a number of risks and uncertainties which could cause actual results
to differ materially from those anticipated by Paramount and
described in the forward looking information. These risks and
uncertainties include, but are not limited to: 


 
--  fluctuations in oil, natural gas, NGLs and bitumen prices and commodity
    price differentials; 
--  fluctuations in foreign currency exchange rates and interest rates; 
--  the uncertainty of estimates and projections relating to future revenue,
    future production, NGLs yields, costs and expenses and the timing
    thereof; 
--  the ability to secure adequate product processing, de-ethanization,
    fractionation, transportation and storage; 
--  uncertainties associated with exploration and development drilling and
    related activities; 
--  operational risks in exploring for, developing and producing oil,
    natural gas, NGLs and bitumen and the timing thereof; 
--  the ability to obtain equipment, services, supplies and personnel in a
    timely manner and at an acceptable cost; 
--  potential disruptions, unexpected technical difficulties or other
    constraints in designing, developing, operating or utilizing new,
    expanded or existing facilities, including third-party facilities; 
--  risks and uncertainties involving the geology of oil and gas deposits; 
--  the uncertainty of reserves and resource estimates; 
--  the ability to generate sufficient cash flow from operations and obtain
    other sources of financing at an acceptable cost to fund planned
    operational, exploration and development activities, including costs of
    anticipated new and expanded facilities and other projects, and to meet
    current and future obligations; 
--  the ability to fulfill pipeline transportation, processing, de-
    ethanization and fractionation commitments;   
--  changes to, or in the interpretation or application of, laws,
    regulations or policies; 
--  changes in environmental laws including potential emission reduction
    obligations and fracing regulations; 
--  the receipt, timing, and scope of governmental or regulatory approvals; 
--  potential title defects affecting Paramount's properties; 
--  uncertainties regarding aboriginal land claims and co-existing with
    local populations and stakeholders; the effects of weather; 
--  the timing and cost of future abandonment and reclamation activities; 
--  clean-up costs or business interruptions resulting from environmental
    damage and contamination; 
--  the ability to enter into or continue leases; 
--  existing and potential lawsuits and regulatory actions; 
--  general economic, business and market conditions; 
--  industry wide pipeline, processing, de-ethanization and fractionation
    constraints; and 
--  other risks and uncertainties described elsewhere in this document and
    in Paramount's other filings with Canadian securities authorities. 

