Pengrowth Announces 55 Percent Increase in 2012 Year-End Proved Plus Probable Reserves and Replacement of 672 Percent of 2012 Production
CALGARY, ALBERTA--(Marketwire - Feb 28, 2013) - Pengrowth Energy Corporation (PGF.TO) (PGH) is pleased to announce strong 2012 year-end reserve additions.
Highlights:
Proved plus probable (2P) reserves increased by 55 percent to 512.0 million barrels of oil equivalent (MMboe) at December 31, 2012 from 330.5 MMboe at year-end 2011.
Pengrowth replaced 672 percent of 2012 production, adding 213.2 MMboe of 2P reserves in 2012 at an all-in annual Finding, Development and Acquisition (FD&A) cost of $18.16 per boe including changes in Future Development Capital (FDC) for 2P reserves. The 2012 FD&A costs, excluding changes to FDC were $9.92 per boe for 2P reserves.
All-in Finding and Development (F&D) costs were $16.85 per boe for 2P reserves including changes in FDC.
Pengrowth''s three year average all-in FD&A and F&D costs for 2P reserves were $18.45 per boe and $17.36 per boe, respectively, including FDC ($11.38 per boe and $8.19 per boe, respectively, excluding FDC).
2012 crude oil and natural gas liquids (NGL) reserves increased by 29 percent and 79 percent on a proved (1P) and 2P basis, respectively. This significant increase in liquids reserves is a direct result of reserves acquired through the acquisition of NAL Energy Corporation (NAL) as well as focusing capital on oil and liquids-rich projects, particularly the Lindbergh thermal project.
At Lindbergh, reserves were increased significantly with 89 MMbbl of reserve additions due to delineation drilling and positive pilot results. At year-end 2012, 2P reserves stood at 95 MMbbl while 1P reserves were 13 MMbbl. The best estimate incremental contingent resources were 218 MMbbl.
2P reserve life index (RLI) increased to 14.7 years at year-end 2012, a 23 percent increase from the year-end 2011 figure of 12.0 years.
Reserves
Pengrowth''s 2P reserves at year-end 2012 were 512.0 MMboe based on an independent engineering evaluation conducted by GLJ Petroleum Consultants Ltd. (GLJ) effective December 31, 2012 and prepared in accordance with National Instrument 51-101 (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (COGEH). This represents a 55 percent increase in 2P reserves since December 31, 2011 resulting from a combination of acquisitions, drilling activity and increased reserve bookings at Lindbergh. Pengrowth replaced 672 percent of 2012 annual production through the addition of a total of 213.2 MMboe of 2P reserves offset by 31.7 MMboe of production, including 0.3 MMboe from the Lindbergh pilot.
Pengrowth''s total proved reserves of 300.1 MMboe account for 59 percent of total 2P reserves. Proved producing reserves of 237.7 MMboe represent approximately 79 percent of the total proved reserves.
Using a 6:1 boe conversion rate for natural gas, approximately 30 percent of 2P reserves are light/medium crude oil, 25 percent are heavy oil and bitumen, 8 percent are NGL and 37 percent are natural gas.
Using a 10 percent present value discount factor and GLJ''s January 1, 2013 pricing forecast, proved producing reserves and total proved reserves account for 61 and 70 percent respectively, of the 2P reserves before tax present value of $6.1 billion.
Company Interest Reserves Summary - December 31, 2012
(GLJ January 1, 2013 forecast prices and costs)
Light & Medium Crude Oil (Mbbl |
| Heavy Oil |
| Bitumen |
| Natural Gas Liquids (Mbbl |
| Natural |
| Total Oil |
| Percent of 2P Oil |
| |
Proved Producing | 85,484 | 15,486 | 1,653 | 25,749 | 655.9 | 237,685 | 46 | % | ||||||
Proved Developed Non-Producing | 2,333 | 78 | 0 | 845 | 21.8 | 6,883 | 1 | % | ||||||
Proved Undeveloped | 20,025 | 6,122 | 11,136 | 1,831 | 98.3 | 55,510 | 11 | % | ||||||
Total Proved | 107,841 | 21,687 | 12,789 | 28,425 | 776.0 | 300,078 | 59 | % | ||||||
Total Probable | 45,388 | 10,975 | 82,003 | 11,256 | 373.6 | 211,882 | 41 | % | ||||||
Total Proved Plus Probable (2P) | 153,229 | 32,662 | 94,792 | 39,681 | 1,149.6 | 511,960 | 100 | % |
2012 Operational and Property Review
Capital expenditures in 2012 were $467 million, before property acquisitions and dispositions. Pengrowth participated in drilling 183 gross (93.3 net) wells in 2012. The 2012 capital program yielded 103.8 MMboe of 2P reserve additions, including revisions, representing a 327 percent replacement of 2012 production. As a result of the successful pilot results and ongoing development activities, the Lindbergh thermal project contributed the largest increase where 88.8 MMboe of 2P reserves were added bringing the total 2P Lindbergh reserves to 94.8 MMboe.
