CALGARY, ALBERTA - March 3, 2011 /CNW/ - Paramount Resources Ltd. (TSX:POU) ("Paramount" or the "Company") announces its financial and operating results for the year ended December 31, 2010.
Financial and Operating Highlights (1)
Three months ended
December 31 Year ended December 31
($ millions, except as % %
noted) 2010 2009 Change 2010 2009 Change
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Financial
Petroleum and natural
gas sales 46.0 45.0 2 184.4 161.7 14
Funds flow from
operations 19.9 18.8 6 86.9 60.3 44
Per share - diluted
($/share) 0.27 0.27 - 1.19 0.90 32
Net earnings (loss) (75.5) (46.4) (63) (122.5) (97.9) (25)
Per share - diluted
($/share) (1.03) (0.67) (54) (1.68) (1.46) (15)
Exploration and
development
expenditures(2) 78.1 21.5 263 199.0 93.4 113
Investments in other
entities - market
value(3) 502.9 342.9 47
Total assets 1,377.2 1,102.0 25
Net debt 295.2 50.9 480
Common shares
outstanding
(thousands) 75,034 72,058 4
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Operating
Sales volumes
Natural gas (MMcf/d) 60.4 47.0 29 57.7 51.8 11
Oil and NGLs (Bbl/d) 3,387 3,673 (8) 3,417 3,580 (5)
Total (Boe/d) 13,461 11,514 17 13,029 12,207 7
Gas weighting 75% 68% 74% 71%
Average realized price
Natural gas ($/Mcf) 4.04 4.85 (17) 4.50 4.44 1
Oil and NGLs ($/Bbl) 75.48 71.00 6 71.83 59.50 21
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Reserves (4)
Proved plus probable
Natural gas (Bcf) 181.8 155.0 17
Crude oil and NGLs
(MBbl) 9,782 8,667 13
Total (MBoe) 40,087 34,493 16
Finding and
development costs
(proved & probable)
($/Boe) 26.91 26.76 1
Reserves replacement 160% 58%
Estimated future net
revenue before tax @
10%
Proved 397.8 365.5 9
Proved plus probable 556.0 549.6 1
Net undeveloped land
(thousands of acres) 1,198 1,151 4
Net wells drilled
(including oil sands
evaluation) 14 9 167 88 21 314
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(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) Exploration and development expenditures are presented after the
deduction of $11.4 million (2009 - $3.8 million) of Alberta Drilling
Royalty credits.
(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.
2010 HIGHLIGHTS
Principal Properties
-- The Company replaced 160 percent of the reserves produced in 2010.
-- Proved plus probable finding and development costs, excluding
facilities and gathering construction costs, were $20.76/Boe.
-- Funds flow from operations increased 44 percent to $86.9 million.
-- Netback increased 35 percent to $95.1 million despite low gas prices.
-- Operating expenses per Boe decreased by 16 percent.
-- Production increased seven percent to 13,029 Boe/d in 2010 compared to
12,207 Boe/d in 2009.
-- In early 2011, Paramount and its partner drilled and completed an
exploratory horizontal Montney oil well in the West Ante Creek area,
believed to be a significant light oil discovery.
-- In February 2011, Paramount sold approximately 6,000 net acres of
undeveloped land in North Dakota, unrelated to the farm-out lands, for
cash proceeds of US$40 million.
Strategic Investments
-- In May 2010, Paramount received an updated independent evaluation of its
Grand Rapids oil sands resource at Hoole, having a before-tax net
present value of future net revenue of $1.9 billion, discounted at ten
percent (Best Estimate (P50)). Paramount intends to file a regulatory
application for commercial development in 2011.
-- In August 2010 MEG Energy Corp. ("MEG") completed its initial public
offering on the Toronto Stock Exchange. As a result, Paramount now
carries its MEG investment at market value, and the December 31, 2010
carrying value was increased to $168.3 million or $45.49 per share,
compared to $101.8 million or $27.50 per share in the prior year.
-- In February 2011, Trilogy Energy Corp. ("Trilogy") announced a
significant Montney oil discovery. As of February 28, 2011, the market
value of Paramount's investment in 24.1 million Trilogy shares was
$487.5 million, 64 percent higher than at December 31, 2010.
Corporate
-- The Company raised $430 million in a series of financing transactions
between November 2010 and February 2011 in preparation for its 2011
capital program, focused on liquids rich gas developments in the Kaybob
Deep Basin and at Karr-Gold Creek.
-- General and administrative expense per Boe decreased by 16 percent
compared to 2009.
REVIEW OF OPERATIONS
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KAYBOB 2010 2009 Change
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Sales Volumes
Natural Gas (MMcf/d) 23.5 18.9 4.6
Crude Oil & NGLs (Bbl/d) 573 470 103
Total (Boe/d) 4,495 3,615 880
Exploration and Development
Expenditures(1)($ millions)
Exploration, drilling, completions
and tie-ins 61.8 31.1 30.7
Facilities and gathering 14.4 7.8 6.6
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76.2 38.9 37.3
Gross Net Gross Net
--------------------------------
Undeveloped Land (000's of acres) 271.2 163.1 171.7 87.4
Wells drilled 16 7 13 6
Wells placed on production 14 6 15 9
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(1) Before the deduction of Alberta Drilling Royalty credits.