 
The foregoing list of risks is not exhaustive. Additional information
concerning these and other factors which could impact Paramount, its
operations and its financial condition are included in Paramount's
Annual Information Form for the year ended December 31, 2012. The
forward-looking information contained in this document is made as of
the date hereof and, except as required by applicable securities law,
Paramount undertakes no obligation to update publicly or revise any
forward-looking statements or information, whether as a result of new
information, future events or otherwise. 
NON-GAAP MEASURES 
In this document "Funds flow from operations", "Funds flow from
operations - per Boe", "Funds flow from operations per share -
diluted", "Netback", "Netback including commodity & insurance
settlements", "Net Debt", "Exploration and development expenditures"
and "Investments in other entities - market value", collectively the
"Non-GAAP measures", are used and do not have any standardized
meanings as prescribed by Generally Accepted Accounting Principles in
Canada ("GAAP").  
Funds flow from operations refers to cash from operating activities
before net changes in operating non-cash working capital, geological
and geophysical expenses and asset retirement obligation settlements.
Funds flow from operations is commonly used in the oil and gas
industry to assist management and investors in measuring the
Company's ability to fund capital programs and meet financial
obligations. Netback equals petroleum and natural gas sales less
royalties, operating costs, production taxes and transportation
costs. Netback is commonly used by management and investors to
compare the results of the Company's oil and gas operations between
periods. Net Debt is a measure of the Company's overall debt position
after adjusting for certain working capital amounts and is used by
management to assess the Company's overall leverage position. Refer
to the calculation of Net Debt in the liquidity and capital resources
section of Paramount's Management's Discussion and Analysis.
Exploration and development expenditures refer to capital
expenditures and geological and geophysical costs incurred by the
Company's COUs (excluding land and acquisitions). The exploration and
development expenditure measure provides management and investors
with information regarding the Company's Principal Property spending
on drilling and infrastructure projects, separate from land
acquisition activity. Investments in other entities - market value
reflects the Company's investments in enterprises whose securities
trade on a public stock exchange at their period end closing price
(e.g. Trilogy, MEG Energy, MGM Energy and others), and investments in
all other entities at book value. Paramount provides this information
because the market values of equity-accounted investments, which are
significant assets of the Company, are often materially different
than their carrying values.  
Non-GAAP measures should not be considered in isolation or construed
as alternatives to their most directly comparable measure calculated
in accordance with GAAP, or other measures of financial performance
calculated in accordance with GAAP. The Non-GAAP measures are
unlikely to be comparable to similar measures presented by other
issuers. 
OIL AND GAS MEASURES AND DEFINITIONS 
This document contains disclosures expressed as "Boe" and "Boe/d".
All oil and natural gas equivalency volumes have been derived using
the ratio of six thousand cubic feet of natural gas to one barrel of
oil. Equivalency measures may be misleading, particularly if used in
isolation. A conversion ratio of six thousand cubic feet of natural
gas to one barrel of oil is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent
a value equivalency at the well head. The term "liquids" is used to
represent oil and natural gas liquids.  
During the 2012, the value ratio between crude oil and natural gas
was approximately 31:1. This value ratio is significantly different
from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be
misleading as an indication of value. 
The reserves replacement disclosure herein was calculated as the net
increase in proved and probable reserves estimates from extensions
and discoveries, technical revisions and economic factors divided by
the total production in the year.  
Oil Sands Resource Notes: 
High Estimate is considered to be an optimistic estimate of the
quantity of resource that will actually be recovered. It is unlikely
that the actual remaining quantities of resources recovered will meet
or exceed the high estimate. Those resources at the high end for the
estimate range have a lower degree of certainty (a 10 percent
confidence level) that the actual quantities recovered will equal or
exceed the estimate.   
Best Estimate is considered to be the best estimate of the quantity
that will be actually recovered. It is equally likely that the actual
remaining quantities recovered will be greater or less than the best
estimate. Those resources that fall within the best estimate have a
50 percent confidence level that the actual quantities recovered will
equal or exceed the estimate.   
Low Estimate is considered to be a conservative estimate of the
quantity of resources that will actually be recovered. It is likely
that the actual remaining quantities recovered will exceed the low
estimate. Those resources at the low end of the estimate range have
the highest degree of certainty (a 90 percent confidence level) that
the actual quantities recovered will equal or exceed the estimate.   
Discovered Exploitable Bitumen In Place ("DEBIP") is the estimated
volume of bitumen, as of a given date, which is contained in a
subsurface stratigraphic interval of a known accumulation that meets
or exceeds certain reservoir characteristics, such as minimum
continuous net pay, porosity and mass bitumen content. For the
Remaining Hoole Leases, the presence of these characteristics is
considered necessary for the commercial application of known recovery
technologies. There is no certainty that it will be commercially
viable to produce any portion of the resources from the Remaining
Hoole Leases.  
Contingent Resources are those quantities of bitumen estimated, as of
a given date, to be potentially recoverable from known accumulations
using established technology or technology under development, but are
classified as a resource rather than a reserve due to one or more
contingencies, such as the absence of regulatory applications,
detailed design estimates or near term development plans. There is no
certainty that it will be commercially viable to produce any portion
of the contingent resources. For the Remaining Hoole Leases,
contingencies which must be overcome to enable the reclassification
of bitumen contingent resources as reserves include the finalization
of plans for the development, submission of a regulatory application
and management's intent to proceed evidenced by a development plan
with major capital expenditures. Economic Contingent Resources are
those contingent resources that are economically recoverable based on
specific forecasts of commodity prices and costs (based on McDaniel's
forecast prices and costs as of January 1, 2013). Volumes presented
are working interest, before the deduction of royalties.  
NPV means net present value and represents Cavalier Energy's share of
future net revenue, before the deduction of income tax, from the
economic contingent resources in the Grand Rapids formation within
the Remaining Hoole Leases. The calculation considers such items as
revenues, royalties, operating costs, abandonment costs and capital
expenditures. Royalties have been calculated based on Alberta's
Royalty Framework applicable to oil sands projects. The calculation
does not consider financing costs and general and administrative
costs. NPVs were calculated assuming natural gas is used as a fuel
for steam generation. Revenues and expenditures were calculated based
on McDaniel's forecast prices and costs as of January 1, 2013. The
estimated net present values disclosed in this press release do not
represent fair market value. 
Contacts:
Paramount Resources Ltd.
J.H.T. (Jim) Riddell
President and Chief Operating Officer
(403) 290-3600
(403) 262-7994 (FAX) 
Paramount Resources Ltd.
B.K. (Bernie) Lee
Chief Financial Officer
(403) 290-3600
(403) 262-7994 (FAX)
www.paramountres.com
 
 
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