CALGARY, ALBERTA - March 7, 2013 /CNW/ - Paramount Resources Ltd. (TSX:POU) -
Reserves and Principal Properties
- Total proved and probable reserves increased 239 percent to 179.9 MMBoe, with conventional reserves increasing 64 percent to 86.8 MMBoe (replacement ratio of six times) and probable oil sands bitumen reserves increasing 93.1 MMBoe.
- Conventional proved reserves increased 43 percent year-over-year to 50.9 MMBoe, after production of 7.3 MMBoe and dispositions of 3.4 MMBoe (replacement ratio of three times).
- Conventional proved and probable finding and development costs, excluding facilities and gathering system construction costs, decreased 50 percent to $12.18 per Boe and for the Kaybob COU decreased 24 percent to $10.31 per Boe.
- Natural gas and NGLs sales volumes increased approximately 20 percent despite downstream processing and transportation constraints which impacted the Company's operations in the second half of the year.
- The Company's new 45 MMcf/d refrigeration facility at Musreau (the "Musreau Refrig Facility") has been operating near capacity since being re-commissioned in March.
- Operating expenses decreased 14 percent to $9.58 per Boe in 2012 compared to $11.20 per Boe in 2011 due to the sale of higher cost US properties and processing cost savings from the Company's Musreau Refrig Facility.
- Construction of the Company's wholly-owned 200 MMcf/d deep cut facility at Musreau (the "Musreau Deep Cut Facility") commenced in the third quarter of 2012 following the receipt of regulatory approval. The project continues to be on-schedule, with commissioning expected to commence by the end of the third quarter of 2013.
- Advance drilling for the deep cut facility expansions at Musreau and Smoky continued. The Company currently has an inventory of 43 (35 net) Kaybob Deep Basin wells with estimated first month deliverability exceeding 225 MMcf/d (185 MMcf/d net) of raw gas.
- In February 2013, the Company closed the sale of substantially all of its remaining US properties for cash proceeds of US$22.5 million, subject to closing adjustments. Since 2011, the Company has realized aggregate cash proceeds of approximately US$130 million on the sale of its US properties, significantly in excess of their carrying value.
- Paramount drilled and completed its first horizontal shale gas exploration well at Patry in Northeast British Columbia in March 2013. In order to further evaluate well performance, the Company plans to bring the well on production by the end of 2013.
- Paramount's wholly-owned subsidiary, Cavalier Energy Inc. ("Cavalier Energy"), recorded 93.1 million barrels of probable bitumen reserves with an NPV10 of $379 million following its regulatory applications for the initial 10,000 Bbl/d phase of the Hoole Grand Rapids development.
- Fox Drilling completed the construction of two new walking drilling rigs, which will drill on multi-well pad sites in the Kaybob COU.
- To fund the Company's growth initiatives, Paramount raised over $700 million in aggregate cash proceeds in 2012, including over $400 million from equity offerings, the sale of investments and non-core oil and gas properties and $300 million from the notes offering.
- At February 28, 2013, Paramount had cash balances of $109.2 million and its $300 million credit facility was undrawn.
|Financial and Operating Highlights(1)(2)|
|($ millions, except as noted)|
|Three months ended December 31||Year ended December 31|
|2012||2011||% Change||2012||2011||% Change|
|Petroleum and natural gas sales||54.6||63.3||(14)||197.1||241.7||(18)|
|Funds flow from operations||17.7||26.1||(32)||58.1||96.2||(40)|
|Per share - diluted ($/share)||0.20||0.33||(39)||0.67||1.23||(46)|
|Net income (loss)||(151.8)||(209.9)||28||(61.9)||(232.0?||73|
|Per share - basic and diluted ($/share)||(1.69)||(2.54)||33||(0.71)||(2.96)||76|
|Exploration and development expenditures||166.8||144.1||16||523.1||465.7||12|
|Investments in other entities - market value(3)||704.8||1,077.3||(35)|
|Common shares outstanding (thousands)||89,932||85,500||5|
|Natural gas (MMcf/d)||104.1||91.5||14||98.5||81.6||21|
|Average realized price|
|Natural gas ($/Mcf)||3.45||3.62||(5)||2.72||4.04||(33)|
|Net wells drilled (excluding oil sands evaluation)||8||13||(38)||34||48||(29)|
|Net oil sands evaluation wells drilled||-||-||-||1||27||(96)|
|Proved and probable|
|Natural gas (Bcf)||323.7||244.1||33|
|Light and medium crude oil (MBbl)||2,128||6,573||(68)|
|Total Conventional (MBoe)||86,842||53,015||64|
|Oil sands bitumen (MBbl)||93,091||-||100|
|Total Company (MBoe)||179,933||53,015||239|
|Conventional F&D cost before facilities expenditures (proved and probable) ($/Boe)||12.18||24.19||(50)|
|Conventional reserves replacement (proved and probable)||599%||193%|
|NPV10 future net revenue before tax|
|Proved and probable||1,259.3||832.2||51|
|(1) Readers are referred to the advisories concerning non-GAAP measures and oil and gas definitions in the Advisories section of this document.
(2) Amounts include the results of discontinued operations. Refer to page seven of Paramount's Management's Discussion and Analysis for the year ended December 31, 2012.
(3) Based on the period-end closing prices of publicly traded enterprises and the book value of the remaining investments.
(4) Net debt is a non-GAAP measure, it is calculated and defined in the Liquidity and Capital Resources section of Paramount's Management's Discussion and Analysis for the year ended December 31, 2012.
(5) Working interest reserves before royalty deductions. Net present values were determined using forecast prices and costs and do not represent fair market value.
|REVIEW OF OPERATIONS(1)|
|Natural gas (MMcf/d)||98.5||81.6||21|
|Netbacks ($ millions)(2)||($/Boe)(3)||($/Boe)(3)||% Change
|Natural gas revenue||98.2||2.72||120.2||4.04||(33)|
|Royalty and sulphur revenue||3.6||-||4.0||-|
|Petroleum and natural gas sales||197.1||27.04||241.7||38.00||(29)|
|Operating expense and production tax||(69.9)||(9.58)||(71.3)||(11.20)||(14)|
|Financial commodity contract settlements||(0.1)||(0.02)||0.2||0.03||(167)|
|Netback including commodity & insurance settlements||95.0||13.04||128.0||20.13||(35)|
|(1) Amounts include the results of discontinued operations. Refer to page seven of Paramount's Management's Discussion and Analysis for the year ended December 31, 2012.
(2) Readers are referred to the advisories concerning non-GAAP measures and oil and gas definitions in the Advisories section of this document.
(3) Natural gas revenue shown per Mcf.
Paramount's natural gas and NGLs sales volumes increased 21 percent in 2012 as the Company completed the first phase of its Kaybob Deep Basin expansion with the re-commissioning of the Musreau Refrig Facility at the end of the first quarter. New production was also added at Valhalla in the Grande Prairie COU, where the gathering and compression system was expanded.
The ability of Paramount to maximize production through its natural gas firm-capacity and Company-owned facilities in 2012, including the Musreau Refrig Facility and Valhalla gathering and compression system, was impacted by various third party downstream disruptions and capacity constraints (the "Third Party Disruptions"), which reduced sales volumes at times by up to 6,000 Boe/d. The Third Party Disruptions mainly related to reduced throughput at third party NGLs de-ethanization and fractionation facilities at Fort Saskatchewan, which resulted in the apportionment of available processing capacity. The Third Party Disruptions were also caused by NGLs and natural gas pipeline takeaway constraints and scheduled and unscheduled downtime at third party natural gas processing facilities. The Company estimates that average sales volumes in the second half of 2012 were reduced by approximately 3,000 Boe/d. Sales volumes in December 2012 and January 2013 were constrained to approximately 22,000 Boe/d.