The Kaybob corporate operating unit ("COU") operates in West Central Alberta, where significant liquids rich natural gas producing areas include Musreau, Smoky and Resthaven. The Kaybob COU pursues multiple Deep Basin gas horizons primarily focusing on the Fahler, Dunvegan and Cadotte, which are high pressure, liquids rich, tight gas formations with large reserves potential. To access these deep formations, the Company is drilling mostly horizontal wells to measured depths of 2,500 to 4,600 meters, and completing them with 13 to 18 fracture stages. Four wells per pool per section are permitted and productive zones are being commingled in a single wellbore to enhance recoveries. The Company believes greater well density will be required in order to fully recover the gas resource. Regulatory approval has been obtained to increase well density to eight wells per pool per section for an initial seven sections, and the Company has submitted applications to increase well density for an additional 13 sections. The Kaybob COU has identified in excess of 100 additional drilling locations targeting formations where the Company has had success, and additional formations are actively being explored.
The Kaybob COU achieved promising drilling results with its horizontal wells in the 2009/2010 winter drilling program, and in the fourth quarter of 2010 the Company accelerated its Deep Basin development activities. A total of 13 (8.2 net) wells were drilled between November 2010 and February 2011, of which four (1.7 net) wells have been put on production with initial gross flow rates of 7-10 MMcf/d, consistent with the range of results from horizontal wells the Company has drilled previously in the area. Of the remaining nine (6.5 net) wells, five (3.8 net) wells are expected to be completed and put on production prior to spring break-up and four (2.7 net) wells are expected to be completed and tied-in during the third quarter of 2011.
In June 2010, the Kaybob COU recompleted an existing upper Montney formation vertical wellbore at Musreau with encouraging results. Since then, the Company has been actively acquiring additional Montney mineral rights underlying and offsetting much of its core lands in the Musreau, Smoky and Resthaven areas, and currently holds approximately 105,000 (100,000 net) acres of Montney rights. The Kaybob COU recently spudded its first horizontal well targeting the upper Montney formation at Musreau, and expects to drill an additional three horizontal wells in 2011, assuming drilling results continue to meet expectations.
The Kaybob COU plans to drill a total of up to 28 (16.8 net) wells in 2011. The majority of the wells will be drilled from existing leases or new multiple-well pads, reducing per-well drilling costs by minimizing mobilization and demobilization activities and allowing surface equipment and pipelines to be shared. Where two or more wells are drilled from a single lease, the Company is striving to drill and complete wells back-to-back, increasing equipment and personnel efficiencies and reducing per-well completion costs.
To help ensure the Company will have adequate processing capacity available in the future, Paramount has commenced the construction of a 100 percent owned, $38 million processing plant at Musreau, with a design capacity of 50 MMcf/d of raw gas, anticipated to be operational in the third quarter of 2011. The Company has also nominated for 50 MMcf/d of new capacity as part of an expansion of the non-operated Smoky processing plant, at an expected cost to Paramount of between $47 million and $57 million. The expansion is anticipated to be operational in late 2012. Once completed, the Kaybob COU will own 60 MMcf/d of the total 300 MMcf/d processing capability at the expanded Smoky processing plant.
Expenditures on facilities and gathering systems of $14.4 million in 2010 primarily related to engineering costs and payments on long lead time equipment for the new Musreau and Smoky plants. Other costs were incurred to begin construction of 48 km of pipelines for major gathering system expansions and natural gas and NGLs sales pipelines for the new Musreau plant. Major infrastructure plans for 2011 include completing the construction of the new Musreau plant, the new Smoky plant expansion and construction of the associated gathering systems, sales pipelines and additional field compression.
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GRANDE PRAIRIE 2010 2009 Change
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Sales Volumes
Natural Gas (MMcf/d) 12.4 7.5 4.9
Crude Oil & NGLs (Bbl/d) 951 960 (9)
Total (Boe/d) 3,012 2,204 808
Exploration and Development
Expenditures(1)($ millions)
Exploration, drilling, completions
and tie-ins 81.6 35.2 46.4
Facilities and gathering 28.8 8.8 20.0
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110.4 44.0 66.4
Gross Net Gross Net
--------------------------------
Undeveloped Land (000's of acres) 343.7 248.7 311.1 233.1
Wells Drilled 16 14 6 5
Wells Placed on Production 10 8 8 7
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(1) Before the deduction of Alberta Drilling Royalty credits.
The Grande Prairie COU operates in the Peace River Arch area of Alberta. Core natural gas producing areas include Karr-Gold Creek, Mirage and Valhalla. The COU's primary crude oil producing property is in the deep, light, sweet oil trend at Crooked Creek. The Grande Prairie COU's most significant development projects are at Karr-Gold Creek and at Valhalla.