In addition to the NAL acquisition, Pengrowth spent $87 million on property acquisitions, net of disposition proceeds. In aggregate, this added 110.8 MMboe of 2P reserves offset by the divesture of certain non- core properties with attributed 2P reserves of 1.4 MMboe.
Additional 2012 development activities and 2013 planned activities for each core area are outlined below:
Swan Hills Area
The Swan Hills trend is a significant conventional oil resource providing long term, low decline production and cash flow for the Company. This extensive carbonate oil reservoir provides Pengrowth with significant opportunities to put its expertise in horizontal drilling and multi-stage acid fracturing of carbonate reservoirs to work on its operated interests in Judy Creek, Carson Creek, House Mountain, Deer Mountain and Virginia Hills.
In 2012, Pengrowth spent $170.7 million on light oil and liquids-rich gas plays in the Swan Hills area, participating in the drilling of 36 gross (25.2 net) wells. In addition to ongoing miscible flood development and waterflood optimization, 2012 activity was primarily focused on the development of the tighter platform and R5 shoal zones at Judy Creek, Deer Mountain, Virginia Hills and Carson Creek. Further partner-operated development targeted the House Mountain, Freeman and Sawn Lake areas.
In 2013, Pengrowth plans to invest $132 million on light oil and liquids-rich gas plays in the Swan Hills trend. The 2013 program includes approximately 15 net operated and non-operated drills, as well as significant optimization activities in Judy Creek, Virginia Hills, Sawn Lake, Deer Mountain and House Mountain.
At Judy Creek, Pengrowth will continue to exploit numerous development opportunities in the Beaverhill Lake A and B pools with new drills, re-entries, recompletions and workovers. The remainder of Pengrowth''s activity will focus on expanding its footprint within the Swan Hills trend by developing opportunities identified at Deer and House mountains, Virginia Hills and Sawn Lake. Pengrowth also holds a 100% working interest in 47 sections of land on an undeveloped platform margin play in the Devil area with significant upside potential, which the Company intends to exploit in 2013.
Olds/Garrington
The Olds/Garrington area is located in south-central Alberta and is comprised of stacked reservoirs offering multi-zone potential targeting light oil and liquids-rich natural gas development. Opportunities in the area are centered on the exploitation of the Lochend and Garrington Cardium oil and Harmattan Elkton and Mannville liquids-rich natural gas plays. These plays provide Pengrowth with a complementary set of opportunities that will support continued capital development in this area for several years. In 2012, Pengrowth spent $95 million in the Olds/Garrington area on activities targeting the Elkton, Mannville and Cardium plays, drilling 35 gross (17.8 net) wells during the year.
Capital expenditures in this area in 2013 are expected to be approximately $200 million, primarily targeting Cardium light oil ($163 million/40 net wells) in the Lochend and Garrington areas.
At Lochend, Pengrowth recently acquired additional high working interest Cardium lands which are included in its 2013 development plans. These are prolific, light oil wells with approximate netbacks of $64/bbl and recycle ratios in excess of 3.0 times.
Additional capital has been allocated to the Elkton and Mannville liquids-rich natural gas plays, which are characterized by their high liquids content (approximately 50 to 90 bbls/ MMcf) providing strong economic returns and cash flows.
Pengrowth currently has six rigs drilling in the Olds/Garrington area and anticipates drilling over 50 net wells in 2013.
Lindbergh
The Lindbergh thermal project is a key component of Pengrowth''s growth strategy, with the potential to grow oil production by up to 50,000 barrels per day (bbl/d) of bitumen. The Lindbergh property, encompassing 42.5 sections of land in the Cold Lake area of Alberta, is 100 percent owned and operated by Pengrowth. This 11°API oil has favorable viscosity characteristics and is in a clean, continuous, high permeability reservoir. Lindbergh is expected to provide Pengrowth with the potential to develop a significant commercial project of low cost, low decline, stable oil production, with a 25 year reserve life.