Oil sales volumes decreased 29 percent to 1,620 Bbl/d in 2012 compared to 2,291 Bbl/d in 2011, primarily because of the second quarter US property disposition and natural declines in other areas.
Petroleum and natural gas sales revenue in 2012 decreased $44.6 million compared to 2011 as a result of lower realized prices and the US property disposition. Operating costs decreased $1.4 million compared to 2011 primarily due to the disposition of the US properties, partially offset by higher operating expenses from continuing operations.
|Natural gas (MMcf/d)||59.5||44.5||34|
|Exploration and Development Expenditures ($ millions)|
|Exploration, drilling, completions and tie-ins||200.7||171.2||17|
|Facilities and gathering||161.8||91.6||77|
|Total Land Holdings (sections)||788||446||792||441|
The Kaybob corporate operating unit ("COU") operates in West Central Alberta, where its core properties are in the Deep Basin at Musreau, Smoky and Resthaven. Paramount has assembled extensive multi-zone mineral rights to 788 (446 net) sections, with the primary formations of interest being the Montney and various Cretaceous horizons. Depending on the formation, well densities of eight or more wells per section per formation are anticipated to be required to recover the resources in place, representing a multi-decade inventory of drilling locations.
Paramount continues to execute the large-scale development of its Deep Basin lands that will materially increase production volumes and cash flow. The Company's drilling activities are currently focused on the Montney, Dunvegan, and Falher formations, which are high pressure, liquids rich, tight gas formations with large reserves potential. These plays continue to generate robust rates of return in the current low natural gas price environment because of the high liquids content in these formations.
The Company achieved significant reserves growth in 2012 as a result of its development activities in the Kaybob Deep Basin. Further increases in reserves are expected as facilities expansions are completed and development drilling continues.
To support the accelerated development of Paramount's Deep Basin lands, the Company constructed its wholly-owned 45 MMcf/d Musreau Refrig Facility, is building a 200 MMcf/d deep cut processing facility at Musreau and is participating in the deep cut expansion of the non-operated Smoky facility, which together will more than triple Paramount's current gas processing capacity to over 300 MMcf/d. The Company has also entered into long-term agreements to transport, de-ethanize and fractionate NGLs streams that will be produced from these new facilities, and has entered into a long-term ethane sales agreement with a petrochemical company.
Average daily sales volumes in the Kaybob COU during 2012 were 10,910 Boe/d, an increase of 30 percent compared to 2011. Sales volumes in the first quarter of 2012 were impacted by the fourth quarter 2011 electrical component failure at the Musreau Refrig Facility. The re-commissioning of the facility was completed in March 2012, and average sales volumes increased to 12,236 Boe/d in the second quarter. Sales volumes in the second half of the year were reduced as a result of the previously described Third Party Disruptions. By the middle of September, production across the Kaybob COU was curtailed to less than 6,500 Boe/d, including a temporary reduction in throughput at the Musreau Refrig Facility to 10 MMcf/d. Sales volumes reached 13,500 Boe/d in November following the partial resolution of Third Party Disruptions.
Between December 2012 and February 2013, Kaybob COU sales volumes have ranged between 11,500 Boe/d and 13,500 Boe/d as operations continue to be impacted by Third Party Disruptions. Based on the current NGLs constraints and projections of capacity for the remainder of 2013, production is expected to be within the current range until the expansion of a third-party NGLs pipeline is completed, Paramount secures additional fractionation capacity and the Musreau Deep Cut Facility is brought on-stream. The Kaybob COU has approximately 28,000 Boe/d of first year production behind pipe which will be brought on-stream when the Musreau and Smoky deep cut expansions are on-stream.
After the start-up of the Musreau Refrig Facility, operating costs for the Kaybob COU were reduced to approximately $5.00 per Boe, before deducting processing income. The Musreau Refrig Facility provides significant savings to the Company through the elimination of third-party processing fees. The Kaybob COU's per unit operating costs are expected to further decrease with the commissioning of the Musreau Deep Cut Facility, as fixed costs will be applied over significantly larger production volumes. In the third quarter, Paramount received a $6.2 million settlement in respect of a business interruption insurance claim related to the electrical equipment failure at the Musreau Refrig Facility in December 2011.
Paramount has completed the first phase of its Deep Basin expansion with the re-commissioning of the Musreau Refrig Facility. The next major milestone will be the start-up of the Musreau and Smoky deep cut facilities, which will represent a major step change for Paramount, as Kaybob COU sales volumes are expected to increase more than four times 2012 levels by the end of 2014.
Musreau Deep Cut Facility
Paramount's wholly-owned Musreau Deep Cut Facility is designed to capture incremental volumes of NGLs from the Company's Deep Basin liquids rich gas production that would otherwise be sold as slightly higher heat content natural gas. The incremental liquids are captured by cooling the natural gas stream sufficiently to change the phase of the components from a gas to a liquid and then separating these streams using gravity. Liquids yields from the facility will vary depending on the liquids content of the gas being processed and the temperature to which Paramount cools the gas stream, among other factors.
Construction of the Musreau Deep Cut Facility commenced in the third quarter of 2012 following the receipt of regulatory approval. Site preparation is complete and piling and concrete work continues. Major equipment, including compressors, generators and storage vessels, are being delivered to the facility site over the course of the winter so that construction can continue through break-up. Paramount has awarded the structural steel contract and anticipates awarding the mechanical contracts shortly, with electrical and instrumentation contracts to follow. The project continues to be on-schedule and in-line with budget, with approximately $100 million incurred to December 31, 2012 and an additional $80 million budgeted for 2013 to complete construction.
Paramount is currently developing its commissioning plan. Commissioning of the facility is expected to begin towards the end of the third quarter of 2013 and span approximately two months, a process which involves testing and calibrating the individual components and control systems, purging vessels and piping, and pressure testing the system.
Paramount has secured a long-term firm service arrangement for the transportation of NGLs produced from its Kaybob area facilities commencing in December 2013. The Company has also entered into a long-term firm service arrangement with a midstream company for the de-ethanization and fractionation of NGLs volumes commencing in April 2014. The Company is working on procuring interruptible NGLs fractionation capacity for the period between the planned December 2013 start-up of the Musreau Deep Cut Facility and the commencement of the long-term firm service fractionation arrangement.
Kaybob COU sales volumes are expected to increase to approximately 30,000 Boe/d over the first few months after startup, as the operations team optimizes the facility's equipment and processes. Volumes initially processed through the Musreau Deep Cut Facility will be primarily from leaner Cretaceous wells in which Paramount's working interest generally ranges from 50 percent to 100 percent. Ethane is expected to remain in the gas stream until the midstream company completes an expansion of its de-ethanization facilities, which is scheduled to be operational in the second half of 2014. By late-2014, Kaybob COU sales volumes are expected to increase by over four times 2012 levels once a greater proportion of liquids-rich, 100 percent working interest Montney wells are flowing through the Musreau Deep Cut Facility, the expansion of the third party de-ethanization facility is completed and the Smoky Deep Cut Facility is on-stream.
