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
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(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
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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
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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
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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.
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