Pengrowth began steam injection into the Lindbergh pilot project in February 2012. Pilot production rates and instantaneous steam oil ratio (ISOR) outperformed expectations during the year. The pilot, which consists of two well pairs, has been in operation for over 10 months and is currently producing in excess of 1,600 bbl/d of bitumen, with a consistent ISOR of 1.7. To date, the Pilot has produced more than 425,000 bbls of bitumen.
The excellent pilot results and associated reserve potential have provided Pengrowth with the confidence needed to accelerate and expand the first phase of commercial development. As of year-end 2012, GLJ estimated 95 MMbbl of 2P reserves and 218 MMbbl of additional best estimate contingent resources for Lindbergh. On January 10, 2013, Pengrowth''s Board of Directors approved the first phase of Lindbergh commercial development, which is expected to reach 12,500 bbl/d of bitumen by early 2015. Two additional expansion phases are expected to increase total Lindbergh production to 50,000 bbl/d of bitumen by 2018.
Pengrowth plans to spend $300 million at Lindbergh in 2013, inclusive of $55 million announced in December 2012. This capital will be spent on long lead items, starting construction of the central processing facility in the second quarter and the drilling of 8 of 23 well pairs which is expected to commence in the fourth quarter.
Regulatory, environmental, landowner and First Nations discussions surrounding Lindbergh are on track. Pengrowth anticipates regulatory and environmental approvals for Phase 1 to be granted in Q2 2013.
Reserves Reconciliation
Total 2P reserve additions in 2012 were 213.2 MMboe, replacing production by 672 percent and growing reserves at year-end by 55 percent compared to 2011.
Reserve additions of 103.8 MMboe, including revisions, resulted from drilling and improved recovery projects. The most significant of these additions were reserves attributed to the Lindbergh thermal project, where 2P reserves increased by 88.8 MMboe in 2012 over year-end 2011 numbers.
Acquisitions contributed to an additional 110.8 MMboe of 2P reserves being added in 2012, offset by minor dispositions of 1.4 MMboe.
Company Interest Reserves Reconciliation 2012
(GLJ January 1, 2013 forecast prices and costs)
Light & Medium Crude | Heavy Oil |
| Natural Gas Liquids | Natural Gas | Total Oil Equivalent | ||||||||
Oil (Mbbl | ) | (Mbbl | ) | (Mbbl | ) | (Mbbl | ) | (Bcf | ) | (Mboe | ) | ||
Total Proved | |||||||||||||
December 31, 2011 | 85,455 | 19,676 | 4,436 | 22,512 | 617.0 | 234,910 | |||||||
Technical Revisions | 1,686 | 733 | 1 | 770 | 27.5 | 7,735 | |||||||
Drilling | 2,914 | 3,172 | 8,678 | 705 | 15.3 | 18,030 | |||||||
Improved Recovery | 1,009 | 267 | 0 | 148 | 0.2 | 1,461 | |||||||
Acquisitions | 28,058 | 515 | 0 | 8,801 | 236.5 | 76,826 | |||||||
Dispositions | (93 | ) | (164 | ) | 0 | (67 | ) | (3.8 | ) | (963 | ) | ||
Economic Factors | (938 | ) | (129 | ) | 0 | (516 | ) | (27.8 | ) | (6,211 | ) | ||
Production | (10,250 | ) | (2,384 | ) | (326 | ) | (3,927 | ) | (88.9 | ) | (31,710 | ) | |
December 31, 2012 | 107,841 | 21,687 | 12,789 | 28,425 | 776.0 | 300,079 | |||||||
Total Proved Plus Probable | |||||||||||||
December 31, 2011 | 116,823 | 25,550 | 6,348 | 30,746 | 906.3 | 330,511 | |||||||
Technical Revisions | 1,086 | 608 | 1 | (423 | ) | 14.3 | 3,615 | ||||||
Drilling | 4,762 | 8,068 | 88,769 | 1,067 | 16.2 | 105,356 | |||||||
Improved Recovery | 1,406 | 248 | 0 | 34 | 0.2 | 1,719 | |||||||
