Paramount Resources Ltd. (TSX:POU)
2011 OVERVIEW
Principal Properties
-- Proved reserves increased by 39 percent to 35.7 MMBoe. Proved plus
probable reserves increased by 32 percent to 53.0 MMBoe. The Company
replaced 193 percent of 2011 production.
-- Proved plus probable finding and development costs, excluding facilities
and gathering system construction costs, were $24.19/Boe for the Company
and $13.57/Boe for the Kaybob COU.
-- Average sales volumes in 2011 increased 34 percent to 17,426 Boe/d.
Netback increased 34 percent to $127.8 million in 2011 compared to $95.1
million in 2010.
-- The Kaybob COU increased its sales volumes by 86 percent to 8,361 Boe/d
in 2011 compared to 4,495 Boe/d in 2010. Construction of phase two of
the Musreau facility, an incremental 200 MMcf/d deep cut liquids
extraction plant, will begin in 2012. Procurement of long lead-time
equipment has already commenced.
-- In May 2011, Paramount completed its acquisition of ProspEx Resources
Ltd. ("ProspEx"), adding significant land holdings and producing assets
in the Deep Basin at Kakwa, Elmworth and Wapiti and land holdings at
Pembina and Brazeau in Southern Alberta.
-- The Southern COU divested non-core properties during the first quarter
of 2012 at West Pembina, Alberta and Kindersley, Saskatchewan for total
proceeds of approximately $50 million.
-- In the first quarter of 2012 Paramount and its wholly-owned subsidiary
Summit Resources, Inc. ("Summit") initiated a process to sell Summit and
its United States properties.
Strategic Investments
-- The market value of Paramount's portfolio of investments in other oil
and gas entities increased 114 percent to $1.1 billion at December 31,
2011, primarily due to an increase in the market price of Trilogy Energy
Corp. ("Trilogy") shares. In January 2012, Paramount received $189.5
million in gross proceeds from the sale of 5.0 million of its 24.1
million Trilogy shares.
-- In July 2011, the Company received an updated independent evaluation of
its bitumen resources within the Grand Rapids formation at its Hoole oil
sands property. Estimated economic contingent bitumen resources
increased 20 percent from the April 2010 evaluation to 763 million
barrels (Best Estimate (P50)). The before- tax net present value of
future net revenue of such economic contingent resources, discounted at
ten percent (Best Estimate (P50)), increased 49 percent to $2.8 billion.
-- In November 2011, Paramount reorganized all of the Company's oil sands
and carbonate bitumen interests into a new wholly-owned subsidiary;
Cavalier Energy Inc. ("Cavalier Energy"). The reorganization was
undertaken to create a focused, self-funding oil sands entity in order
to accelerate the development of Paramount's bitumen interests.
Corporate
-- Between December 2010 and November 2011, Paramount raised approximately
$650 million through debt and equity issuances, providing financial
flexibility to support the Company's plans for a large-scale Deep Basin
liquids-rich natural gas development and strengthening its balance
sheet.
-- General and administrative costs per Boe decreased 17 percent in 2011 to
$2.66 per Boe compared to $3.19 per Boe in 2010.
FINANCIAL AND OPERATING HIGHLIGHTS (1)
Three months ended
December 31 Year ended December 31
($ millions, except as % %
noted) 2011 2010 Change 2011 2010 Change
----------------------------------------------------------------------------
Financial
Petroleum and natural
gas sales 63.3 46.0 38 241.7 184.4 31
Funds flow from
operations(2) 26.1 21.3 23 96.2 94.0 2
Per share - basic and
diluted ($/share) 0.33 0.29 14 1.23 1.29 (5)
Net loss (209.9) (106.3) (97) (232.0) (90.0) (158)
Per share - basic and
diluted ($/share) (2.54) (1.44) (76) (2.96) (1.24) (139)
Exploration and
development
expenditures 144.1 78.6 83 465.7 199.0 134
Investments in other
entities - market
value(3) 1,077.3 502.9 114
Total assets 1,725.7 1,391.3 24
Net debt 513.4 295.2 74
Common shares
outstanding (thousands) 85,500 75,183 14
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Operating
Sales volumes
Natural gas (MMcf/d) 91.5 60.4 51 81.6 57.7 41
NGLs (Bbl/d) 1,620 1,030 57 1,542 932 65
Oil (Bbl/d) 2,356 2,357 - 2,291 2,485 (8)
Total (Boe/d) 19,223 13,461 43 17,426 13,029 34
Gas weighting 79% 75% 78% 74%
Average realized price
Natural gas ($/Mcf) 3.65 4.04 (10) 4.10 4.50 (9)
NGLs ($/Bbl) 81.27 75.52 8 82.24 70.58 17
Oil ($/Bbl) 94.33 75.45 25 87.81 72.30 21
Net wells drilled 13 9 44 75 88 (15)
Net undeveloped land
(thousands of acres) 1,225 1,198 2
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Reserves(4)
Proved plus probable
Natural gas (Bcf) 244.1 181.8 34
Crude oil and NGLs
(MBbl) 12,333 9,782 26
Total (MBoe) 53,015 40,087 32
Finding and development costs before facilities
expenditures (proved plus probable) ($/boe) 24.19 20.76 17
Reserves replacement
(proved plus probable) 193% 160%
NPV future net revenue
before tax @ 10%
Proved 611.4 397.8 54
Proved plus probable 832.2 556.0 50
(1) Readers are referred to the advisories concerning non-GAAP
measures and oil and gas measures and definitions in the
"Advisories" section of this document.
(2) The Company has adjusted its funds flow from operations
measure for all periods presented. Refer to the advisories
concerning non-GAAP measures in the "Advisories" section of this
document.
(3) Based on the period-end closing prices of publicly traded
enterprises and book value of the remaining investments.
(4) Working interest reserves before royalty deductions, using
forecast prices and costs.
REVIEW OF OPERATIONS
KAYBOB 2011 2010 % Change
----------------------------------------------------------------------------
Sales Volumes
Natural Gas (MMcf/d) 44.5 23.5 89
NGLs (Bbl/d) 868 495 75
Oil (Bbl/d) 72 79 (9)
------------------------------------------------------------------
Total (Boe/d) 8,361 4,495 86
------------------------------------------------------------------
Exploration and Development Expenditures(1)($
millions)
Exploration, drilling, completions and tie-
ins 171.2 61.8 177
Facilities and gathering 91.6 14.4 536
------------------------------------------------------------------
262.8 76.2 245
------------------------------------------------------------------
Gross Net Gross Net
----------------------------------------------------------------------------
Total Land Holdings (sections) 792 441 703 474
----------------------------------------------------------------------------
Wells drilled 28 18 16 7
--------------------
(1) Before the deduction of Alberta Drilling Royalty
credits.
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. The Company has assembled an
extensive land holding of 792 (441 net) sections with varying
rights to multiple formations from the Cretaceous to the Montney.