The Company continues to advance its project to construct an amine processing train at the Musreau Deep Cut Facility, which will provide the capability to treat sour gas production at the facility instead of at well sites. This enhancement is expected to cost approximately $50 million, and will decrease equipping costs by over $1 million per well and reduce ongoing well operating costs. Design work for the amine facility has been completed and long lead-time components have been ordered. The amine processing train is scheduled to be on-stream in the first half of 2014, and will not impact the start-up of the Musreau Deep Cut Facility.
Smoky Deep Cut Facility
Paramount continues to participate in the deep cut expansion of the non-operated processing facility at Smoky (the "Smoky Deep Cut Facility"). The Company will have a 20 percent interest in the expanded facility, an increase from its 10 percent interest in the existing 100 MMcf/d dew point facility. The Smoky Deep Cut Facility will initially have 200 MMcf/d of capacity upon start-up, increasing to 300 MMcf/d through the later installation of an incremental 100 MMcf/d of compression. As a plant owner, Paramount has the option at any time to request installation of the additional compression, which would bring the Company's total owned capacity in the facility to 60 MMcf/d. Construction work commenced at the site in the third quarter of 2012 with the installation of pilings and foundations. NGLs bullets and compressors have been delivered and a significant portion of the major equipment is expected to be delivered prior to break-up, with the remaining components to be delivered later this year. The expansion is scheduled to be commissioned in the third quarter of 2014. Paramount's share of the Smoky Deep Cut Facility expansion costs is expected to total $65 million, of which approximately $30 million has been incurred to December 31, 2012.
Kaybob Processing Capacity
Upon completion of the Musreau Deep Cut Facility and the Smoky Deep Cut Facility, Paramount expects to have over 300 MMcf/d of net owned and third party firm-service processing capacity in the Deep Basin, estimated to be capable of yielding over 73,000 Boe/d of sales volumes when fully utilized. This capacity will be used to process Paramount's production as well as third-party unavoidably commingled volumes for a fee. Paramount currently has access to an incremental 10 to 12 MMcf/d of interruptible processing capacity and will continue to utilize such capacity in addition to its owned and firm-service capacity where available. The Company's current and future owned and firm-service processing capacity in the Deep Basin is as follows:
|Current Processing Capacity|
|Musreau Refrig Facility||45||45||8,600|
|Firm Contracted Capacity||10||10||1,800|
|Subtotal - Current Capacity||215||79||15,620|
|Future Processing Capacity|
|Musreau Deep-Cut Facility||200||200||50,000|
|Smoky Deep-Cut Facility||200||30||7,500|
|Subtotal - Future Capacity||400||230||57,500|
To see the map associated with this release, click the following link: download/2013+March+7_map.pdf
Kaybob Drilling Activity
During 2012, Paramount was active drilling and completing wells in the Deep Basin, continuing to build production deliverability in preparation for the start-up of the new Musreau and Smoky deep cut facilities. The Company drilled 27 (21.2 net) wells in 2012, including 7 (6.0 net) horizontal Montney formation wells and completed 17 (13.1 net) wells, including 9 (8.0 net) Montney formation wells. The initial flow rates and NGLs content continue to be consistent with expectations, further confirming well performance profiles.
The Company's producing Falher formation wells have on average performed in accordance with the anticipated type curve below: download/2013+March+7_graph.pdf
NGLs transportation and fractionation capacity constraints have temporarily limited Paramount's ability to bring on Montney formation wells due to their higher liquids content. The Company has continued to drill and complete Montney wells in advance of the Musreau and Smoky deep cut facilities expansions and test results from the latest wells continue to be consistent with earlier wells, further confirming expected recoveries from this formation. The following table summarizes test results for Montney formation wells rig released in 2011 and 2012:
|(1) Test rates represent the average rate of gas-flow during post clean-up production tests up the largest choke setting. All wells were stimulated using frac oil and substantially all fluids recovered during the test periods were load fluids. As a result, fluid volumes recovered during the tests have not been disclosed. Pressure transient analyses and well-test interpretations have not been carried out for these wells and as such, data should be considered to be preliminary until such analysis or interpretation has been done. Test results are not necessarily indicative of long-term performance or of ultimate recovery.
(2) Average flow-back casing pressure for the duration of the test.
The Company has varying rights to multiple formations within its 788 (446 net) section Kaybob COU land position, including 391 (240 net) sections of Cretaceous rights and 229 (195 net) sections of Montney rights. Having rights to multiple formations allows the Company to evaluate shallower formations while drilling deeper wellbores targeting deeper rights. Prospective shallower zones can be completed in addition to the deeper reservoirs to increase total recoveries from individual locations. The Company has received approval to drill up to five Montney formation wells per section on six sections and is preparing to file applications on additional lands. It is anticipated that well densities of eight or more wells per section per formation will be required to fully recover the resources.
Paramount's experience over the past few years in the Deep Basin has allowed the Company to achieve cost reductions in drilling and completion operations through improved drilling and fracturing techniques and improved logistics with multi-well pad sites. The Company has been successful in reducing drilling time for Falher formation wells to approximately 30 days from 40 days in 2010. Drilling time for the deeper Montney formation wells has been reduced to approximately 45 days from over 80 days in the early part of 2011. With the cost of each drilling day averaging approximately $75,000, the reduction in drilling days alone has resulted in significant cost savings. The Company has also reduced completion costs by improving pumping techniques, optimizing frac sizing and spacing, recycling the frac oil, and negotiating lower rates for services, equipment and completion fluids.
During the fourth quarter of 2012, the Company finished equipping the wells on its first five-well pad at Musreau. Three (2.5 net) Montney formation wells and two (1.5 net) Falher formation wells were drilled, completed, equipped and tied-in for aggregate gross costs of approximately $45 million, including the cost of site sweetening packages for the Montney wells. Average gross raw gas test rates for the five wells totalled approximately 55 MMcf/d over the final 24 hours of their test periods, with flowing pressures averaging 2,500 PSI.
Multi-well pad sites will increasingly be used to develop Paramount's Deep Basin lands, where drilling and completion operations are performed on multiple wells thereby minimizing mobilization and de-mobilization costs and reducing equipping and tie-in costs by using common facilities. The Company plans to utilize its two new built-for-purpose walking rigs to drill on its multi-well pad sites beginning in the second quarter of 2013. These rigs have the ability to move across the lease with drill pipe standing in the derrick so that pad wells are drilled in sequence with minimal downtime between wells. Completion operations on pad sites allow the Company to produce back energized oil from a fracture stimulation, recycle the fluid and re-inject it into the next well, saving the cost of transporting and purchasing new frac oil.
Paramount currently has five drilling rigs working in the Deep Basin, which continue to add to the Company's inventory of wells that will feed the Musreau and Smoky deep cut facilities. The Company plans to drill up to an additional 40 wells during 2013, approximately 50 percent of which will target the Montney formation. The 2013 drilling program includes eight pad sites that are expected to account for 32 of the planned 40 wells.
The following table summarizes the status of Kaybob Deep Basin wells that have been drilled and are awaiting production as of February 28, 2013, the estimated remaining capital required to complete these wells, and their anticipated production and sales volumes:
Net Raw Gas
|Gross||Net||First Month||First Year||First Month||First Year|
|Shut-in due to capacity constraints||9||8||-||23||11||6,400||3,100|
|Tied-in, capable of producing||10||7||-||54||25||14,900||7,000|
|Completed, awaiting tie-in||14||12||20||59||29||19,000||9,200|
|Drilled, awaiting completion||10||8||51||52||28||17,000||9,100|
|(1) Based on the Company's 4.9 Bcf type curve for Falher wells and 3.7 Bcf type curve for Montney wells.