Acquisitions | 40,337 | 958 | 0 | 12,747 | 340.4 | 110,814 | |||||||
Dispositions | (145 | ) | (218 | ) | 0 | (103 | ) | (5.8 | ) | (1,426 | ) | ||
Economic Factors | (790 | ) | (168 | ) | 0 | (459 | ) | (33.0 | ) | (6,919 | ) | ||
Production (1) | (10,250 | ) | (2,384 | ) | (326 | ) | (3,927 | ) | (88.9 | ) | (31,710 | ) | |
December 31, 2012 | 153,229 | 32,662 | 94,792 | 39,681 | 1,149.6 | 511,960 | |||||||
(1) | For reserves reporting purposes, 2012 annual production includes production from the Lindbergh pilot, which is not included in the production figures in our financial disclosure. |
Before Income Tax Net Present Value Summary as at December 31, 2012
(GLJ January 1, 2013 forecasted prices and costs)
Discounted at | ||||||||||||
($ 000, except percentages) | Undiscounted | 5 | % | 10 | % | 15 | % | 20 | % | Percent of 2P Discounted at 10 | % | |
Proved Producing | 6,143 | 4,610 | 3,704 | 3,110 | 2,693 | 61 | % | |||||
Proved Developed Non-Producing | 208 | 125 | 86 | 64 | 50 | 1 | % | |||||
Proved Undeveloped | 1,521 | 793 | 465 | 284 | 172 | 8 | % | |||||
Total Proved | 7,872 | 5,528 | 4,255 | 3,458 | 2,916 | 70 | % | |||||
Total Probable | 6,059 | 3,175 | 1,834 | 1,127 | 717 | 30 | % | |||||
Total Proved Plus Probable (2P) | 13,931 | 8,703 | 6,088 | 4,586 | 3,632 | 100 | % | |||||
Select streams of GLJ''s January 1, 2013 forecast prices and inflation rates for costs are shown below:
WTI Crude Oil | Edm Light Crude Oil | WCS Crude Oil | Natural Gas at AECO | Inflation Rate | |||||||
Year | ($US/bbl | ) | ($Cdn/bbl | ) | ($Cdn/bbl | ) | ($Cdn/MMBtu | ) | (%/year | ) | |
2012 (Actual) | 94.10 | 86.86 | 73.29 | 2.45 | - | ||||||
2013 | 90.00 | 85.00 | 70.13 | 3.38 | 2.0 | ||||||
2014 | 92.50 | 91.50 | 76.15 | 3.83 | 2.0 | ||||||
2015 | 95.00 | 94.00 | 78.22 | 4.28 | 2.0 | ||||||
2016 | 97.50 | 96.50 | 80.29 | 4.72 | 2.0 | ||||||
2017 | 97.50 | 96.50 | 80.29 | 4.95 | 2.0 | ||||||
2018 | 97.50 | 96.50 | 80.29 | 5.22 | 2.0 | ||||||
2019 | 98.54 | 97.54 | 81.16 | 5.32 | 2.0 | ||||||
2020 | 100.51 | 99.51 | 82.79 | 5.43 | 2.0 | ||||||
2021 | 102.52 | 101.52 | 84.46 | 5.54 | 2.0 | ||||||
2022 | 104.57 | 103.57 | 86.16 | 5.64 | 2.0 | ||||||
Thereafter | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | 2.0 |
Finding, Development and Acquisition Costs
During 2012, Pengrowth spent $461 million, net of information technology and office expenditures, on development and optimization activities, which added 21.0 MMboe of proved and 103.8 MMboe of 2P reserves including revisions. The largest 2P additions were at Lindbergh, where 2P reserves increased by 88.8 MMboe due to further delineation drilling and superior pilot performance.
Pengrowth spent $1,654 million on acquisitions in 2012, net of proceeds from dispositions, adding 2P reserves of 109.4 MMboe.
Pengrowth''s 2012 FD&A costs are summarized below. These are determined separately for exploration and development activities, and acquisition and disposition transactions, and with and without the change in future development costs (FDC). FDC reflects the amount of estimated capital that will be required to bring non-producing, undeveloped or probable reserves on stream. These forecasts of future development costs will change with time due to ongoing development activity, inflationary changes in capital costs and acquisition or disposition of assets. Pengrowth includes FD&A costs because it believes that acquisitions and dispositions can have a significant impact on its ongoing reserve replacement costs.