Karr-Gold Creek is located 50 km southwest of Grande Prairie, where Paramount has assembled a land position of approximately 115,000 (95,000 net) acres, including 48,000 (24,000 net) acres of land added through the acquisition of Redcliffe Exploration Inc. ("Redcliffe") in June 2010. Paramount currently has regulatory approval to drill two wells per section in this area, and plans to seek approval for greater well density should well performance demonstrate that it is required to optimize reserve recoveries. The Company estimates that up to ten wells per year can be drilled at Karr-Gold Creek over the next five years.
Paramount began its development at Karr-Gold Creek in 2008 and 2009, drilling six (6.0 net) horizontal wells prior to having sufficient infrastructure in place to process and transport production from the wells. During the drilling of these initial wells, the Company focused on developing effective drilling and completion techniques, including the length of the horizontal section of the wellbore, fracturing density and the quantity of fracturing fluids. At the conclusion of the production tests, these wells were shut-in pending the installation of a gathering system and adequate dehydration and compression facilities. As the Company improved its completion techniques, later wells tested at rates between 9 MMcf/d and 13 MMcf/d of raw gas and approximately 50 Bbl/MMcf of NGLs. Marketable gas sales volumes are expected to be 25 percent lower due to shrinkage and processing. Based on these encouraging drilling results, the Company accelerated its drilling program, drilling nine (8.2 net) wells in 2010.
In early 2010, Paramount acquired and upgraded a small compression facility at Karr-Gold Creek, which is capable of processing 8 MMcf/d of raw gas. Wells were alternately placed on production at the new facility and then shut-in because of capacity constraints. The Company also commenced the construction of a large compression and dehydration facility capable of processing 40 MMcf/d of raw gas, which is being built in two phases. The initial 20 MMcf/d phase went on-stream in late December 2010, and the second 20 MMcf/d phase is expected to commence operations in mid-2011. In addition, Paramount is expanding sweet infrastructure in the area to accommodate both sweet sales gas and fuel gas required in facilities operations. Paramount expects to have processing capacity for 8 MMcf/d of raw sweet gas by mid-2011, which can be expanded as the area develops.
Weather conditions in the fall of 2010 were extremely wet in the Karr-Gold Creek area, and although the first 20 MMcf/d phase of the processing facility went on-stream in late December, it was not operating at full capacity as commissioning was still underway. The conditions also delayed well completions and tie-ins. Of the 15 (14.2 net) wells drilled at Karr Gold Creek to date, three are currently producing, four are in the process of being restarted after being shut-in, five are scheduled to be tied-in during the first quarter of 2011 and three are expected to be completed and tied-in by the second quarter of 2011.
The Company has been working to restore production from the shut-in wells, as operational challenges have been encountered in achieving previous production levels. Paramount believes these challenges are not atypical in the start-up phase of a new development and they will be overcome, however, the reserves assigned to Karr-Gold Creek at December 31, 2010 were negatively impacted. The Company anticipates that reserves estimates for Karr-Gold Creek will increase as the restarted wells return to normal production levels, additional wells are completed and tied-in and the new facility is optimized to operate at design capacity.
The 2011 capital budget for Karr-Gold Creek includes drilling up to 10 wells and the completion of the second phase of the new facility, which will bring total dehydration and processing capacity for the area to 48 MMcf/d. Paramount expects that all of the wells drilled and completed to March 31, 2011 will be tied-in and brought on production in 2011, as sufficient processing and transmission capacity will be available.
The Valhalla development is located approximately 120 km northwest of Karr-Gold Creek. Paramount has acquired approximately 43,000 (30,000 net) acres of land in this area which has multi-zone potential, including the Montney and Lower Doig formations. The Company has drilled a number of exploratory horizontal wells on the lands to date. Progressively better results have been achieved with each well, the latest three having tested between 9 MMcf/d and 11 MMcf/d of raw gas, with high flowing pressures. Marketable sales gas volumes from these wells are expected to be 15 percent lower due to shrinkage and processing. Paramount's development plan in Valhalla includes drilling up to four horizontal wells per section in each prospective Montney zone, for a total of twelve laterals in every fully developed section. The Company is also evaluating opportunities to target other formations in Valhalla to increase liquids recoveries and enhance returns.
The Company's 2010 development activities at Valhalla included drilling and completing four (3.0 net) wells. Construction of a gas gathering system with capacity for up to 15 MMcf/d of raw gas is progressing with the system expected to be operational in mid-2011. As with Karr-Gold Creek, construction has been delayed by wet weather. The wells drilled and completed at Valhalla in 2010 will be tied-in and placed on production when the new facility enters service.
In early 2011, Paramount and its partner drilled and completed an exploratory horizontal Montney oil well at the Company's non-operated West Ante Creek property, believed to be a significant light oil discovery. Following recovery of the completion load fluid, the well flowed at an average test rate of approximately 1,000 Bbl/d plus associated natural gas over a three-day test period. Follow-up wells are planned for later in the year to further delineate this discovery. Paramount holds a 50 percent working interest in 6,400 gross acres at West Ante Creek prospective for Montney oil development, with the potential for 42 wells on a fully developed basis.