With well densities of up to eight wells per section per formation
forecast to be required to recover these resources, Paramount's
Deep Basin land position represents a multi-decade inventory of
drilling locations.
Paramount is executing a large-scale development on these lands
that is expected to significantly increase the Kaybob COU's
production volumes. The Company's drilling activities over the past
few years have substantially de-risked the Cretaceous Dunvegan and
Falher formations, which are high pressure, liquids rich, tight gas
formations with large reserves potential. With the high liquids
content in these formations, these plays continue to be economic
despite the current low natural gas price environment. Paramount
has also continued the evaluation of its Montney holdings, a deeper
horizon in which the Company's initial wells have exhibited higher
liquids yields than the Cretaceous zones and are expected to
provide higher rates of return despite higher drilling costs
related to increased depths. A combination of Cretaceous and
Montney opportunities will support the Company's accelerated
development plans and the construction of deep-cut processing
facilities.
Average daily sales volumes in the Kaybob COU during 2011 were
8,361 Boe/d, an increase of 86 percent compared to 2010. The
increase was primarily the result of new wells being brought on in
Musreau and Resthaven, and wells added through the acquisition of
ProspEx. During the year, the Kaybob COU reached the limit of its
available owned capacity, contracted firm service capacity and
interruptible processing capacity, which resulted in the temporary
shut-in of a number of wells. In mid-December the Company completed
construction of its new 45 MMcf/d processing facility at Musreau. A
key electrical component within the facility failed shortly after
start-up, resulting in the plant having to be shut-down for
repairs. Commissioning of the facility is underway, and gas sales
are expected to recommence in mid-March.
During 2011 the Kaybob COU drilled 28 (18.3 net) wells,
completed and tied-in 17 (10.0 net) wells, including 10 (6.8 net)
operated Falher and Dunvegan wells. Subsequent to year-end, an
additional seven (3.8 net) Falher and Dunvegan wells were
completed, of which three (3.0 net) were equipped and tied-in. Some
of these wells are shut-in in preparation for the Musreau plant to
be ramped up to design capacity before they are brought on
production. Paramount currently has an additional two (2.0 net)
Falher and Dunvegan wells awaiting completion and tie-in. The
following table summarizes test results and average natural gas
sales volumes for operated Cretaceous wells rig released during
2011:
http://media3.marketwire.com/docs/306pou1.jpg
The Company has assembled a total of 209 (176 net) sections of
Montney rights, and has drilled and completed five (4.5 net)
horizontal wells to date. The first Montney well (0.5 net) was
tied-in during 2011, with sales volumes averaging approximately 4.1
MMcf/d of natural gas and 79 Bbl/MMcf of NGLs over its first 90
days of production. The company anticipates two (2.0 net) Montney
wells will be brought on production in the third quarter of 2012.
The following table summarizes test results and average natural gas
sales volumes for operated Montney wells rig released during
2011:
http://media3.marketwire.com/docs/306pou2.jpg
The Kaybob COU is currently operating four drilling rigs on its
Deep Basin properties, and the Company has commissioned the
construction of an additional two triple-sized walking rigs to be
owned and operated by Fox Drilling Inc. ("Fox Drilling"), a
wholly-owned subsidiary of Paramount, that are expected to drill on
the Kaybob lands during the 2012/2013 winter drilling season. The
Company plans to drill and complete additional wells throughout
2012 and 2013 in preparation for new processing capacity that will
be added during the second half of 2013, and in the interim will
produce volumes held behind pipe on interruptible service to
maximize value. The Kaybob COU currently anticipates drilling up to
27 (18.3 net) wells in 2012, including up to five (4.0 net) Montney
wells.
Design and procurement of long lead-time equipment has commenced
for phase two of the Musreau processing facility, an incremental
200 MMcf/d deep cut liquids extraction facility. Construction is
anticipated to begin this fall once regulatory approvals have been
obtained. The incremental capacity will be used to process
Paramount natural gas as well as third party natural gas for a fee.
It is anticipated that construction of this second phase will be
completed during the second half of 2013 at an estimated cost of
$180 million. The addition of deep cut facilities will add
significant value to Paramount's natural gas production due to the
price premium realized from the extraction and sale of additional
NGLs volumes that would otherwise be sold as slightly higher heat
content natural gas.
At Smoky, procurement activities relating to the expansion of a
non-operated processing plant have also commenced, with orders
being placed for long lead-time components. The existing 100 MMcf/d
(10 MMcf/d net) facility is being expanded to 300 MMcf/d (60 MMcf/d
net) and upgraded to operate as a deep cut liquids extraction
facility. Initially, compression capacity for 200 MMcf/d will be
installed, with an additional 100 MMcf/d of compression to be added
when production volumes warrant the investment, thereby deferring a
portion of the capital costs. The expansion is expected to be
completed in late-2013.
With the start-up of the first phase of the Musreau plant,
Paramount will have 49 MMcf/d of Company owned capacity and 10
MMcf/d of firm-service third-party processing capacity in
Musreau-Kakwa. Paramount also has 20 MMcf/d of Company-owned
processing capacity in the Resthaven-Smoky area. Throughout 2012
and into 2013, the Company expects to have an aggregate of 79
MMcf/d of Company-owned and third party firm service capacity and
will utilize interruptible service where available until the
expansions of the Musreau and Smoky plants are completed. Paramount
currently has access to an additional 10 to 12 MMcf/d of
interruptible capacity at Musreau/Cutbank.
The Kaybob COU's current and expected future Company-owned and
firm-service third-party processing capacity in the Deep Basin is
as follows:
Gross Net Paramount Net Paramount
Raw Gas Raw Gas Estimated Sales
Plant Capacity Plant Capacity Plant Capacity(1)
--------------------------------------------------
Current Capacity (MMcf/d) (MMcf/d) (Boe/d)
----------------------------------------------------------------------------
Musreau - Operated 45 45 8,600
Kakwa - Non-operated 40 4 720
Musreau/Cutbank -
Contracted firm service 10 10 1,800
Resthaven - Non-operated 20 10 1,800
Smoky Plant - Non-
operated 100 10 1,800
----------------------------------------------------------------------------
215 79 14,720
----------------------------------------------------------------------------
Future Capacity
Musreau Phase II Deep-Cut
- Operated 200 200 50,000
Smoky/Resthaven Deep-Cut
- Non-operated 200 30 6,750
----------------------------------------------------------------------------
400 230 56,750
----------------------------------------------------------------------------
Total - Year-end 2013 615 309 71,470
----------------------------------------------------------------------------
(1) Estimated
GRANDE PRAIRIE 2011 2010 % Change
----------------------------------------------------------------------------
Sales Volumes
Natural Gas (MMcf/d) 16.0 12.4 29
NGLs (Bbl/d) 505 367 38
Oil (Bbl/d) 393 583 (33)
---------------------------------------------------------------
Total (Boe/d) 3,568 3,012 18
---------------------------------------------------------------
Exploration and Development
Expenditures(1)($ millions)
Exploration, drilling, completions
and tie-ins 106.4 81.6 30
Facilities and gathering 49.6 28.8 72
---------------------------------------------------------------
156.0 110.4 41
---------------------------------------------------------------
Gross Net Gross Net
----------------------------------------
Total Land Holdings (sections) 629 430 703 474
Wells drilled 22 15 16 14
(1) Before the deduction of Alberta Drilling Royalty
credits.
