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 $300 million credit facility was undrawn.
Financial and Operating Highlights(1)(2)
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($ millions, except as noted)
Three months ended
December 31 Year ended December 31
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2012 2011 % Change 2012 2011 % Change
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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
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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)
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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) ($/Boe) 12.18 24.19 (50)
Conventional reserves replacement (proved and
probable) 599% 193%
NPV10 future net revenue before tax
Proved 455.9 611.4 (25)
Proved and probable 1,259.3 832.2 51
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(1) Readers are referred to the advisories concerning non-GAAP measures and
oil and gas definitions in the Advisories section of this document.
(2) Amounts include the results of discontinued operations. Refer to page
seven of Paramount's Management's Discussion and Analysis for the year
ended December 31, 2012.
(3) Based on the period-end closing prices of publicly traded enterprises
and the book value of the remaining investments.
(4) Net debt is a non-GAAP measure, it is calculated and defined in the
Liquidity and Capital Resources section of Paramount's Management's
Discussion and Analysis for the year ended December 31, 2012.
(5) Working interest reserves before royalty deductions. Net present values
were determined using forecast prices and costs and do not represent fair
market value.
REVIEW OF OPERATIONS(1)
2012 2011 % Change
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Sales Volumes
Natural gas (MMcf/d) 98.5 81.6 21
NGLs (Bbl/d) 1,873 1,542 21
Oil (Bbl/d) 1,620 2,291 (29)
------------------------------------
Total (Boe/d) 19,917 17,426 14
------------------------------------
% Change
Netbacks ($ 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)
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(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 $1.4 million compared to 2011 primarily due to the
disposition of the US properties, partially offset by higher operating expenses
from continuing operations.
Kaybob
2012 2011 % Change
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Sales Volumes
Natural gas (MMcf/d) 59.5 44.5 34
NGLs (Bbl/d) 924 868 6
Oil (Bbl/d) 62 72 (14)
------------------------------------
Total (Boe/d) 10,910 8,361 30
------------------------------------
Exploration and Development
Expenditures ($ 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
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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
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Subtotal - Current Capacity 215 79 15,620
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Future Processing Capacity
---------------------------
Musreau Deep-Cut Facility 200 200 50,000
Smoky Deep-Cut Facility 200 30 7,500
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Subtotal - Future Capacity 400 230 57,500
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Projected Total 615 309 73,120
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(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
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(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
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(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
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43 35 71
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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
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188 93 57,300 28,400
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(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
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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
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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 production 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 774 424 334
------------------------------------------------------------
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.
FOR FURTHER INFORMATION PLEASE CONTACT:
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
Paramount Resources (TSX:POU)
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