(2) Based on processing through a deep cut facility.
Once the Musreau Deep Cut Facility is fully operational and the ramp-up of production volumes is complete, the Company estimates that approximately 20 new wells will be required each year to keep the facility operating at capacity.
The Kaybob COU's focus in 2013 is to complete the construction of the Musreau Deep Cut Facility and maximize production volumes through available capacity. The Company is ready for significant growth. With production volumes ramping-up as the Musreau and Smoky deep cut facilities are brought on-stream, Paramount will begin to realize returns on its Deep Basin drilling and infrastructure investments.
|Natural gas (MMcf/d)||20.9||16.0||31|
|Exploration and Development Expenditures ($ millions)|
|Exploration, drilling, completions and tie-ins||69.5||106.4||(35)|
|Facilities and gathering||32.9||49.6||(34)|
|Total Land Holdings (sections)||577||379||629||430|
The Grande Prairie COU operates in the Peace River Arch area of Alberta. Core producing areas include Valhalla and Karr-Gold Creek. Average daily sales volumes in the Grande Prairie COU during 2012 were 4,536 Boe/d, an increase of 27 percent compared to 2011. Fourth quarter 2012 sales volumes averaged 5,243 Boe/d, after being curtailed as a result of the Third Party Disruptions between August and October.
Increases in 2012 sales volumes were primarily from Valhalla. The Company's gathering and compression system was expanded to 24 MMcf/d in the second quarter and additional wells were brought on-stream. The Company drilled six (4.3 net) wells in Valhalla in 2012 targeting the Montney and Doig formations. These wells were completed and tied-in during the year, along with wells drilled in 2011.
Karr-Gold Creek is located approximately 20 kilometers north of the Kaybob COU's Musreau development. Activities in 2012 focused on exploration of the middle and upper Montney reservoirs and continued efforts to improve the performance of the Company's previously completed lower Montney formation wells. Paramount's middle and upper Montney land position at Karr-Gold Creek of approximately 180 (148 net) sections exhibits similar geological reservoir and fluid characteristics to competitors' offsetting lands, and the Company's Montney holdings in the Musreau / Resthaven area.
In the third quarter of 2012, the Company completed a previously drilled middle Montney well at Karr-Gold Creek, which was brought-on production during the first quarter of 2013. A new well targeting the middle Montney formation was drilled in the fourth quarter of 2012, was completed in the first quarter of 2013 and will be tied-in during the third quarter. Test results from these wells have exceeded forecasts, confirming Paramount's interpretation that the Kaybob middle/upper Montney play extends northwest onto the Karr lands, adding significant resources to Paramount's future development base in the Deep Basin.
Results of the performance enhancement program for the Company's lower Montney wells at Karr-Gold Creek have not been consistent with expectations. While recoveries from some wells improved modestly, others wells are unchanged and Third Party Disruptions impacted the project for a significant portion of the year. This program will not be continued in 2013.
Exploration and development activities in the Grande Prairie COU will include the drilling, completion and tie-in of middle Montney wells at Karr-Gold Creek. The Company anticipates the existing inventory of producing and behind pipe wells at Valhalla will be sufficient to maintain production volumes at the current level throughout 2013, subject to the availability of NGLs transportation and fractionation capacity.
|Natural gas (MMcf/d)||9.8||10.8||(9)|
|Exploration and Development Expenditures ($ millions)|
|Exploration, drilling, completions and tie-ins||23.0||14.9||51|
|Facilities and gathering||2.7||4.7||(43)|
|Total Land Holdings (sections)||627||432||708||489|
|(1) Amounts include the results of discontinued operations. Refer to page seven of Paramount's Management's Discussion and Analysis for the year ended December 31, 2012.|
In May 2012, Summit closed the sale of all of its operated properties in North Dakota and all of its Montana properties for cash proceeds of approximately US$70 million. This disposition included approximately 900 Boe/d of production and 42 net sections of land. During the first quarter of 2013, Summit closed the sale of its non-operated joint venture operations and lands in North Dakota for aggregate gross proceeds of US$22.5 million, subject to closing adjustments. This disposition included approximately 200 Boe/d of production and undeveloped land. With the closing of these transactions, substantially all of Paramount's US assets and operations have been sold.
Combined with the 2011 sale of undeveloped land in the United States for US$40 million, approximately US$130 million in cash proceeds has been realized from the sale of US properties, significantly in excess of the book value of these assets.
Southern COU sales volumes decreased 18 percent to 2,814 Boe/d in 2012 compared to 3,424 Boe/d in 2011, mainly as a result of the disposition of the operated US properties in May. Wells drilled in 2012 include three (2.2 net) wells in Harmattan in southern Alberta, one of which was completed and is scheduled to be brought-on production in the second quarter of 2013.
Plans for the Southern COU's properties in 2013 consist primarily of routine maintenance and production optimization programs.
|Natural gas (MMcf/d)||8.3||10.3||(19)|
|Exploration and Development Expenditures ($ millions)|
|Exploration, drilling, completions and tie-ins||21.2||21.8||(6)|
|Facilities and gathering||6.9||3.4||103|
|Total Land Holdings (sections)||962||690||959||592|
Sales volumes in the Northern COU were 1,657 Boe/d in 2012, 20 percent lower than 2011, as a result of natural declines at Cameron Hills and Bistcho and second quarter processing disruptions at the Bistcho plant.
Paramount's initial well at Birch in Northeast British Columbia was brought on-stream in December 2012 following the completion of modifications to surface facilities. Two additional wells drilled in 2012 have been completed and tied-in. The Company has 3 MMcf/d of raw gas processing capacity at Birch, and is currently working to optimize production from these wells. In the third quarter, Paramount drilled a vertical evaluation well at Birch to evaluate the lower Montney formation and preserve surrounding mineral rights.
In March 2013, Paramount sold its properties in the Bistcho area of Alberta and the Cameron Hills area of the Northwest Territories for approximately $9 million, subject to closing adjustments. Average sales volumes for these properties were approximately 1,000 Boe/d in 2012.
Paramount's shale gas holdings encompass approximately 260 (220 net) sections in the Liard Basin and the Horn River Basin in Northeast British Columbia and the Northwest Territories, including approximately 180 net sections with potential from the Besa River shale gas formation.
To see a map of the Liard Basin, click the following link: download/2013+March+7_map.pdf
Paramount drilled and completed its first horizontal shale gas exploration well at Patry in Northeast British Columbia. The well was drilled to a vertical depth of approximately 3,400 meters with a horizontal bore of approximately 1,200 meters, and was completed with a 10-stage fracture stimulation in the Besa River formation in early March 2013 that included the injection of approximately 120,000 barrels of completion fluids.
The well commenced flowing on clean-up in the first week of March 2013 and continues to recover the completion fluids. Over the first 69 hours of metered gas flow, natural gas rates ranged between 5 MMcf/d and 14 MMcf/d on clean-up and completion fluid recoveries averaged approximately 4,000 Bbl/d at flowing tubing pressures of 11,000 to 35,000 kPa up 114.3 mm tubing. During the last 24 hours of that period, natural gas rates averaged 7 MMcf/d at an average flowing tubing pressure of approximately 11,500 kPa and completion fluid recovery was approximately 2,800 Bbl/d. As a pressure transient analysis or well test interpretation has not been carried out at this time, the flow-back data provided should be considered preliminary. In addition, this data is not necessarily indicative of long-term performance or ultimate recovery.