The Grande Prairie COU operates in the Peace River Arch area of
Alberta. Core producing areas include Karr-Gold Creek, Valhalla and
Mirage. Average daily sales volumes in the Grande Prairie COU
during 2011 were 3,568 Boe/d, an increase of 18 percent compared to
2010. The increase was primarily the result of production increases
in Valhalla as a new gathering and compression system was brought
on stream and at Karr-Gold Creek.
VALHALLA
Valhalla is located approximately 70 km northwest of Grande
Prairie. Paramount owns approximately 67 (47 net) sections of land
in this area which has multi-zone potential, including in the
Montney and Lower Doig formations. The Company's activities at
Valhalla accelerated in 2011, with the drilling of 8 (5.7 net)
wells and 7 (5.3 net) wells being brought on production. The wells
drilled in 2011, which primarily target the Montney formation, have
yielded promising results, with significant liquids yields.
A new 10 MMcf/d compression and gathering system was
commissioned in the second quarter of 2011. Construction of an
expansion to this system to bring total capacity to 28 MMcf/d is
near completion and expected to be operational in the second
quarter of 2012. Due to capacity constraints four (2.2 net) wells
have been temporarily shut-in and will be re-started when the
expanded compression capacity is available.
The Grande Prairie COU plans to drill up to 9 (5.0 net) operated
and non-operated wells at Valhalla in 2012.
KARR-GOLD CREEK
Paramount has assembled a land position of approximately 180
(148 net) sections at Karr-Gold Creek, located 50 km southwest of
Grande Prairie. Exploration activities continued on the play during
2011, as the Company worked to optimize recovery systems and
increase production from existing wells. Since commencing
exploration of Karr-Gold Creek in 2008, the Company has brought 10
(9.7 net) lower Montney horizontal wells on production. To date,
the performance of these wells has been below expectations, with
current aggregate production averaging approximately 6 MMcf/d. A
number of operational challenges in 2011 impacted the Company's
effort to improve well performance, including inconsistent
production resulting from multiple unplanned third party processing
interruptions totalling 77 days and delays in the delivery of
surface equipment.
During 2012, Paramount plans to bring three (3.0 net) lower
Montney horizontal wells that were drilled during 2011 onto
production and complete a previously drilled horizontal well in a
Middle Montney reservoir.
The Company completed expansions to gathering and compression
systems at Karr-Gold Creek during the year, with sour gas capacity
being increased to 40 MMcf/d and sweet gas capacity of 8 MMcf/d.
The sweet development at Karr-Gold Creek has targeted various Deep
Basin Cretaceous formations and the Triassic Nikanassin formation,
with ten (6.0 net) wells being drilled in 2011 and 9 (6.1 net)
wells being placed on production. The sweet compression facility is
operating near capacity, with five (3.5 net) wells awaiting tie-in.
Two (1.5 net) sweet wells are planned to be drilled in 2012.
ANTE CREEK
Three (2.0 net) wells were drilled at Ante Creek in 2011
targeting oil from the Montney formation. The first well is
producing at approximately 200 Bbl/d (100 Bbl/d net), the maximum
currently permitted under regulation, a second well was dry and
abandoned and a third well was completed during the first quarter
of 2012. The exploration program at Ante Creek has experienced
delays due to regulatory issues, production equipment failures and
midstream service interruptions. Paramount anticipates developing
plans for further activities at Ante Creek once the performance of
the latest well is known and the regulatory matters have been
successfully resolved.
SOUTHERN 2011 2010 % Change
----------------------------------------------------------------------------
Sales Volumes
Natural Gas (MMcf/d) 10.8 9.3 16
NGLs (Bbl/d) 150 59 154
Oil (Bbl/d) 1,483 1,363 9
---------------------------------------------------------------
Total (Boe/d) 3,424 2,973 15
---------------------------------------------------------------
Exploration and Development
Expenditures(1)($ millions)
Exploration, drilling, completions
and tie-ins 14.9 9.3 60
Facilities and gathering 4.7 2.3 104
---------------------------------------------------------------
19.6 11.6 69
---------------------------------------------------------------
Gross Net Gross Net
----------------------------------------------------------------------------
Total Land Holdings (sections) 708 489 638 452
----------------------------------------
Wells drilled 22 12 27 17
(1) Before the deduction of Alberta Drilling Royalty
credits.
The Southern COU operates in Southern Alberta, Saskatchewan,
North Dakota and Montana. Core areas in Southern Alberta include
the natural gas producing Chain-Craigmyle and Harmattan properties
and the oil producing property at Enchant. In the United States,
the Southern COU's core oil producing area is in North Dakota near
Medora. The Southern COU's average sales volumes increased 15
percent in 2011 compared to 2010, primarily as a result of
production from wells added through the ProspEx acquisition at
Harmattan and Pembina.
CANADA
At Chain, 13 (13.0 net) wells were brought on production in
2011, which added new production to replace natural declines. The
Company does not plan to carry out any natural gas drilling at
Chain in 2012 due to the current low natural gas price
environment.
During the first quarter of 2012, Paramount closed dispositions
of non-core properties at West Pembina, Alberta and Kindersley,
Saskatchewan for total proceeds of approximately $50 million. These
properties did not have significant production volumes.
The Southern COU plans to drill up to 9 (7.5 net) oil wells in
Harmattan, Enchant, Delia and Pembina in 2012.
UNITED STATES
In the United States, Paramount operates through its
wholly-owned subsidiary, Summit. In February 2011, Summit sold
approximately 6,000 net acres of undeveloped land in North Dakota
for cash proceeds of US$40 million.
During the fourth quarter of 2011, Summit's joint venture
partner drilled and completed the final earning wells under the
parties' joint development agreement, earning an undivided 50
percent interest in Summit's undeveloped Bakken/Three Forks lands
in North Dakota.
In the first quarter of 2012 Paramount and Summit initiated a
process to sell Summit and all of its United States properties.