2010 - 2012 | ||||||||
2012 | 2011 | Weighted Average | ||||||
| Proved plus |
| Proved plus |
| Proved plus | |||
FD&A Costs Excluding Future Development Capital | ||||||||
Exploration and Development Capital Expenditures - $MM | 461.0 | 461.0 | 603.4 | 603.4 | 1,393.8 | 1,393.8 | ||
Exploration and Development Reserve Additions including Revisions - MMboe | 21.0 | 103.8 | 41.0 | 39.3 | 82.6 | 170.2 | ||
Finding and Development Cost - $/boe | 21.93 | 4.44 | 14.70 | 15.34 | 16.88 | 8.19 | ||
F&D Recycle Ratio, $/$ | 1.0 | 5.2 | 1.9 | 1.9 | 1.5 | 3.2 | ||
Net Acquisition Capital - $MM | 1,654.2 | 1,654.2 | (8.3 | ) | (8.3 | ) | 2,046.5 | 2,046.5 |
Net Acquisition Reserve Additions - MMboe | 75.9 | 109.4 | (0.2 | ) | (0.3 | ) | 86.9 | 132.0 |
Net Acquisition Cost - $/boe | 21.81 | 15.12 | 52.06 | 32.85 | 23.54 | 15.51 | ||
Total Capital Expenditures including Net Acquisitions - $MM | 2,115.2 | 2,115.2 | 595.1 | 595.1 | 3,440.3 | 3,440.3 | ||
Reserve Additions including Net Acquisitions - MMboe | 96.9 | 213.2 | 40.9 | 39.1 | 169.5 | 302.2 | ||
Finding Development and Acquisition Cost - $/boe | 21.83 | 9.92 | 14.56 | 15.23 | 20.30 | 11.38 | ||
FD&A Costs Including Future Development Capital | ||||||||
Exploration and Development Capital Expenditures - $MM | 461.0 | 461.0 | 603.4 | 603.4 | 1,393.8 | 1,393.8 | ||
Exploration and Development Change in FDC - $MM | 104.6 | 1,288.0 | 257.0 | 188.0 | 393.6 | 1,562.0 | ||
Exploration and Development Capital including Change in FDC - $MM | 565.6 | 1,748.9 | 860.4 | 791.4 | 1,787.4 | 2,955.8 | ||
Exploration and Development Reserve Additions including Revisions - MMboe | 21.0 | 103.8 | 41.0 | 39.3 | 82.6 | 170.2 | ||
Finding and Development Cost - $/boe | 26.91 | 16.85 | 20.96 | 20.12 | 21.65 | 17.36 | ||
F&D Recycle Ratio, $/$ | 0.9 | 1.4 | 1.4 | 1.4 | 1.2 | 1.5 | ||
Net Acquisition Capital - $MM | 1,654.2 | 1,654.2 | (8.3 | ) | (8.3 | ) | 2,046.5 | 2,046.5 |
Net Acquisition FDC - $MM | 229.8 | 467.2 | 0.0 | 0.0 | 263.8 | 573.2 | ||
Net Acquisition Capital including FDC - $MM | 1,884.0 | 2,121.4 | (8.3 | ) | (8.3 | ) | 2,310.3 | 2,619.7 |
Net Acquisition Reserve Additions - MMboe | 75.9 | 109.4 | (0.2 | ) | (0.3 | ) | 86.9 | 132.0 |
Net Acquisition Cost - $/boe | 24.83 | 19.39 | 52.06 | 32.85 | 26.58 | 19.85 | ||
Total Capital Expenditures including Net Acquisitions - $MM | 2,115.2 | 2,115.2 | 595.1 | 595.1 | 3,440.3 | 3,440.3 | ||
Total Change in FDC - $MM | 334.4 | 1,755.2 | 257.0 | 188.0 | 657.4 | 2,135.2 | ||
Total Capital including Change in FDC - $MM | 2,449.6 | 3,870.4 | 852.1 | 783.1 | 4,097.7 | 5,575.5 | ||
Reserve Additions including Net Acquisitions - MMboe | 96.9 | 213.2 | 40.9 | 39.1 | 169.5 | 302.2 | ||
Finding Development and Acquisition Cost including FDC - $/boe | 25.29 | 18.16 | 20.84 | 20.04 | 24.18 | 18.45 | ||
2010 - 2012 | ||||||||
2012 | 2011 | Weighted Average | ||||||
Operating Netback ($/boe) (1) | 22.93 | 28.45 | 25.94 | |||||
(1) | The operating netbacks are equal to sales revenue plus other income less royalties, operating expenses and transportation costs. Please see Pengrowth''s 2012 year-end Management Discussion & Analysis (MD&A) and Annual Information Form (AIF) dated February 28, 2013 for further information. |
(2) | The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in the estimated future development costs generally will not reflect total F&D costs related to reserves additions for that year. |
Total Future Net Revenue (Undiscounted)
(GLJ January 1, 2013 forecast pricing and costs)
($millions) | Revenue | Royalties | Operating | Development | Abandonment | Revenue Before | Income | Revenue After |