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SOUTHERN 2010 2009 Change
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Sales Volumes
Natural Gas (MMcf/d) 9.3 10.7 (1.4)
Crude Oil & NGLs (Bbl/d) 1,422 1,602 (180)
Total (Boe/d) 2,973 3,382 (409)
Exploration and Development
Expenditures(1)($ millions)
Exploration, drilling, completions
and tie-ins 9.3 6.2 3.1
Facilities and gathering 2.3 0.7 1.6
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11.6 6.9 4.7
Gross Net Gross Net
--------------------------------
Undeveloped Land (000's of acres) 261.6 200.1 263.4 201.7
Wells drilled 27 17 2 -
Wells placed on production 13 10 6 5
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(1) Before the deduction of Alberta Drilling Royalty credits.
The Southern COU operates in Southern Alberta, Saskatchewan, North Dakota and Montana. Core areas comprise the natural gas producing Chain/Craigmyle field near Drumheller, Alberta and the oil producing area near Medora, North Dakota.
The Southern COU drilled 13 (10.1 net) coal bed methane ("CBM") wells and 12 (5.4 net) oil wells during the year. Three of the CBM wells have been put on production and the final ten CBM wells will be tied into existing facilities by the second quarter of 2011. A new Mannville formation oil well was also brought on production at Chain, and this trend will be explored further with an additional well late in 2011.
Paramount entered into a joint development agreement in southern Saskatchewan in 2010 with a Canadian exploration and development company. Under the agreement, the partner has committed to carry out a multiple well Viking formation drilling program in order to earn a post-payout interest of 55 percent in certain properties. Three oil wells have been drilled to date under this agreement. Additional drilling is planned for this play in 2011.
At Enchant, a new Arcs formation oil well was brought on production in the fourth quarter. This discovery will be explored further in the first half of 2011 with three additional wells. Further development opportunities will be evaluated based on the results of the 2011 drilling program.
In the United States, Paramount operates through its wholly-owned subsidiary, Summit Resources Inc. ("Summit"). In April 2010, Summit entered into a joint development agreement with a United States exploration and development company which has significant operations and experience in the Bakken play in North Dakota. Under the agreement, which covers approximately 39,900 net acres of Summit's undeveloped Bakken lands in North Dakota, the US company is carrying out a multiple well Bakken horizontal drilling program using multi-stage fracture technology in order to earn an undivided 50 percent of Summit's interest in these lands (19,950 net acres). The North Dakota joint development partner has drilled and completed three horizontal wells to date. The wells have not performed as expected, with the first two producing at nominal rates.
In February 2011, Paramount sold approximately 6,000 net acres of undeveloped land in North Dakota, unrelated to the farm-out lands, for cash proceeds of US$40 million.
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NORTHERN 2010 2009 Change
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Sales Volumes
Natural Gas (MMcf/d) 12.5 14.7 (2.2)
Crude Oil & NGLs (Bbl/d) 471 548 (77)
Total (Boe/d) 2,549 3,006 (457)
Exploration and Development
Expenditures(1)($ millions)
Exploration, drilling, completions
and tie-ins 11.1 4.5 6.6
Facilities and gathering 1.1 2.9 (1.8)
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12.2 7.4 4.8
Gross Net Gross Net
--------------------------------
Undeveloped Land (000's of acres) 532.7 381.1 611.6 433.7
Wells drilled 5 5 3 3
Wells placed on production - - 4 3
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(1) Before the deduction of Alberta Drilling Royalty credits.
The Northern COU operates in Northern Alberta, Northeast British Columbia and the Cameron Hills and Fort Liard areas of the Northwest Territories. Northern's primary focus is at Cameron Hills, and other significant properties are located at Clarke Lake in Northeast British Columbia.
Capital expenditures for the Northern COU in 2010 related to drilling and completing five (4.9 net) wells in the Cameron Hills area. One of the wells from the 2010 program is expected to be brought on production early in 2011. The remaining wells were suspended.
During the first quarter of 2011, Northern plans to drill and complete three (2.6 net) oil wells in the Cameron Hills area. Production and follow-up development drilling associated with these wells will take place in subsequent years, pending an evaluation of the 2011 drilling results.
STRATEGIC INVESTMENTS
Oil Sands
Paramount's land position includes approximately 180,000 (177,000 net) acres of oil sands leases, prospective for oil sands bitumen and carbonate bitumen.
Hoole Grand Rapids Oil Sands Project
The Hoole area of Alberta is situated within the western portion of the Athabasca Oil Sands region. Paramount owns 100 percent of approximately 39,000 acres of in-situ oil sands leases in this region.
The Hoole Oil Sands Project continued to progress in 2010, with ongoing design work being performed to support a regulatory application for commercial development. Paramount also spent $9.9 million to drill 45 oil sands evaluation wells to further delineate the reservoir and bitumen resources.