NORTHERN 2011 2010 % Change
----------------------------------------------------------------------------
Sales Volumes
Natural Gas (MMcf/d) 10.3 12.5 (18)
NGLs (Bbl/d) 19 11 73
Oil (Bbl/d) 343 460 (25)
---------------------------------------------------------------
Total (Boe/d) 2,073 2,549 (19)
---------------------------------------------------------------
Exploration and Development
Expenditures(1)($ millions)
Exploration, drilling, completions
and tie-ins 21.8 11.1 96
Facilities and gathering 3.4 1.1 209
---------------------------------------------------------------
25.2 12.2 107
---------------------------------------------------------------
Gross Net Gross Net
----------------------------------------------------------------------------
Total Land Holdings (sections) 959 592 820 530
----------------------------------------------------------------------------
Wells drilled 2 2 5 5
--------------------
(1) Before the deduction of Alberta Drilling Royalty
credits.
The Northern COU's significant properties are located in the
Northwest Territories at Cameron Hills and Liard, in Alberta at
Bistcho and in Northeast British Columbia at Birch and Clarke Lake.
The Northern COU's average sales volumes decreased by 19 percent in
2011 compared to 2010, primarily as a result of production declines
at Cameron Hills and Bistcho.
Paramount owns 60 (60 net) sections of land at Birch that are
prospective for liquids-rich natural gas from the Montney
formation. The Birch acreage was acquired in 2011 as part of the
ProspEx acquisition and through crown land sale purchases. During
the third quarter of 2011, Paramount completed its initial
exploratory well with promising results, indicating significant
liquid yields. The Company has secured limited access to a
gathering system and the well will be brought on production in
2012. Two (2.0 net) additional wells were drilled and completed in
the first quarter of 2012 and are expected to be tied-in later in
the year.
STRATEGIC INVESTMENTS
OIL SANDS
In November, 2011 Paramount reorganized all of its oil sands and
carbonate bitumen interests into a new wholly-owned subsidiary,
Cavalier Energy and assembled its executive leadership team. The
reorganization was undertaken to create a focused, self-funding oil
sands entity in order to accelerate the development of Paramount's
bitumen interests.
Cavalier Energy's properties include approximately 56 sections
of land at Hoole, which are primarily prospective for bitumen in
the Grand Rapids formation and carbonate properties, which are
primarily prospective for bitumen in the Grosmont formation. The
carbonate properties include approximately 15 sections of land at
Saleski and 186 sections of land in other areas (the "Other
Carbonate Lands"), including leases at Orchid, Granor and House.
Cavalier Energy also owns approximately 18 additional sections of
oil sands rights in the Athabasca oil sands area of northeastern
Alberta.
During 2011, Paramount received an updated independent
evaluation of the bitumen resources within the Grand Rapids
formation at the Hoole oil sands property in July and an initial
independent evaluation of the bitumen resources within the Grosmont
formation at Saleski and the Other Carbonate Lands in November. The
evaluations were conducted by the Company's independent reserves
evaluator, McDaniel & Associates Consultants Ltd. ("McDaniel").
The table below summarizes the results of McDaniel's evaluation of
the volumes attributable to Cavalier Energy's bitumen resources and
the estimated net present value of future net revenue at Hoole:
Other
Carbonate
Hoole(1) Saleski(1) Lands(1)
----------------------------------------------------------------------------
Discovered Exploitable Bitumen In
Place (3) (MBbl) 1,631,742 1,184,641 430,586
Economic Contingent Resources(2)(4)
(MBbl) 762,661 N/A N/A
Contingent Resources (Technology
Under Development)(8) (MBbl) N/A 380,493 111,118
NPV of Future Net Revenue (Discounted
at 10%)(5) ($MM) 2,834 N/A N/A
Undiscovered Exploitable Bitumen In
Place(6) (MBbl) N/A 109,332 4,418,573
Prospective Resources(7) (MBbl) N/A 34,006 1,073,439
----------------------------------------------------------------------------
MBbl means thousands of barrels.
All amounts presented in the table above are categorized as
"Best Estimate".(9)
See the "Advisories" section at the end of this document for
note references.
Cavalier Energy's near-term plans are to focus on the
development of its 100 percent owned oil sands leases at Hoole,
including finalizing the scope and design of the initial phase of
the development, submitting an application for commercial
development, and evaluating funding alternatives. Cavalier Energy
will also continue to further delineate its carbonate bitumen
leases at Saleski and the Other Carbonate Lands.
SHALE GAS
Paramount's shale gas land position encompasses 150,000 (127,000
net) acres which has potential for production from the Besa River
shale gas formation in the Horn River and Liard Basins.
The Company has commenced drilling an initial vertical
evaluation well in the Dunedin area of the Liard Basin of Northeast
British Columbia. This well is expected to be drilled to 4,500
meters at a cost of approximately $15 million and will be cored and
logged for evaluation. Paramount continues to monitor industry
activities in the Horn River and Liard Basins where operators are
applying multi-stage fracturing technology to maximize production
rates and reserve recoveries. The Company is taking a conservative
approach to de-risking its shale gas holdings in the current low
natural gas price environment while taking steps to maintain its
mineral rights.
INVESTMENTS IN OTHER ENTITIES
Market
Value(1)
2011 2010
----------------------------------------------------------------------------
As at Shares Shares
December 31 (000's) ($ millions) ($/share) (000's) ($ millions) ($/share)
----------------------------------------------------------------------------
Trilogy 24,144(2) $ 907.1 37.57 24,144 $ 297.0 12.30
MEG Energy
Corp. 3,700 153.8 41.57 3,700 168.3 45.49
MGM Energy
Corp. 43,834 10.6 0.24 43,834 8.8 0.20
Other(3) 5.8 28.8
----------------------------------------------------------------------------
Total $ 1,077.3 $ 502.9
----------------------------------------------------------------------------
(1) Based on the period-end closing price of publicly traded
investments and book value of remaining investments.
(2) In January 2012 Paramount closed the sale of five million of
its Trilogy non-voting shares for gross proceeds of $189.5
million.
(3) Includes investments in other public and private
corporations.
Trilogy is a Canadian energy corporation formed through a
spinout of assets from Paramount in April 2005. Originally an
income trust, Trilogy converted to a corporate structure in
February 2010.
Trilogy is a growing petroleum and natural gas-focused Canadian
energy corporation that actively develops, produces and sells
natural gas, crude oil and natural gas liquids. Trilogy's
geographically concentrated assets are primarily low-risk, high
working interest properties that provide abundant infill drilling
opportunities and good access to infrastructure and processing
facilities, many of which are operated and controlled by
Trilogy.
MEG Energy Corp. ("MEG") is a public energy company based in
Calgary, Alberta. MEG is an oil sands company focused on
sustainable in situ oil sands development and production in the
southern Athabasca region of Alberta, Canada. MEG is actively
developing enhanced oil recovery projects that utilize steam
assisted gravity drainage ("SAGD") extraction methods. MEG is not
engaged in oil sands mining.
MEG owns a 100% working interest in over 900 sections of oil
sands leases. MEG has identified two commercial SAGD projects, the
Christina Lake project and the Surmont project. MEG believes that
the Christina Lake project can support over 200,000 Bbl/d of
sustained production for 30 years and that the Surmont project can
support 100,000 Bbl/d of sustained production for over 20 years. In
addition, MEG holds other leases at other properties that are in
the resource definition stage and that could provide significant
additional development opportunities.
