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.
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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