In May 2010, Paramount received an updated evaluation of its Grand Rapids resource at Hoole from McDaniel & Associates Consultants Ltd. ("McDaniel"), the Company's independent reserves evaluator, with an evaluation date of April 30, 2010. The following table presents a summary of the results of the McDaniel evaluation:
NPV(6) of
Future
Contingent Fully Net Revenue
Resources(2) First Year Developed Discounted @
Category / Level of (3) Production Production(5) 10%
Certainty(1) (MBbl)(4) (5)(Bbl/d) (Bbl/d) ($MM)(7)(8)
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High estimate 786,394 22,320 85,000 2,934
Best estimate 634,102 21,120 70,000 1,908
Low estimate 458,893 20,700 50,000 967
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(1) A low estimate means high certainty (P90), a best estimate means most
likely (P50) and a high estimate means low certainty (P10).
(2) Represents the Company's share of recoverable volumes before deduction
of royalties.
(3) 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.
(4) Thousands of barrels
(5) These estimates assume that initial production will commence in 2015 and
fully developed production will be reached in 2016 for the low estimate,
2017 for the best estimate, and 2018 for the high estimate.
(6) NPV means net present value and represents the Company's share of future
net revenue, before the deduction of income tax and does not represent
fair value. 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. All NPVs are
calculated assuming natural gas is used as a fuel for steam generation.
Revenues and expenditures were calculated based on the reserve
evaluator's forecast prices and costs as of April 1, 2010.
(7) Millions of Canadian dollars
(8) See Paramount's 2010 Annual Information Form for a full description of
the Hoole Oil Sands Resource.
In 2011, Paramount plans to drill an additional 15 oil sands evaluation wells, complete a 25 km seismic program and complete design and other work to support the Company's application for commercial development in the third quarter. The Company has invested an aggregate of $25.5 million (2009 - $11.1 million) in the project to date. Paramount plans to obtain an updated resource evaluation from McDaniel in 2011 incorporating the results of the 2011 drilling and seismic programs.
Carbonate Bitumen
The Carbonate bitumen trend is differentiated from conventional oil sands in that the bitumen is contained within Devonian-aged dolomites and limestone rocks, as opposed to the Cretaceous sands currently being exploited. The difference in the reservoirs results in production challenges that require different recovery techniques. Though there are currently no economic projects producing this resource, it is receiving a great deal of industry interest, including an operating pilot presently underway. The bitumen hosted within this carbonate trend are believed to exceed 420 billion barrels, resulting in compelling opportunities for entities with holdings on the trend.
In the first quarter of 2011, Paramount will begin assessing this potentially significant resource with a 15 well drilling and delineation program at Saleski, the most prospective of the Company's carbonate leases. The program will target the Grosmont formation, and the core samples obtained will be incorporated into a detailed analysis of the property.
Shale Gas
Paramount's land position encompasses 175,000 (147,000 net) acres in Northeast British Columbia and the Northwest Territories prospective for shale gas from the Horn River Basin and the Liard Basin.
The Company is in the early stages of evaluating the potential of its acreage in these emerging shale plays. Paramount has been actively monitoring industry activities in the Horn River and Liard Basins where operators are applying multi-stage fracturing technology to maximize production rates and reserves recoveries and commencing the development of infrastructure to process and transport production.
Paramount plans to drill its first shale gas well in the Liard Basin in the first quarter of 2012.
Investments in Other Entities
Market Value(1)
-------------------------------
2010 2009
Year ended Shares Shares
December 31 (000's) ($ millions) ($/share) (000's) ($ millions) ($/share)
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Trilogy Energy
Corp. 24,144 $ 297.0 12.30 23,995 206.1 8.59
MEG Energy
Corp. 3,700 168.3 45.49 3,700 101.8 27.50
MGM Energy
Corp. 43,834 8.8 0.20 43,834 12.5 0.29
Other(2) 28.8 22.5
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Total $ 502.9 $ 342.9
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(1) Based on the period-end closing price of publicly traded investments and
book value of remaining investments.
(2) Includes NuLoch Resources Inc., Paxton Corporation, and other public and
private corporations.
Trilogy Energy Corp.
Trilogy Energy Corp. 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's geographically concentrated assets are primarily low-risk, high working interest, lower-decline properties that provide abundant infill drilling opportunities and good access to infrastructure and processing facilities, many of which are operated and controlled by Trilogy. Advances made in horizontal drilling and completion techniques have provided Trilogy with the opportunity to confidently exploit additional tight gas reservoirs on its acreage at attractive finding and development costs. Trilogy plans to continue its strategy of capitalizing on its core assets, focusing on tight gas reservoirs where horizontal technology can be used to add low cost reserves and grow production efficiently.
MEG Energy Corp.
MEG Energy Corp. is a public energy company based in Calgary, Alberta that is focused on oil sands development in the Athabasca region of Alberta, Canada. MEG has identified two commercial SAGD projects, the Christina Lake Project and the Surmont Project. The initial phases of the Christina Lake Project are on-stream with production exceeding 25,000 Bbl/d. Phase 2B, designed to add 35,000 Bbl/d, with first production scheduled for 2013 and Phase 3, designed to add 150,000 Bbl/d, is at the regulatory approval stage.