The Company is working to confirm that all 10 stages of the fracture stimulation are open and contributing. In order to further evaluate well performance, the Company plans to tie the Patry well into existing pipeline infrastructure located within two miles of the well site and plans to bring the well on production by the end of 2013.
The Company re-commenced drilling operations on its initial shale gas evaluation well at Dunedin in February 2013 after drilling operations were suspended there in the spring of 2012 due to warm weather. Paramount plans to drill this well to the intended vertical depth of approximately 4,500 meters at which point it will evaluate further plans to complete the vertical wellbore and/or drill a horizontal leg. This activity is expected to extend the mineral rights surrounding the well location for an additional decade and provide information useful for future development.
CAVALIER ENERGY INC.
Cavalier Energy is designed to be a focused, self-funding entity, which was created in 2011 as a wholly-owned subsidiary of Paramount to execute the development of the Company's oil sands and carbonate bitumen assets. Cavalier Energy holds over 300 sections, representing approximately 200,000 net acres of Crown leases in the Western Athabasca region of Alberta.
Hoole Grand Rapids
The initial focus of Cavalier Energy is to develop the Grand Rapids formation in its 100 percent owned in-situ oil sands leases in the Hoole area of Alberta (the "Hoole Project"). The Hoole Project is 10 kilometers northeast of Wabasca-Desmarais, Alberta. Since 2004, approximately $60 million has been invested through land acquisitions, stratigraphic drilling, engineering studies, and environmental field programs to bring this asset to the development stage.
In 2012, Cavalier Energy focused its efforts on recruiting its leadership team and developing the project strategy, including the project size, use of technologies and execution approach. These actions provided the necessary information for the regulatory application and the company's development strategy.
In November 2012, Cavalier Energy submitted regulatory applications for the initial 10,000 Bbl/d phase of the Hoole Grand Rapids development ("Hoole Grand Rapids Phase 1") to the Energy Resources Conservation Board ("ERCB") and Alberta Environment and Sustainable Resource Development ("AESRD"). Cavalier Energy anticipates regulatory approvals to be received in the first half of 2014. Construction of Hoole Grand Rapids Phase 1 is dependent upon the receipt of regulatory approvals, sanctioning by the Board of Directors, and securing funding.
During 2013, Cavalier Energy plans to complete the front end engineering and design work for Hoole Grand Rapids Phase 1 along with geotechnical work and the drilling of additional source water and disposal wells. Estimated costs of these activities totalling $15 million are expected to be funded with drawings on Cavalier Energy's $40 million credit facility.
In January 2013, Cavalier Energy received an updated independent evaluation of the Hoole Project, effective December 31, 2012, from the Company's independent reserves evaluators. The evaluation ascribed 93 million barrels of probable reserves with a net present value (discounted at 10 percent) of $379 million to Hoole Grand Rapids Phase 1, which covers approximately two sections of the Hoole Project. Over and above the aforementioned reserves, the evaluation ascribed 719 million barrels of economic contingent resources (best estimate) with a net present value (discounted at 10 percent) of $1.949 billion to the remaining approximate 54 sections of the Hoole Project (the "Remaining Hoole Leases") within the Grand Rapids formation. The updated estimates and reclassification of Hoole Project volumes from economic contingent resources to probable reserves follows Cavalier Energy's November 2012 regulatory applications.
The reserves assigned to Hoole Grand Rapids Phase 1 are summarized in the Reserves section of this document. Results of the evaluation of the Remaining Hoole Leases are as follows:
|Classification/Level of Certainty(1)||DEBIP(1)||Economic
|NPV of Future Net
(discounted at 10%)
|(1) See Oil Sands Resource Notes in the Advisories section of this document.
(2) MMBbl means millions of barrels.
Future Exploration Portfolio
Cavalier Energy holds 128,000 acres of mineral rights located on the Grosmont Carbonate Trend. Industry peers have begun to explore this resource and have constructed pilot projects to refine extraction technologies. Cavalier Energy is monitoring industry developments and will develop future plans for its holdings based on the results of these pilot projects.
Cavalier Energy acquired 36 sections of land at Eagles Nest in early 2012. The property is prospective for oil sands bitumen in the McMurray and Wabiskaw formations and seismic data is currently being evaluated to validate mapping and plan additional seismic and drilling activities.
FOX DRILLING INC.
Fox Drilling Inc. ("Fox Drilling") now owns five triple-sized rigs in Canada, including two new built-for-purpose walking rigs and a rig previously owned by Paramount Drilling U.S. that was moved in the fourth quarter of 2012 from the United States. Fox Drilling's two original rigs drilled on the Company's lands in Alberta throughout 2012. The two new walking drilling rigs will be deployed on multi-well pad sites in the Kaybob COU's Deep Basin development. Fox Drilling's rigs are designed to drill the deep horizontal wells that industry is currently focusing on in the Deep Basin of Alberta.
INVESTMENTS IN OTHER ENTITIES
|As at December 31||2012||2011|
|Trilogy Energy Corp. ("Trilogy")||19,144||$||557.3||29.11||24,144||$||907.1||37.57|
|MEG Energy Corp.||3,700||112.6||30.44||3,700||153.8||41.57|
|MGM Energy Corp.||54,147||13.5||0.25||43,834||10.6||0.24|
|(1) Based on the period-end closing price of publicly traded investments and book value of remaining investments.|
|(2) Includes investments in other public and private corporations.|
In January 2012, Paramount closed the sale of 5.0 million of its non-voting Trilogy shares for net cash proceeds of $181.7 million, recognizing a gain of $157.2 million.
In the fourth quarter of 2012, the revolving period and maturity date of the Company's $300 million credit facility was extended to November 30, 2013 and November 30, 2014, respectively, with all other material terms of the credit facility remaining unchanged.
To fund the Company's growth initiatives, Paramount raised over $700 million in aggregate cash proceeds in 2012, including over $400 million from equity offerings, the sale of investments and non-core oil and gas properties and $300 million from the notes offering.
Paramount plans to invest approximately $500 million in its Principal Properties in 2013, excluding land acquisitions and capitalized interest, primarily focused on the Kaybob COU's Deep Basin development. Construction of the Musreau Deep Cut Facility is scheduled to be completed in the fourth quarter and construction of the third-party Smoky Deep Cut Facility will continue into 2014. In preparation for the start-up of the deep cut facilities, the Company plans to drill and complete up to 40 new wells in Kaybob in 2013. Budgeted activities also include the drilling, completion and tie-in of middle Montney wells at Karr-Gold Creek.
The Company plans to invest approximately $50 million in its Strategic Investments in 2013, directed towards drilling and completions in the Liard Basin and continued pre-development work for oil sands projects within Cavalier Energy.
Average sales volumes in January 2013 were constrained to approximately 22,000 Boe/d and increased to approximately 23,500 Boe/d in the last week of February 2013. Paramount's ability to maximize production through its Company-owned and firm-service contracted capacity will likely continue to be impacted by downstream NGLs processing and transportation constraints until the fourth quarter of 2013.
Sales volumes for the first three quarters of 2013 are expected to range between 21,000 Boe/d and 25,000 Boe/d, after giving effect to the first quarter property dispositions, depending upon the availability of downstream NGLs transportation and processing capacity. Sales volumes are expected to increase in the fourth quarter once the expansion of a third-party NGLs pipeline is completed, additional fractionation capacity is secured and the Musreau Deep Cut Facility is on-stream.