Paramount acquired its ownership interest in MEG in 2007 as
partial consideration for the sale of certain oil sands leases and
related properties to MEG.
MGM Energy Corp. ("MGM Energy") is a Canadian energy company
focused on the acquisition and development of hydrocarbon resources
in the Northwest Territories. The company's business strategy is to
acquire interests in prospective lands and existing discoveries in
the Canadian North, and to employ current technology in exploring
those lands, with the ultimate intention of developing projects
that will ship hydrocarbons through the Mackenzie Valley pipeline,
when built.
MGM Energy is currently active in two areas: the Mackenzie
Delta, where it owns interests in six discoveries and the Colville
Lake/Sahtu region of the Central Mackenzie Valley, where it owns
interests in two discoveries. MGM Energy's land holdings include
both Federal Lands and First Nations Oil and Gas Concessions.
MGM Energy was formed through the 2007 spinout by Paramount of
certain farm-in rights and other assets in the Northwest
Territories.
Paramount's wholly-owned subsidiaries, Fox Drilling and
Paramount Drilling U.S. LLC, currently own three custom built
triple-sized drilling rigs with diesel-electric power top drives
and dual mud pumps. These rigs are designed to drill the deep
horizontal wells that the industry is currently focusing on. Two of
the rigs are being used in the Company's drilling program in the
Kaybob COU and the third rig is contracted to third parties in the
United States until mid-2012. The Company has recently commenced
construction of two triple-sized walking rigs, at an estimated cost
of $20 million per rig, which are expected to be available to drill
on Company properties in Canada in late-2012.
OUTLOOK
Paramount plans to invest $475 million in its Principal
Properties in 2012 (excluding land acquisitions and capitalized
interest), primarily focused in the Kaybob COU's Deep Basin
development. Construction of the Musreau and Smoky deep-cut
facilities will commence during the year, and drilling and
completion activities will continue in preparation for start-up in
the second half of 2013. Planned 2012 activities also include
drilling at Valhalla in the Grande Prairie COU and at Birch in the
Northern COU.
The Company also plans to invest approximately $60 million in
its Strategic Investments in 2012 to complete construction of two
new triple-sized walking drilling rigs within Fox Drilling; to
continue pre-development activities for oil sands projects within
Cavalier Energy; and to drill a shale gas well in the Liard
Basin.
Production during the first quarter of 2012 has been impacted by
capacity constraints in the Kaybob COU as a result of the failure
of a key electrical component at the Musreau 45 MMcf/d facility and
the expiry of certain firm processing contracts in November 2011;
and in the Grande Prairie COU due to delays in the delivery of
surface equipment. First quarter 2012 sales volumes are expected to
average approximately 18,000 Boe/d.
The Musreau facility is currently being commissioned, with gas
sales expected to recommence in mid- March, and the Valhalla gas
gathering system expansion and installation of surface equipment at
Karr-Gold Creek are scheduled to be completed by the end of March.
Sales volumes for the remainder of 2012 are forecast to range
between 26,000 and 28,000 Boe/d. The Company expects its sales
volumes will continue to be in this range until facility expansions
at Musreau and Smoky are completed and brought on-stream in the
second half of 2013.
FOURTH QUARTER REVIEW
Net Loss
Three months ended December 31 2011 2010
----------------------------------------------------------------------------
Principal Properties (250.3) (84.6)
Strategic Investments (3.4) (10.9)
Corporate (16.3) (32.7)
Tax Recovery 60.1 21.9
----------------------------------------------------------------------------
Net Loss (209.9) (106.3)
----------------------------------------------------------------------------
Netback
Three months ended December 31 2011 2010
----------------------------------------------------------------------------
($/Boe) ($/Boe)
Petroleum and natural gas sales 63.3 35.80 46.0 37.11
Royalties (5.5) (3.13) (4.4) (3.51)
Operating expense and production tax (21.2) (11.98) (12.8) (10.37)
Transportation (5.1) (2.88) (4.3) (3.46)
----------------------------------------------------------------------------
Netback 31.5 17.81 24.5 19.77
Financial commodity contract
settlements 0.3 0.17 1.8 1.44
----------------------------------------------------------------------------
Netback including financial
commodity contract
settlements 31.8 17.98 26.3 21.21
----------------------------------------------------------------------------
Funds Flow from Operations
Three months ended December 31 2011 2010
----------------------------------------------------------------------------
Cash from operating activities 7.2 10.4
Change in non-cash working capital 14.9 8.8
Geological and geophysical expenses 1.9 1.5
Asset retirement obligations settled 2.1 0.6
----------------------------------------------------------------------------
Funds flow from operations 26.1 21.3
----------------------------------------------------------------------------
Funds flow from operations ($/Boe) 19.77 17.17
----------------------------------------------------------------------------
Sales Volumes Three months ended December 31
----------------------------------------------------
Natural Gas (MMcf/d) NGLs (Bbl/d)
----------------------------------------------------
2011 2010 Change% 2011 2010 Change%
----------------------------------------------------
Kaybob 50.8 28.8 76 901 614 47
Grande Prairie 19.4 11.4 70 480 333 44
Southern 11.4 9.1 25 216 59 266
Northern 9.9 11.1 (11) 23 24 (4)
----------------------------------------------------------------------------
91.5 60.4 51 1,620 1,030 57
----------------------------------------------------------------------------
Sales Volumes Three months ended December 31
----------------------------------------------------
Oil (Bbl/d) Total (Boe/d)
----------------------------------------------------
2011 2010 Change% 2011 2010 Change%
----------------------------------------------------
Kaybob 62 98 (37) 9,437 5,506 71
Grande Prairie 333 428 (22) 4,048 2,667 52
Southern 1,551 1,397 11 3,670 2,976 23
Northern 410 434 (6) 2,068 2,312 (11)
----------------------------------------------------------------------------
2,356 2,357 0 19,223 13,461 43
----------------------------------------------------------------------------
Paramount's fourth quarter average sales volumes were 19,223
Boe/d, consisting of 91.5 MMcf/d of natural gas and 3,976 Bbl/d of
oil and NGLs. Petroleum and natural gas sales were $63.3 million,
an increase of $17.3 million from the fourth quarter of 2010 due to
increased production volumes from new wells and acquisitions and
higher oil and NGLs prices, partially offset by lower natural gas
prices. Production levels in the Kaybob COU in the fourth quarter
of 2011 were impacted by lower firm processing capacity in Musreau
and equipment failures shortly after the start-up of the new
Musreau plant resulting in some production being temporarily
shut-in.