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 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 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 Drilling
Paramount has invested $45 million to build three custom built triple-sized drilling rigs with diesel electric power, top drives and dual mud pumps. They are designed to drill the deep horizontal wells the industry is drilling today. Two of the rigs are being used in the Company's drilling programs in the Grande Prairie and Kaybob COUs and the third drilled for a third party in North Dakota for the duration of 2010. A total of 16 wells were drilled in 2010 over 658 drilling days and US$3.1 million was earned in external revenue.
OUTLOOK
Based on encouraging drilling and completion results, Paramount accelerated 2010 development plans in the Kaybob and Grande Prairie COUs, increasing total exploration and development spending to $199.0 million. Paramount expects to invest $425 million in its Principal Properties in 2011, excluding land acquisitions. The 2011 Principal Properties capital program will focus on drilling and facility construction at Musreau, Smoky and Resthaven in the Kaybob COU and at Karr-Gold Creek and Valhalla in the Grande Prairie COU. The Company plans to invest an additional $25 million in the Hoole oil sands and Saleski carbonate bitumen areas. Paramount has flexibility within its current capital plan to increase or decrease spending, depending upon future economic conditions, among other factors.
Based on current production levels, market conditions, and the current exploration and development budget, 2011 annual average production is expected to be approximately 20,000 Boe/d, with an anticipated 2011 exit rate of 25,000 Boe/d.
FOURTH QUARTER REVIEW
Fourth Quarter Review
Netback
Three months ended December 31
($ millions, except as noted) 2010 2009
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Petroleum and natural gas sales 46.0 45.0
Royalties (4.4) (7.4)
Operating expense and production tax (12.8) (12.5)
Transportation (4.3) (3.4)
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Netback 24.5 21.7
Financial commodity contract settlements 1.8 1.7
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Netback including financial commodity contract
settlements 26.3 23.4
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Netback including financial commodity contract
settlements ($/Boe) 21.22 22.13
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Funds Flow from Operations
Three months ended December 31
($ millions, except as noted) 2010 2009
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Cash flow from operating activities 11.1 21.3
Change in non-cash working capital 8.8 (2.5)
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Funds flow from operations 19.9 18.8
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Funds flow from operations ($/Boe) 16.10 17.75
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Sales Volumes
Three months ended December 31
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Natural Gas Oil and NGLs
(MMcf/d) (Bbl/d) Total (Boe/d)
---------------------------------------------------------------
2010 2009 Change 2010 2009 Change 2010 2009 Change
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Kaybob 28.8 19.0 9.8 713 473 240 5,506 3,636 1,870
Grande
Prairie 11.4 5.7 5.7 761 1,046 (285) 2,667 1,993 674
Southern 9.1 9.7 (0.6) 1,455 1,563 (108) 2,976 3,198 (222)
Northern 11.1 12.6 (1.5) 458 591 (133) 2,312 2,687 (375)
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Total 60.4 47.0 13.4 3,387 3,673 (286) 13,461 11,514 1,947
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Paramount's fourth quarter sales volumes of 13,461 Boe/d consisted of 60.4 MMcf/d of natural gas and 3,387 Bbl/d of oil and NGLs, generating revenue of $46.0 million, an increase of $1.0 million from the prior year comparable quarter due to higher natural gas volumes and higher oil and NGLs prices, partially offset by lower natural gas prices and lower oil and NGLs production volumes. Production levels in the Grande Prairie COU in the fourth quarter of 2010 were impacted by the commissioning of the new Karr-Gold Creek plant, which temporarily shut-in some wells while they were being tied-in to the new facility, and by drilling new wells on pad sites, requiring producing wells on the pads to be shut-in during drilling operations.
Fourth quarter royalties decreased to $4.4 million in 2010 compared to $7.4 million in 2009, primarily as a result of production from new wells which benefit from the first year maximum five percent royalty rate and deep natural gas royalty holidays. Operating expenses were $0.3 million higher in the fourth quarter of 2010 compared to the prior year primarily due to higher production volumes in the Grande Prairie and Kaybob COUs.
Funds flow from operations in the fourth quarter of 2010 increased by $1.1 million to $19.9 million compared to $18.8 million in 2009, primarily due to lower royalties, partially offset by higher interest expenses.
Fourth quarter exploration and development expenditures of $78.1 million were primarily related to the Grande Prairie COU's Karr-Gold Creek deep gas program and the Deep Basin development in the Kaybob COU.
RESERVES
Paramount's estimated proved plus probable reserve volumes increased by 16 percent to 40,087 MBoe at December 31, 2010 compared to 34,493 MBoe in the prior year, and the Company replaced 160 percent of the reserves produced in the year. New reserves were added primarily at Smoky, Resthaven and Musreau in the Kaybob COU and at Karr-Gold Creek in the Grande Prairie COU and from the Redcliffe acquisition, partially offset by natural declines, negative price revisions due to a 28 percent decline in forecast prices compared to December 2009 and technical revisions due to well performance in certain properties.