After the Musreau Deep Cut Facility starts up in late-2013, the Company will have owned and firm-service contracted natural gas processing capacity of 279 MMcf/d, which will increase to over 300 MMcf/d in 2014 with the addition of the Smoky Deep Cut Facility. Sales volumes are expected to increase to over 50,000 Boe/d by late-2014 as facility processes are optimized and the new long-term NGLs processing contracts come into effect.
FOURTH QUARTER REVIEW
|Three months ended December 31|
|Natural Gas (MMcf/d)||NGLs (Bbl/d)||Oil (Bbl/d)||Total (Boe/d)|
|2012||2011||% Change||2012||2011||% Change||2012||2011||% Change||2012||2011||% Change|
Netback - Continuing Operations
|Three months ended December 31||2012||2011|
|Royalty and sulphur revenue||0.7||-||1.0||-|
|Petroleum and natural gas sales||54.6||28.70||56.2||33.38|
|Financial commodity contract settlements||0.7||0.38||0.3||0.18|
|Netback including financial commodity contract settlements||27.4||14.38||27.7||16.47|
|(1) Natural gas revenue shown per Mcf.|
Paramount's fourth quarter average sales volumes were 20,674 Boe/d in 2012, an increase of 13 percent over the fourth quarter of 2011. Natural gas sales volumes increased in the Kaybob COU as a result of new production from wells producing through the Company's new Musreau Refrig Facility. Sales volumes also increased at Valhalla in the Grande Prairie COU where a new gathering and compression system was commissioned in the first quarter of 2012. Sales volumes in the Southern and Northern COUs decreased due to natural declines.
Fourth quarter 2012 petroleum and natural gas sales were $54.6 million, a decrease of $1.6 million from the fourth quarter of 2011, as a 14 percent decrease in average realized prices more than offset the 13 percent increase in sales volumes.
Natural gas and NGLs sales volumes in the fourth quarter of 2012 were reduced due to Third Party Disruptions, which required Paramount to restrict NGLs recovery rates and curtail production in the Kaybob and Grande Prairie COUs. The Company estimates that average sales volumes in the fourth quarter were reduced by approximately 3,000 Boe/d as a result, including reduced liquids yields as the Company preferentially flowed lower liquids content wells. Sales volumes in December 2012 and January 2013 were constrained to approximately 22,000 Boe/d.
Operating expenses decreased $1.4 million in the fourth quarter of 2012 compared to the prior year, as higher operating costs related to the new Musreau Refrig Facility and new wells brought-on production were more than offset by the impact of higher processing income and lower third party processing fees. Operating costs per Boe decreased to $9.41 in the fourth quarter of 2012 compared to $11.45 in the fourth quarter of 2011. The per-unit decrease is primarily due to a higher proportion of sales from the Kaybob COU, which has per unit operating costs of approximately $5.00 per Boe before accounting for the impact of third party processing income. Operating expenses in the fourth quarter include the cost of seasonal maintenance in the Northern COU at remote locations.
|Three months ended December 31||2012||2011|
|Gain (loss) on financial commodity contracts||0.6||(7.7)|
|General and administrative||(4.0)||(4.0)|
|Depletion and depreciation||(183.1)||(271.7)|
|Exploration and evaluation||(13.8)||(7.2)|
|Gain (loss) on sale of property, plant and equipment||(1.8)||3.0|
|Loss from equity-accounted investments||(0.4)||(1.0)|
|Loss from continuing operations||(151.8)||(210.8)|
|Discontinued Operations, net of tax||-||0.9|
Paramount recorded a loss from continuing operations of $151.8 million for the three months ended December 31, 2012 compared to a loss from continuing operations of $210.8 million in the same period of 2011.
Significant factors contributing to the change are shown below:
|Three months ended
|Loss from continuing operations - 2011||(210.8)|
|Lower depletion, depreciation and impairment mainly due to lower write-downs of petroleum and natural gas properties and goodwill||88.6|
|Gain on financial commodity contracts compared to a loss in 2011||8.3|
|Lower income tax recovery in 2012||(23.0)|
|Higher exploration and evaluation expense||(6.6)|
|Loss on sale of property, plant and equipment compared to a gain in 2011||(4.8)|
|Higher interest in 2012 due to higher debt levels||(3.0)|
|Loss from continuing operations - 2012||(151.8)|
Funds Flow from Operations(1)
|Three months ended December 31||2012||2011(2)|
|Cash from operating activities||(13.2)||7.2|
|Change in non-cash working capital||27.2||14.9|
|Geological and geophysical expenses||1.0||1.9|
|Asset retirement obligations settled||2.7||2.1|
|Funds flow from operations||17.7||26.1|
|Funds flow from operations ($/Boe)||9.29||14.73|
|(1) Refer to the advisories concerning non-GAAP measures in the Advisories section of this document.|
|(2) Includes the results of discontinued operations.|
Funds flow from operations decreased by $8.4 million in the fourth quarter of 2012 compared to the same period in 2011, primarily as a result the sale of the US properties, which generated $4.0 million of funds flow from operations in the fourth quarter of 2011, and higher interest expense.
Paramount achieved strong conventional reserves additions in 2012, driven by the Company's Deep Basin development in the Kaybob COU. The Company's conventional proved and probable reserves at December 31, 2012 increased 64 percent to 86.8 MMBoe compared to 53.0 MMBoe at December 31, 2011, after production of 7.3 MMBoe and dispositions of 4.4 MMBoe, with a proved and probable reserves replacement ratio of 599 percent. Proved reserves increased 43 percent to 50.9 MMBoe at December 31, 2012 from 35.7 MMBoe at December 31, 2011, with a proved reserves replacement ratio of 336 percent.
Hoole Oil Sands Bitumen
Incremental to the conventional reserves additions, the Company recorded 93.1 MMBbl of probable bitumen reserves additions related to Cavalier Energy's 10,000 barrel per day oil sands development planned for the Hoole Grand Rapids. These reserves volumes were recognized following Cavalier Energy's November 2012 regulatory applications for project approval to the ERCB and AESRD.
Paramount's reserves for the year ended December 31, 2012 were evaluated by McDaniel & Associates Consultants Ltd., the Company's independent reserves evaluator, and prepared in accordance with National Instrument 51-101 definitions, standards and procedures. The Company's working interest reserves and before tax net present value of future net revenues as of December 31, 2012 using forecast prices and costs are as follows:
|Gross Proved and Probable Reserves(1)||Before Tax Net Present Value(1)(3)|
|Total Proved and Probable
|Oil Sands Bitumen|
|Total Proved and Probable
|Total Proved and Probable||323.7||2,128||30,761||93,091||179,933||3,487||1,259||866|
|(1) Columns may not add due to rounding.
(2) Refer to the oil and gas measures and definitions in the Advisories section of this document.
|(3) The estimated net present values disclosed in this document do not represent fair market value. Revenues and expenditures were calculated based on McDaniel's forecast prices and costs as of January 1, 2013.|
December 31, 2012 reserves include 10.1 MMBoe of proved developed non-producing ("PDNP") reserves, mainly related to wells in the Kaybob COU that have been drilled and are expected to come on-stream once the deep cut facilities expansions are completed. Proved undeveloped ("PUD") reserves totalling 11.3 MMBoe are mainly related to certain of the locations that the Kaybob COU expects to drill over the next year. PDNP and PUD reserves are expected to be reclassified to proved developed producing reserves once the Musreau Deep Cut Facility is substantially complete and the undeveloped locations are drilled.