Fourth quarter 2011 royalties increased to $5.5 million in 2011
compared to $4.4 million in 2010, primarily as a result of
increased revenue. The average royalty rate decreased from 9.3% to
8.7%, as a greater proportion of current production is subject to
the Alberta new well and deep drilling royalty incentive programs.
Operating expenses were $8.4 million higher in the fourth quarter
of 2011 compared to the prior year primarily due to higher
production volumes from new well production and acquisitions.
Operating costs per Boe increased to $11.98 in the fourth quarter
of 2011 compared to $10.37 in the fourth quarter of 2010. The per
unit increase is due primarily to an equalization adjustment for
processing fees at a third party midstream facility and higher 2011
costs related to winter ice roads and well work-overs.
Funds flow from operations in the fourth quarter of 2011
increased by $4.8 million to $26.1 million compared to $21.3
million in 2010, primarily due to the increase in petroleum and
natural gas sales, partially offset by higher operating expenses
and interest.
Fourth quarter exploration and development expenditures of $78.1
million were primarily related to the Deep Basin development in the
Kaybob COU and spending at Karr-Gold Creek and Valhalla in the
Grande Prairie COU.
RESERVES
Paramount's estimated proved reserve volumes increased by 39
percent to 35.7 MMBoe at December 31, 2011 compared to 25.6 MMBoe
in the prior year. The Company's estimated proved and probable
reserve volumes increased by 32 percent to 53.0 MMBoe at December
31, 2011 compared to 40.1 MMBoe in the prior year. The Company
achieved a 193 percent reserves replacement ratio on a proved and
probable basis, excluding acquisitions. New reserves were added
primarily at Musreau, Resthaven and Smoky in the Kaybob COU and
from the ProspEx acquisition, partially offset by negative price
revisions due to a 22 percent decline in forecast natural gas
prices compared to December 2010 and technical revisions due to
well performance in certain properties within the Grande Prairie
and Northern COUs.
Paramount's reserves for the year ended December 31, 2011 were
evaluated by McDaniel 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 for the year ended December 31, 2011
using forecast prices and costs are as follows:
Gross Proved and Probable Reserves(1)
----------------------------------------------------------------------------
Light &
Medium Natural
Natural Crude Gas
Gas Oil Liquids Total
----------------------------------------------------------------------------
Reserves Category (Bcf) (MBbl) (MBbl) (MBoe)(2)
----------------------------------------------------------------------------
Canada
Proved
Developed Producing 120.4 1,930 2,381 24,375
Developed Non-producing 30.6 241 1,128 6,469
Undeveloped 10.5 - 216 1,964
----------------------------------------------------------------------------
Total Proved 161.5 2,171 3,725 32,808
Total Probable 82.0 981 1,941 16,588
----------------------------------------------------------------------------
Total Proved plus Probable
Canada 243.5 3,152 5,665 49,395
----------------------------------------------------------------------------
United States
Proved
Developed Producing 0.5 2,702 75 2,858
Developed Non-producing - - - -
Undeveloped - - - -
----------------------------------------------------------------------------
Total Proved 0.5 2,702 75 2,858
Total Probable 0.1 719 20 762
----------------------------------------------------------------------------
Total Proved plus Probable USA 0.6 3,421 95 3,620
----------------------------------------------------------------------------
Total Company
Total Proved 162.0 4,874 3,799 35,665
Total Probable 82.1 1,699 1,961 17,349
----------------------------------------------------------------------------
Total Proved plus Probable 244.1 6,573 5,760 53,015
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Before Tax Net Present
Value(1)
------------------------------------------------------------------
($ millions)
Discount
Rate
------------------------------------------------------------------
Reserves Category 0% 10% 15%
------------------------------------------------------------------
Canada
Proved
Developed Producing 565.3 420.4 374.8
Developed Non-producing 147.9 101.3 88.6
Undeveloped 33.1 21.8 18.2
------------------------------------------------------------------
Total Proved 746.3 543.5 481.6
Total Probable 428.7 204.2 155.3
------------------------------------------------------------------
Total Proved plus Probable
Canada 1,175.1 747.7 636.9
------------------------------------------------------------------
United States
Proved
Developed Producing 109.1 68.3 58.2
Developed Non-producing (0.4) (0.3) (0.3)
Undeveloped - - -
------------------------------------------------------------------
Total Proved 108.7 68.0 57.9
Total Probable 41.9 16.5 12.3
------------------------------------------------------------------
Total Proved plus Probable USA 150.5 84.5 70.2
------------------------------------------------------------------
Total Company
Total Proved 855.0 611.4 539.5
Total Probable 470.6 220.7 167.6
------------------------------------------------------------------
Total Proved plus Probable 1,325.6 832.2 707.0
------------------------------------------------------------------
------------------------------------------------------------------
(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.
Reserves Reconciliation
Proved Reserves(1) Probable Reserves(1)
----------------------------------------------------------------------------
Oil Oil
Natural and Natural and
Gas NGLs Total Gas NGLs Total
----------------------------------------------------------------------------
(Bcf) (MBbl) (MBoe)(2) (Bcf) (MBbl) (MBoe)(2)
----------------------------------------------------------------------------
January 1, 2011 112.0 6,906 25,576 69.8 2,876 14,511
----------------
Extensions &
discoveries 53.2 2,364 11,237 25.9 1,374 5,693
----------------
Technical
revisions 9.5 (15) 1,576 (13.0) (831) (2,994)
----------------
Economic factors (8.5) (104) (1,522) (9.8) (49) (1,690)
----------------
Acquisitions 25.6 929 5,199 9.2 293 1,833
----------------
Dispositions (0.2) (8) (40) - (1) (4)
----------------
Production (29.8) (1,399) (6,360) - - -
----------------------------------------------------------------------------
December 31,
2011 162.0 8,673 35,666 82.1 3,660 17,349
----------------------------------------------------------------------------
Proved & Probable
Reserves(1)
----------------------------------------------
Oil
Natural and
Gas NGLs Total
----------------------------------------------
(Bcf) (MBbl) (MBoe)(2)
----------------------------------------------
January 1, 2011 181.8 9,782 40,087
----------------
Extensions &
discoveries 79.2 3,737 16,930
----------------
Technical
revisions (3.4) (846) (1,418)
----------------
Economic factors (18.4) (154) (3,212)
----------------
Acquisitions 34.9 1,221 7,032
----------------
Dispositions (0.2) (9) (44)
----------------
Production (29.8) (1,399) (6,360)
----------------------------------------------
December 31,
2011 244.1 12,333 53,015
----------------------------------------------
(1) Columns and rows may not add due to rounding.
(2) Refer to the oil and gas measures and definitions in the
"Advisories" section of this document.