Paramount's reserves for the year ended December 31, 2010 were evaluated by McDaniel and prepared in accordance with the National Instrument 51-101 definitions, standards and procedures. The Company's working interest reserves and before tax net present value of future net revenues for the year ended December 31, 2010 using forecast prices and costs are as follows:
Before Tax Net
Gross Proved and Probable Reserves(1) Present Value(1)
-----------------------------------------------------------
Light & Natural
Natural Medium Gas ($ millions)
Gas Crude Oil Liquids Total Discount Rate
-----------------------------------------------------------
Reserves Category (Bcf) (MBbl) (MBbl) (MBoe)(2) 0% 10% 15%
----------------------------------------------------------------------------
Canada
Proved
Developed
Producing 84.7 2,186 1,441 17,750 407.5 296.6 261.7
Developed Non-
producing 18.6 77 288 3,472 48.4 28.1 24.0
Undeveloped 8.2 18 119 1,497 26.9 17.0 13.8
----------------------------------------------------------------------------
Total Proved 111.5 2,281 1,848 22,719 482.8 341.6 299.5
Total Probable 69.6 1,050 1,025 13,677 287.1 142.9 108.6
----------------------------------------------------------------------------
Total Proved plus
Probable Canada 181.2 3,331 2,873 36,396 769.9 484.5 408.1
----------------------------------------------------------------------------
United States
Proved
Developed
Producing 0.5 2,703 73 2,856 96.9 56.6 47.2
Developed Non-
producing - - - 1 (0.4) (0.3) (0.3)
Undeveloped - - - - - - -
----------------------------------------------------------------------------
Total Proved 0.5 2,703 73 2,857 96.5 56.2 46.9
Total Probable 0.2 777 26 834 41.9 15.2 11.1
----------------------------------------------------------------------------
Total Proved plus
Probable USA 0.7 3,480 99 3,691 138.4 71.4 58.0
----------------------------------------------------------------------------
Total Company
Total Proved 112.0 4,984 1,922 25,576 579.3 397.8 346.5
Total Probable 69.8 1,826 1,050 14,511 329.0 158.1 119.7
----------------------------------------------------------------------------
Total Proved
plus Probable 181.8 6,810 2,972 40,087 908.3 556.0 466.1
----------------------------------------------------------------------------
(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(2) Probable Reserves(2)
--------------------------------------------------------
Natural Oil and Natural Oil and
Gas NGLs Total Gas NGLs Total
--------------------------------------------------------
Bcf MBbl MBoe(3) Bcf MBbl MBoe(3)
----------------------------------------------------------------------------
January 1, 2010 90.5 6,245 21,328 64.5 2,422 13,165
Extensions and
discoveries 28.3 1,002 5,717 14.1 546 2,893
Technical revisions 8.9 289 1,780 (6.0) (573) (1,573)
Economic factors (1.1) (31) (221) (6.2) 14 (1,011)
Acquisitions 6.5 647 1,728 3.4 469 1,037
Production (1) (21.1) (1,247) (4,756) - - -
----------------------------------------------------------------------------
December 31, 2010 112.0 6,906 25,576 69.8 2,876 14,511
----------------------------------------------------------------------------
Proved & Probable
Reserves(2)
---------------------------
Natural Oil and
Gas NGLs Total
---------------------------
Bcf MBbl MBoe(3)
-----------------------------------------------
January 1, 2010 155.0 8,667 34,493
Extensions and
discoveries 42.4 1,548 8,610
Technical revisions 2.9 (284) 207
Economic factors (7.3) (17) (1,232)
Acquisitions 9.9 1,115 2,765
Production (1) (21.1) (1,247) (4,756)
-----------------------------------------------
December 31, 2010 181.8 9,782 40,087
-----------------------------------------------
(1) Excludes royalty interest production.
(2) Columns and rows may not add due to rounding.
(3) Refer to the oil and gas measures and definitions in the "Advisories"
section of this document.
Capital Expenditures
----------
Year ended December 31
($ millions) 2010 2009
----------------------------------------------------------------------------
Geological and geophysical 7.6 5.2
Drilling, completions and tie-ins 144.8 68.0
Facilities and gathering 46.6 20.2
----------------------------------------------------------------------------
Exploration and development expenditures(1) 199.0 93.4
Land and property acquisitions 82.7 6.4
----------------------------------------------------------------------------
Principal Properties 281.7 99.8
Strategic Investments 16.3 17.6
Corporate 0.2 0.1
----------------------------------------------------------------------------
Net capital expenditures 298.2 117.5
----------------------------------------------------------------------------
(1) Exploration and development expenditures are presented after the
deduction of $11.4 million (2009 - $3.8 million) of Alberta Drilling
Royalty credits.