Future development costs totalling $110 million in respect of estimated costs to complete the Musreau Deep Cut Facility and Smoky Deep Cut Facility were deducted in determining the future net revenue of Paramount's total proved reserves; $56 million of which was deducted from PDNP reserves values and $54 million of which was deducted from PUD reserves values.
The following table summarizes future development costs deducted in the calculation of future net revenue from conventional reserves:
|Future Development Costs - Undiscounted|
|Plants||Wells & Other||Total|
|Proved Developed Producing||29,501||382||-||-||-|
|Proved Developed Non-Producing||10,090||72||56||21||77|
|Total Proved and Probable||86,842||880||110||297||407|
|(1) The estimated net present values disclosed in this document do not represent fair market value. Revenues and expenditures were calculated based on McDaniel's forecast prices and costs as of January 1, 2013.|
|Proved Reserves(1)||Proved and Probable Reserves(1)|
|January 1, 2012||162.0||8,673||-||35,666||244.1||12,333||-||53,015|
|Extensions & discoveries||74.4||9,058||-||21,464||148.8||21,167||93,091||139,058|
|December 31, 2012||201.9||17,202||-||50,857||323.7||32,889||93,091||179,933|
|(1) Columns and rows may not add due to rounding.
(2) Light and medium crude oil and natural gas liquids.
(3) Refer to the oil and gas measures and definitions in the Advisories section of this document.
Finding and Development Costs
Paramount's finding and development ("F&D") costs per barrel are summarized below. The total F&D capital includes costs and changes in future development costs relating to major facilities and gathering system projects.
|2012 F&D Cost
Including Major Facilities & Gathering
|3-Year Average F&D|
|PROVED & PROBABLE|
|Oil Sands Bitumen||2.9||1,539.6||1,542.5||93.1||16.57||-||-||16.71|
|(1) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.|
|(2)Refer to the oil and gas measures and definitions in the Advisories section of this document.|
Paramount's F&D costs per barrel, excluding costs and changes in future development costs related to major facilities and gathering system projects are summarized below.
|2012 F&D Cost
Excluding Major Facilities & Gathering
|3-Year Average F&D|
|PROVED & PROBABLE|
|(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.
|Year ended December 31||2012||2011|
|Geological and geophysical||6.0||5.5|
|Drilling, completion and tie-ins||304.6||303.7|
|Facilities and gathering||212.5||156.5|
|Exploration and development expenditures||523.1||465.7|
|Land and property acquisitions||25.2||38.2|
|(1) Strategic Investments includes $7.0 million of undeveloped land purchases.|
|As at December 31||2012||2011|
|(000's of acres)||Gross(1)||Net(2)||Average
|Acreage assigned reserves||523||289||55%||574||334||58%|
|(1) "Gross" acres means the total acreage in which Paramount has an interest.
(2) "Net" acres means gross acres multiplied by Paramount's working interest therein.
Advance Notice Requirement for Nominating Directors
Paramount's board of directors today approved the adoption of Amended and Restated By-laws of the Corporation ("By-laws") which include an advance notice requirement ("Advance Notice Requirement") for shareholders who wish to nominate a person for election as a director of the Corporation (other than pursuant to a requisition of a meeting, or a shareholder proposal, made pursuant to the provisions of the Alberta Business Corporations Act).
The purpose of the Advance Notice Requirement is to provide shareholders, directors and management of the Corporation with a clear framework for nominating directors. Among other things, the Advance Notice Requirement fixes a deadline by which shareholders must submit a notice of director nominations to the Corporation prior to any annual or special meeting of shareholders where directors are to be elected, and sets out the information that must be included in the notice for it to be valid. In the case of an annual meeting of shareholders, notice must be given to the Corporation not less than 30 days nor more than 65 days prior to the date of the annual meeting; provided, that if the first public announcement of the meeting is given less than 50 days prior to the meeting date notice must be given not later than the close of business on the 10th day following such public announcement.
In the case of a special meeting of shareholders (which is not also an annual meeting), notice must be given to the Corporation not later than the close of business on the 15th day following the first public announcement of the date of the special meeting.
Advance notice requirements have been adopted by a number of Canadian issuers, and the deadlines in Paramount's Advance Notice Requirement are supported by Institutional Shareholder Services Inc.
The By-laws (including the Advance Notice Requirement) are effective immediately. At the annual meeting of shareholders to be held on May 8, 2013, shareholders will be asked to confirm and ratify the By-laws. A copy of the By-laws will be made available under the Company's profile at www.sedar.com.
Paramount Resources Ltd. is a Canadian oil and natural gas exploration, development and production company with operations focused in Western Canada. Paramount's common shares are listed on the Toronto Stock Exchange under the symbol "POU".
A copy of this press release in PDF format can be obtained at download/2013+March+7_release.pdf. Paramount's Management's Discussion and Analysis for the year ended December 31, 2012 can be found at download/2013+March+7_md%26a.pdf and the Company's Consolidated Financial Statements for the year ended December 31, 2012 can be obtained at download/2013+March+7_consolidated_financial_statements.pdf. This information will also be made available through Paramount's website at www.paramountres.com and SEDAR at www.sedar.com.
Paramount's Annual Information Form ("AIF") for the year ended December 31, 2012, which includes the disclosure and reports relating to reserves data and other oil and gas information required pursuant to National Instrument 51-101, will also be made available through Paramount's website at www.paramountres.com and SEDAR at www.sedar.com.
Certain statements in this document constitute forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "estimate", "expect", "plan", "schedule", "intend", "propose", or similar words suggesting future outcomes or an outlook. Forward looking information in this document includes, but is not limited to:
- expected production and sales volumes and the timing thereof;
- exploration, development and strategic investment plans and strategies and the anticipated costs, timing, and results thereof;
- budget allocations and capital spending flexibility;
- the availability and adequacy of facilities to process, de-ethanize, fractionate and transport natural gas and NGLs production;
- the scope, timing, and cost of proposed new facilities and facilities expansions and the expected capacity and benefits of such facilities;
- the negotiation and completion of arrangements for the transportation and sales of natural gas, NGLs, and bitumen;
- the timing and scope of the anticipated development of oilsands, carbonate bitumen, and shale gas assets;
- expected drilling programs, well tie-ins, facility construction and expansions, completions and the timing, scope and results thereof;
- estimated reserves and resources and the undiscounted and discounted present value of future net revenues from such reserves and resources (including the forecast prices and costs and the timing of expected production volumes and future development capital);
- future taxes payable or owing;
- business strategies and objectives;
- sources of and plans for funding Paramount's exploration, development, facilities and other expenditures;
- acquisition and disposition plans;
- operating and other costs and royalty rates;
- regulatory applications and the anticipated timing, results and scope thereof; and
- the outcome and timing of any legal claims, insurance claims, audits, assessments and regulatory matters and proceedings.
Such forward-looking information is based on a number of assumptions which may prove to be incorrect. The following assumptions have been made, in addition to any other assumptions identified in this document:
- future oil, gas, NGLs, and bitumen prices and general economic, business, and market conditions;
- the ability to obtain required capital, through access to capital markets and other means, to finance exploration and development activities and new and expanded facilities;
- the ability to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost to carry out activities;
- the ability to market oil, natural gas, NGLs and bitumen successfully to current and new customers;
- the ability to secure adequate product processing, fractionation, transportation and storage;
- the ability of Paramount and its industry partners to obtain drilling success and production levels consistent with expectations, including with respect to anticipated reserves additions and NGLs yields;
- the timely receipt of required regulatory approvals;
- expected timelines and budgets being met and anticipated results achieved, in respect of facilities and infrastructure development;
- anticipated rates of return from existing and planned projects relative to other opportunities;
- estimates of input and labour costs; and
- currency exchange and interest rates.