Proved Producing | 15,098 | 2,646 | 5,694 | 265 | 350 | 6,143 | 351 | 5,792 |
Proved Developed Non-Producing | 427 | 103 | 89 | 23 | 4 | 208 | 55 | 153 |
Proved Undeveloped | 4,425 | 724 | 1,249 | 906 | 25 | 1,521 | 418 | 1,103 |
Total Proved | 19,950 | 3,473 | 7,032 | 1,194 | 379 | 7,872 | 825 | 7,047 |
Total Probable | 15,303 | 3,032 | 4,312 | 1,828 | 72 | 6,059 | 1,588 | 4,471 |
Total Proved Plus Probable | 35,253 | 6,505 | 11,344 | 3,022 | 451 | 13,931 | 2,412 | 11,519 |
(1) | Includes GLJ''s estimate of well abandonment costs and abandonment costs for Sable Island facilities and subsea pipelines, but does not include abandonment costs for other facilities or any surface reclamation costs. Please see our AIF for further information. |
(2) | Income tax values were calculated by Pengrowth using GLJ''s before tax cash flow, current corporate tax rates, existing tax pools and additions to the tax pools through capital expenditures as forecast by GLJ. Please see our AIF for further information. |
Reserve Life Index
Pengrowth''s proved RLI increased to 9.2 years from 9.0 years in 2011. The RLI for proved plus probable reserves increased to 14.7 years at year-end 2012, a 23 percent increase from the year-end 2011 figure of 12.0 years.
Reserve Life Index (years) | 2012 | 2011 | 2010 | 2009 |
Proved Producing | 7.6 | 7.6 | 7.2 | 7.3 |
Total Proved | 9.2 | 9.0 | 8.2 | 8.3 |
Total Proved plus Probable | 14.7 | 12.0 | 11.1 | 10.6 |
RLI refers to the number of years determined by dividing Company Interest reserves of a property by the next year''s forecast Company Interest production for the corresponding reserve category from such property. The reserves and next year''s forecast production for such property come from the GLJ Report.
Tax Pools
Pengrowth''s tax pools totaled approximately $4.5 billion as at December 31, 2012. The table below provides an estimate of tax pools by category as at December 31, 2012. These estimates are based upon forecasts prepared internally and have not been verified by any provincial or federal taxing authority. Pengrowth does not anticipate being subject to any cash income taxes prior to 2017.
Tax Pools | ($ millions) |
COGPE | 1,564 |
CDE | 891 |
UCC | 851 |
CEE | 161 |
Other (Injectants, etc.) | 1,005 |
Total Tax Pools | 4,472 |
Reserves and Contingent Resources Classification
Reserves and contingent resources included herein are stated on a company-interest basis (working interest before deduction of royalties and including any company royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with NI 51-101 Standards of Disclosure for Oil and Gas Activities and COGEH. In addition to the information disclosed in this news release, more detailed information is included in Pengrowth''s Annual Information Form (AIF).
The following table summarizes GLJ''s estimate of reserves and economic contingent resources, as of year-end 2012, for the Lindbergh oil sands property and Groundbirch natural gas property.
Reserves (MMboe) | Contingent Resources (MMboe) | |||||||
Field | Proved | Proved + Probable | Proved + Probable + Possible | Low Estimate | Best Estimate | High Estimate | ||
Lindbergh | 13 | 95 | 155 | 194 | 218 | 328 | ||
Groundbirch | 11 | 28 | 33 | 26 | 46 | 83 | ||
The contingencies which prevent the contingent resources from being classified as reserves at Lindbergh include the need for additional evaluation well drilling within the area, firm development plans, high quality project design and cost estimates and commitment by Pengrowth for future development phases, and submission of regulatory application to expand the currently proposed development area.