Finding and Development Costs
Exploration & Finding &
Development Reserve Development
Capital(1) Additions(2) Costs(2)
------------------------------------------------------------
Proved Proved Proved
Plus Plus Plus
Proved Probable Proved Probable Proved Probable
($ ($
millions) millions) (Mboe) (Mboe) ($/Boe) ($/Boe)
------------------------------------------------------------
Exploration,
drilling,
completions and
tie-ins 152.4 152.4
Change in future
capital 0.7 5.1
------------------------------------
153.1 157.5 7,276 7,585 21.04 20.76
Facilities and
gathering 46.6 46.6 - - - -
----------------------------------------------------------------------------
Total finding
and development
capital 199.7 204.1 7,276 7,585 27.45 26.91
----------------------------------------------------------------------------
(1) The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during the 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.
Finding and development costs in 2010 were impacted by lower than expected reserve estimates for the Karr-Gold Creek development due to limited production data as the new processing facility entered service in late December 2010 and shut-in wells were not fully restored to expected production levels. Lower forecasted natural gas prices at December 31, 2010 also impacted finding and development costs, as downward economic revisions were recorded in respect of Liard in the Northern COU and various other properties.
-----------
Total finding and development 3 Year
costs by year ($/Boe) 2010 2009 2008 Average
----------------------------------------------------------------------------
Proved $ 27.45 $ 24.05 $ 129.24 $ 37.81
Proved plus Probable $ 26.91 $ 26.76 $ 334.80 $ 42.61
----------------------------------------------------------------------------
-----------------------------
Land 2010 2009
----------------------------------------------------------------------------
Average Average
Working Working
(000's of acres) Gross(1) Net(2) Interest Gross(1) Net(2) Interest
---------------------------------------------------------
Undeveloped land 1,682.0 1,198.0 71% 1,620.3 1,151.1 71%
Acreage assigned
reserves 579.7 310.7 54% 588.4 304.5 52%
---------------------------------------------------------
2,261.7 1,508.7 67% 2,208.7 1,455.6 66%
----------------------------------------------------------------------------
Value of
undeveloped
land(3) ($
millions) $ 237.9 $ 145.1
----------------------------------------------------------------------------
(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 appraisal summary of acreage evaluations.
ADDITIONAL INFORMATION
A copy of this press release in PDF format can be obtained at download/2011+March+3_release.pdf. Paramount's Management's Discussion and Analysis and Consolidated Financial Statements for the year ended December 31, 2010 can be obtained at download/2011+March+3_md%26a.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, 2010, which includes the disclosure and reports relating to reserves data and other oil and gas information required pursuant to National Instrument 51-101 of the Canadian Securities Administrators 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 plans and strategies;
-- budget allocations and capital spending flexibility;
-- adequacy of facilities to process natural gas production;
-- 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;
-- ability to fulfill future pipeline transportation commitments;
-- 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;
-- 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 oil and gas prices and general economic and business 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 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 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; 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 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. The material risks and uncertainties include, but are not limited to:
-- fluctuations in crude oil, natural gas and NGLs prices, foreign currency
exchange rates and interest rates;
-- the uncertainty of estimates and projections relating to future
production, costs and expenses;
-- the ability to secure adequate product processing, transportation and
storage;
-- the uncertainty of exploration, development and drilling;
-- 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;
-- potential disruption or unexpected technical difficulties in designing,
developing or operating new or existing facilities;
-- risks and uncertainties involving the geology of oil and gas deposits;
-- the uncertainty of reserves and resource estimates;
-- the ability to generate sufficient cash flow from operations and other
sources of financing at an acceptable cost to meet current and future
obligations;
-- changes to the status or interpretation of laws, regulations or
policies;
-- changes in environmental laws including emission reduction obligations;
-- the timing of governmental or regulatory approvals;
-- changes in general business and economic 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 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 most recent 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 share - diluted", "Netback", "Netback including settlements of financial commodity contracts", "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. They are used to assist management in measuring the Company's ability to finance capital programs and meet financial obligations. Funds flow from operations refers to cash flows from operating activities before net changes in operating working capital. Netback equals petroleum and natural gas sales less royalties, operating costs, production taxes and transportation costs. Refer to the calculation of Net Debt in the liquidity and capital resources section of Management's Discussion and Analysis. Exploration and development expenditures refers to capital expenditures incurred by the Company's COUs excluding land and property acquisitions. 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 at December 31, 2010), and all other investments in other entities at book value. Paramount provides this information because the market values of equity accounted investments, which are significant assets of the Company, are often materially different than their carrying values.
Non-GAAP measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP, or other measures of financial performance calculated in accordance with GAAP. The Non-GAAP measures are unlikely to be comparable to similar measures presented by other issuers.
Oil and Gas Measures and Definitions
This document contains disclosure expressed as "Boe", "MBoe" 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 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.
This document contains disclosure of the results of an updated evaluation of the Company's contingent bitumen resources from the Grand Rapids formation at Hoole, Alberta. 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. A low estimate means high certainty (P90), a best estimate means most likely (P50) and a high estimate means low certainty (P10).