Although Paramount believes that the expectations reflected in such forward looking information is reasonable, undue reliance should not be placed on it as Paramount can give no assurance that such expectations will prove to be correct. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Paramount and described in the forward looking information. These risks and uncertainties include, but are not limited to:
- fluctuations in oil, natural gas, NGLs and bitumen prices and commodity price differentials;
- fluctuations in foreign currency exchange rates and interest rates;
- the uncertainty of estimates and projections relating to future revenue, future production, NGLs yields, costs and expenses and the timing thereof;
- the ability to secure adequate product processing, de-ethanization, fractionation, transportation and storage;
- uncertainties associated with exploration and development drilling and related activities;
- operational risks in exploring for, developing and producing oil, natural gas, NGLs and bitumen and the timing thereof;
- the ability to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost;
- potential disruptions, unexpected technical difficulties or other constraints in designing, developing, operating or utilizing new, expanded or existing facilities, including third-party facilities;
- risks and uncertainties involving the geology of oil and gas deposits;
- the uncertainty of reserves and resource estimates;
- the ability to generate sufficient cash flow from operations and obtain other sources of financing at an acceptable cost to fund planned operational, exploration and development activities, including costs of anticipated new and expanded facilities and other projects, and to meet current and future obligations;
- the ability to fulfill pipeline transportation, processing, de-ethanization and fractionation commitments;
- changes to, or in the interpretation or application of, laws, regulations or policies;
- changes in environmental laws including potential emission reduction obligations and fracing regulations;
- the receipt, timing, and scope of governmental or regulatory approvals;
- potential title defects affecting Paramount's properties;
- uncertainties regarding aboriginal land claims and co-existing with local populations and stakeholders; the effects of weather;
- the timing and cost of future abandonment and reclamation activities;
- clean-up costs or business interruptions resulting from environmental damage and contamination;
- the ability to enter into or continue leases;
- existing and potential lawsuits and regulatory actions;
- general economic, business and market conditions;
- industry wide pipeline, processing, de-ethanization and fractionation constraints; and
- other risks and uncertainties described elsewhere in this document and in Paramount's other filings with Canadian securities authorities.
The foregoing list of risks is not exhaustive. Additional information concerning these and other factors which could impact Paramount, its operations and its financial condition are included in Paramount's Annual Information Form for the year ended December 31, 2012. The forward-looking information contained in this document is made as of the date hereof and, except as required by applicable securities law, Paramount undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise.
In this document "Funds flow from operations", "Funds flow from operations - per Boe", "Funds flow from operations per share - diluted", "Netback", "Netback including commodity & insurance settlements", "Net Debt", "Exploration and development expenditures" and "Investments in other entities - market value", collectively the "Non-GAAP measures", are used and do not have any standardized meanings as prescribed by Generally Accepted Accounting Principles in Canada ("GAAP").
Funds flow from operations refers to cash from operating activities before net changes in operating non-cash working capital, geological and geophysical expenses and asset retirement obligation settlements. Funds flow from operations is commonly used in the oil and gas industry to assist management and investors in measuring the Company's ability to fund capital programs and meet financial obligations. Netback equals petroleum and natural gas sales less royalties, operating costs, production taxes and transportation costs. Netback is commonly used by management and investors to compare the results of the Company's oil and gas operations between periods. Net Debt is a measure of the Company's overall debt position after adjusting for certain working capital amounts and is used by management to assess the Company's overall leverage position. Refer to the calculation of Net Debt in the liquidity and capital resources section of Paramount's Management's Discussion and Analysis. Exploration and development expenditures refer to capital expenditures and geological and geophysical costs incurred by the Company's COUs (excluding land and acquisitions). The exploration and development expenditure measure provides management and investors with information regarding the Company's Principal Property spending on drilling and infrastructure projects, separate from land acquisition activity. Investments in other entities - market value reflects the Company's investments in enterprises whose securities trade on a public stock exchange at their period end closing price (e.g. Trilogy, MEG Energy, MGM Energy and others), and investments in all other entities at book value. Paramount provides this information because the market values of equity-accounted investments, which are significant assets of the Company, are often materially different than their carrying values.
Non-GAAP measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP, or other measures of financial performance calculated in accordance with GAAP. The Non-GAAP measures are unlikely to be comparable to similar measures presented by other issuers.
OIL AND GAS MEASURES AND DEFINITIONS
This document contains disclosures expressed as "Boe" and "Boe/d". All oil and natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. The term "liquids" is used to represent oil and natural gas liquids.
During the 2012, the value ratio between crude oil and natural gas was approximately 31:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.
The reserves replacement disclosure herein was calculated as the net increase in proved and probable reserves estimates from extensions and discoveries, technical revisions and economic factors divided by the total production in the year.
Oil Sands Resource Notes:
High Estimate is considered to be an optimistic estimate of the quantity of resource that will actually be recovered. It is unlikely that the actual remaining quantities of resources recovered will meet or exceed the high estimate. Those resources at the high end for the estimate range have a lower degree of certainty (a 10 percent confidence level) that the actual quantities recovered will equal or exceed the estimate.
Best Estimate is considered to be the best estimate of the quantity that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50 percent confidence level that the actual quantities recovered will equal or exceed the estimate.
Low Estimate is considered to be a conservative estimate of the quantity of resources that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. Those resources at the low end of the estimate range have the highest degree of certainty (a 90 percent confidence level) that the actual quantities recovered will equal or exceed the estimate.
Discovered Exploitable Bitumen In Place ("DEBIP") is the estimated volume of bitumen, as of a given date, which is contained in a subsurface stratigraphic interval of a known accumulation that meets or exceeds certain reservoir characteristics, such as minimum continuous net pay, porosity and mass bitumen content. For the Remaining Hoole Leases, the presence of these characteristics is considered necessary for the commercial application of known recovery technologies. There is no certainty that it will be commercially viable to produce any portion of the resources from the Remaining Hoole Leases.
Contingent Resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but are classified as a resource rather than a reserve due to one or more contingencies, such as the absence of regulatory applications, detailed design estimates or near term development plans. There is no certainty that it will be commercially viable to produce any portion of the contingent resources. For the Remaining Hoole Leases, contingencies which must be overcome to enable the reclassification of bitumen contingent resources as reserves include the finalization of plans for the development, submission of a regulatory application and management's intent to proceed evidenced by a development plan with major capital expenditures. Economic Contingent Resources are those contingent resources that are economically recoverable based on specific forecasts of commodity prices and costs (based on McDaniel's forecast prices and costs as of January 1, 2013). Volumes presented are working interest, before the deduction of royalties.
NPV means net present value and represents Cavalier Energy's share of future net revenue, before the deduction of income tax, from the economic contingent resources in the Grand Rapids formation within the Remaining Hoole Leases. The calculation considers such items as revenues, royalties, operating costs, abandonment costs and capital expenditures. Royalties have been calculated based on Alberta's Royalty Framework applicable to oil sands projects. The calculation does not consider financing costs and general and administrative costs. NPVs were calculated assuming natural gas is used as a fuel for steam generation. Revenues and expenditures were calculated based on McDaniel's forecast prices and costs as of January 1, 2013. The estimated net present values disclosed in this press release do not represent fair market value.