Capital Expenditures
Year ended December 31 2011 2010
----------------------------------------------------------------------------
Geological and geophysical 5.5 7.6
Drilling, completion and tie-ins 303.7 144.8
Facilities and gathering 156.5 46.6
----------------------------------------------------------------------------
Exploration and development expenditures 465.7 199.0
Land and property acquisitions 38.2 82.7
----------------------------------------------------------------------------
Principal Properties 503.9 281.7
Strategic Investments 28.0 16.3
Corporate 0.1 0.1
----------------------------------------------------------------------------
532.0 298.1
----------------------------------------------------------------------------
(1) Exploration and development expenditures are presented after
the deduction of Alberta Drilling Royalty credits
Finding and Development Costs
Total Company
Exploration & Reserve Finding &
Development Additions(2) Development
Capital(1) Costs(2)
----------------------------------------------------------------------------
Proved Proved Proved
Plus Plus Plus
Proved Probable Proved Probable Proved Probable
($ millions)($ millions) (Mboe) (Mboe) ($/Boe) ($/Boe)
----------------------------------------------------------------------------
Exploration,
drilling,
completions
and tie-ins 309.2 309.2
Change in
future capital 3.6 (11.6)
----------------------------------------------------------------------------
312.8 297.6 11,291 12,300 27.70 24.19
Facilities and
gathering 156.5 156.5 - -
----------------------------------------------------------------------------
Total finding
and
development
capital 469.3 454.1 11,291 12,300 41.57 36.92
----------------------------------------------------------------------------
(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.
Total finding and development costs by year ($/Boe)
3 Year
2011 2010 2009 Average
----------------------------------------------------------------------------
Finding and development costs before
facilities expenditures
----------------------------------------------------------------------------
Proved $ 27.70 $ 21.04 $ 18.47 $ 24.03
Proved plus Probable $ 24.19 $ 20.76 $ 19.07 $ 22.45
----------------------------------------------------------------------------
Finding and development costs including
facilities expenditures
----------------------------------------------------------------------------
Proved $ 41.57 $ 27.45 $ 24.05 $ 34.12
Proved plus Probable $ 36.92 $ 26.91 $ 26.76 $ 32.38
----------------------------------------------------------------------------
Finding and development costs in 2011 were impacted by technical
revisions at Karr-Gold Creek and Valhalla in the Grande Prairie COU
and at the Nahanni property in the Northern COU.
Finding and development costs for the Kaybob COU, where
Paramount is currently focused in developing a large-scale liquids
rich play were $13.57 on a proved plus probable basis (excluding
facilities and gathering expenditures):
Kaybob COU
Exploration & Finding &
Development Reserve Development
Capital(1) Additions(2) Costs(2)
----------------------------------------------------------------------------
Proved Proved Proved
Plus Plus Plus
Proved Probable Proved Probable Proved Probable
($ millions) ($ millions) (Mboe) (Mboe) ($/Boe) ($/Boe)
----------------------------------------------------------------------------
Exploration,
drilling,
completions and
tie-ins 171.2 171.2
Change in future
capital 6.4 (15.3)
----------------------------------------------------------------------------
177.6 155.9 9,947 11,481 17.85 13.57
Facilities and
gathering 91.6 91.6 - -
----------------------------------------------------------------------------
Total finding
and development
capital 269.2 247.5 9,947 11,481 27.06 21.56
----------------------------------------------------------------------------
(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.
Total finding and development costs by year ($/Boe)
3 Year
2011 2010 2009 Average
----------------------------------------------------------------------------
Finding and development costs before
facilities expenditures
----------------------------------------------------------------------------
Proved $ 17.85 $ 15.79 $ 15.72 $ 17.11
Proved plus Probable $ 13.57 $ 13.18 $ 15.58 $ 13.71
----------------------------------------------------------------------------
Finding and development costs including
facilities expenditures
----------------------------------------------------------------------------
Proved $ 27.06 $ 19.63 $ 22.60 $ 24.73
Proved plus Probable $ 21.56 $ 16.30 $ 20.44 $ 20.05
----------------------------------------------------------------------------
LAND
2011 2010
----------------------------------------------------------------------------
(000's of acres)
Average Average
Working Working
Gross(1) Net(2) Interest Gross(1) Net(2) Interest
----------------------------------------------------------------------------
Undeveloped land 1,736 1,225 71% 1,682 1,198 71%
Acreage assigned
reserves 574 334 58% 580 311 54%
----------------------------------------------------------------------------
2,310 1,559 67% 2,262 1,509 67%
------------------------------------------------------
Value of undeveloped
land(3) ($ millions) $ 224.3 $ 236.3
----------------------------------------------------------------------------
(1) "Gross" acres means the total acreage in which Paramount has
an interest.
(2) "Net" acres means Paramount's gross working interest acres
multiplied by Paramount's working interest therein.
(3) Based on McDaniel's Evaluation of Unproven Acreage
Interests.
ADDITIONAL INFORMATION
A copy of this press release in PDF format can be obtained at
http://media3.marketwire.com/docs/306pou5.pdf. Paramount's
Management's Discussion and Analysis for the year ended December
31, 2011 can be found at
http://media3.marketwire.com/docs/306pou3.pdf and the Company's
Consolidated Financial Statements for the year ended December 31,
2011 can be obtained at
http://media3.marketwire.com/docs/306pou4.pdf. This information
will also be made available through Paramount's website at
www.paramountres.com and SEDAR at www.sedar.com.
Paramount will file its Annual Information Form ("AIF") for the
year ended December 31, 2011, which includes the disclosure and
reports relating to reserves data and other oil and gas information
required pursuant to National Instrument 51-101, shortly.
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".
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", "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 volumes and the timing thereof;
-- planned exploration and development expenditures and the timing thereof;
-- exploration and development potential and/or plans and strategies and
the anticipated costs and results thereof;
-- budget allocations and capital spending flexibility;
-- adequacy of facilities to process and transport natural gas production;
-- the scope and timing of proposed new facilities and expansions to
existing facilities and the expected capacity and utilization of such
facilities;
-- 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);
-- timing of regulatory applications;
-- the timing of the anticipated development of Paramount's oil sands,
carbonate and shale gas assets;
-- ability to fulfill future pipeline transportation commitments;
-- future taxes payable or owing;
-- undeveloped land lease expiries;
-- timing and cost of future abandonment and reclamation;
-- business strategies and objectives;
-- sources of and plans for financing;
-- acquisition and disposition plans;
-- operating and other costs and royalty rates;
-- regulatory applications and the anticipated timing, results and scope
thereof;
-- anticipated increases in future reserves estimates;
-- expected drilling programs, well tie-ins, facility construction and
expansions, completions and the timing thereof; and
-- the outcome of any legal claims, audits, assessments or other regulatory
matters or 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 crude oil, bitumen, natural gas and NGLs prices and general
economic, business conditions, and market conditions;
-- the ability of Paramount to obtain required capital to finance its
exploration, development and operations;
-- the ability of Paramount to obtain equipment, services, supplies and
personnel in a timely manner and at an acceptable cost to carry out its
activities;
-- the ability of Paramount to market its oil and natural gas successfully
to current and new customers;
-- the ability of Paramount to secure adequate product processing,
transportation and storage;
-- the ability of Paramount and its industry partners to obtain drilling
success consistent with expectations;
-- the timely receipt of required regulatory approvals;
-- expected timelines being met in respect of facility development and
construction projects;
-- access to capital markets and other sources of funding;
-- well economics relative to other projects; 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 crude oil, bitumen, natural gas and NGLs prices, foreign
currency exchange rates and interest rates;
-- the uncertainty of estimates and projections relating to future revenue,
future production, costs and expenses and the timing thereof;
-- the ability to secure adequate product processing, transportation and
storage;
-- the uncertainty of exploration, development and drilling activities;
-- operational risks in exploring for, developing and producing crude oil
and natural gas, and the timing thereof;
-- the ability to obtain equipment, services, supplies and personnel in a
timely manner and at an acceptable cost;
-- potential disruptions or unexpected technical difficulties in designing,
developing or operating new, expanded or existing facilities including,
third party facilities that service Company production;
-- 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 other
sources of financing at an acceptable cost to meet current and future
obligations, including costs of anticipated projects;
-- changes to the status or interpretation of laws, regulations or
policies;
-- changes in environmental laws including emission reduction obligations;
-- the receipt, timing, and scope of governmental or regulatory approvals;
-- changes in economic, business and market conditions;
-- uncertainty regarding aboriginal land claims and co-existing with local
populations;
-- the effects of weather;
-- the ability to fund exploration, development and operational activities
and meet current and future obligations;
-- the timing and cost of future abandonment and reclamation activities;
-- cleanup costs or business interruptions due to environmental damage and
contamination;
-- the ability to enter into or continue leases;
-- existing and potential lawsuits and regulatory actions; and
-- other risks and uncertainties described elsewhere in this document and
in Paramount's other filings with Canadian securities authorities,
including its Annual Information Form.
The foregoing list of risks is not exhaustive. Additional
information concerning these and other factors which could impact
Paramount are included in Paramount's most recent Annual
Information Form. 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", "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 GAAP.
The Company has adjusted its funds flow from operations measure
for all periods subsequent to exclude asset retirement obligation
settlements, cash outflows related to the purchase of Paramount's
Common Shares under the Company's stock incentive plan and the
effect of changes in foreign exchange rates in respect of foreign
currency cash and cash equivalent balances. 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 Management's Discussion and Analysis. Exploration and
development expenditures refer to capital expenditures 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, MGM Energy and others), and investments in all other
entities at book value. Paramount provides this information in its
MD&A 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, natural gas
liquids ("NGLs") and condensate. The term "liquids-rich" is used to
represent natural gas streams with associated liquids volumes.
For fiscal 2011, the value ratio between crude oil and natural
gas was approximately 23:1. 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.
NOTES
(1) Hoole was evaluated by McDaniel as of April 30, 2011.
Saleski and the Other Carbonate Lands were evaluated by McDaniel as
of October 31, 2011.
(2) 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 approvals, 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 Hoole oil sands property, contingencies which
must be overcome to enable the reclassification of bitumen
contingent resources as reserves include the finalization of plans
for the initial development, a regulatory application submission
with no major issues raised, access to capital markets and other
sources of funding 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 April 1, 2011).
(3) Discovered Exploitable Bitumen In Place 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
Hoole oil sands property, the presence of these characteristics is
considered necessary for the commercial application of known
recovery technologies. For the Saleski property and the Other
Carbonate Lands, these volumes have been constrained to areas that
have a minimum thickness of 10 meters of substantially clean,
continuous predominantly bitumen-saturated carbonate with log
porosity meeting a minimum of 10 percent and bitumen saturation
greater than 50 percent, respectively and with both competent top
and lateral reservoir containment. These carbonate bitumen
resources are constrained to one mile in area around known data
points that penetrate the zone and possess definitive geophysical
log data. Discovered Exploitable Bitumen in Place for the Saleski
property and the Other Carbonate Lands may be assigned outside of
the one mile area if reservoir continuity between offsetting
delineation is expected. The technology required to economically
produce bitumen from carbonate formations is currently in the
development stage and has not been proven on a commercial scale.
There is no certainty that it will be commercially viable to
produce any portion of the resources from the Hoole oil sands
property, the Saleski property or the Other Carbonate Lands.
(4) Represents the Company's share of recoverable volumes before
deduction of royalties. In the assessment of Economic Contingent
Resources, McDaniel used a minimum net pay cut-off of 10 meters in
the best estimate case.
(5) NPV means net present value and represents the Company's
share of future net revenue, before the deduction of income tax
from the Economic Contingent Resources in the Grand Rapids
formation within the Hoole oil sands property. 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 in Alberta. 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 April 1, 2011. The
estimated net present values disclosed in this press release do not
represent fair market value.
(6) Undiscovered Exploitable Bitumen In Place is the volume of
petroleum estimated, as of a given date, to be contained in
accumulations yet to be discovered. These resources are mapped
using known data points penetrating the zone and possess definitive
geophysical log data along with seismic data and regional mapping.
There is no certainty that any portion of the resources will be
discovered. If discovered, there is no certainty that it will be
commercially viable to produce any portion of the resources.
(7) Prospective Resources are those quantities of bitumen
estimated, as of a given date, to be potentially recoverable from
undiscovered accumulations by application of future development
projects. Prospective resources have both an associated chance of
discovery and a chance of development. Prospective Resources have
not been, and may never be, discovered.
(8) Contingent Resources/Technology Under Development 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 approvals, 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 Saleski property and the Other
Carbonate Lands, because of the lack of demonstrated commercial
SAGD production within carbonate reservoirs, the recoverable
resources assigned are contingent upon successful application of
SAGD to the subject reservoir or a reasonable analog. The
successful implementation of SAGD technology in carbonate
reservoirs is a significant contingency associated with these
assignments that separate them from typical McMurray clastic SAGD
contingent and prospective resources, where the technology has been
proven effective. In addition to the technical contingency,
additional contingencies applicable to the carbonate resources
include being in the early evaluation stage, the economic viability
of development and the absence of regulatory approvals. The
economic status of these resources are undetermined.
(9) Best Estimate is considered to be the best estimate of the
quantity of resources that will actually be 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.
TEST RESULTS
Test rates disclosed in this document represent the average rate
of gas-flow during post clean-up production tests at the largest
choke setting up 4 1/2" casing. All wells were stimulated using
frac oil and substantially all fluids recovered during the test
periods were load fluids. As a result, recovered fluid volumes for
the duration of the tests have not been disclosed. Pressure
transient analyses and well-test interpretations have not been
carried out for the wells disclosed 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. Liquids yields under
the heading "Average Sales Volumes" are presented for the period
following recovery of all load fluids. Liquids yields are not
presented where recovery of load fluids is incomplete.
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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