The primary contingency which prevents the contingent resources at Groundbirch to be classified as reserves is the early evaluation and delineation stage of the tight gas resource. Additional drilling, completion and testing data is required before Pengrowth can commit to further development.
Pengrowth''s AIF dated February 28, 2013 can be accessed immediately on Pengrowth''s website at www.pengrowth.com, and has been filed on SEDAR at www.sedar.com and as a Form 40-F on EDGAR at www.sec.gov/edgar.shtml.
About Pengrowth:
Pengrowth Energy Corporation is a dividend-paying, intermediate Canadian producer of oil and natural gas, headquartered in Calgary, Alberta. Pengrowth''s assets include the Swan Hills light oil, Cardium light oil and Lindbergh thermal bitumen projects. Pengrowth''s shares trade on both the Toronto Stock Exchange under the symbol "PGF" and on the New York Stock Exchange under the symbol "PGH".
Pengrowth Energy Corporation
Derek Evans, President and Chief Executive Officer
Advisory Regarding Reserves, Contingent Resources and Production Information
All amounts are stated in Canadian dollars unless otherwise specified. All reserves, reserve life index, and production information herein is based upon Pengrowth''s company interest (Pengrowth''s working interest share of reserves or production plus Pengrowth''s royalty interest, being Pengrowth''s interest in production and payment that is based on the gross production at the wellhead), before deduction of royalty obligations and using GLJ''s January 1, 2013 forecast prices and costs as disclosed herein. Numbers presented may not add due to rounding.
The estimated value of reserves disclosed in this press release do not represent fair market value of the reserves.
The estimates of reserves and future net revenues for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to effects of aggregation. When used herein, the term "boe" means barrels of oil equivalent on the basis of one boe being equal to one barrel of oil or NGLs or 6,000 cubic feet of natural gas (6 mcf: 1 bbl). Barrels of oil equivalent may be misleading, particularly if used in isolation. A conversion ratio of six mcf of natural gas to one boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies. The contingencies may include factors such as economics, legal, environmental, political and regulatory matters or lack of markets. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates. Contingent Reserves do not constitute and should not be confused with reserves. There is no certainty that it will be commercially viable to produce any portion on the Contingent Resources. The estimates of Contingent Resources associated with Pengrowth''s Lindbergh Oil Sands property and Groundbirch gas property included herein have been evaluated by GLJ, Pengrowth''s independent qualified reserves evaluator, in accordance with COGEH and NI 51-101. A best estimate is the estimate of the quantity of resource that will be recovered from the accumulation, which under probabilistic methodology reflects a 50 percent confidence level. A low estimate is the estimate of the quantity of resource that will be recovered from the accumulation, which under probabilistic methodology reflects a 90 percent confidence level. A high estimate is the estimate of the quantity of resource that will be recovered from the accumulation, which under probabilistic methodology reflects a 10 percent confidence level. The Contingent Resources as disclosed herein are considered economic based on forecast prices and costs as at December 31, 2012. Additional information relating to the Contingent Resources estimate for Pengrowth''s Lindbergh Oil Sands property and Groundbirch gas property, including specific contingencies and significant positive and negative factors associated with the estimate, can be found in Pengrowth''s AIF dated February 28, 2013, which can be accessed immediately on Pengrowth''s website at www.pengrowth.com and has been filed on SEDAR at www.sedar.com and as Form 40-F on EDGAR at www.sec.gov/edgar.shtml.
Caution Regarding Forward Looking Information:
This press release contains forward-looking statements within the meaning of securities laws, including the "safe harbour" provisions of the Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "intend", "forecast", "target", "project", "guidance", "may", "will", "should", "could", "estimate", "predict" or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this press release include, but are not limited to, statements with respect to 2013 capital expenditures and the allocation thereof, anticipated Lindbergh production, IRR, net present value, costs and timing, drilling plans, liquids content of production, recycle ratios, production, production volumes, operating costs, royalties, future taxes and tax pools, future development costs, Pengrowth''s production profile, liquids to gas ratio, reserves and the replacement thereof. Statements relating to "reserves" and "resources" are deemed to be forward -looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can profitably be produced in the future.
Forward-looking statements and information are based on current beliefs as well as assumptions made by and information currently available to Pengrowth concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.
By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: changes in general economic, market and business conditions; the volatility of oil and gas prices; fluctuations in production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth''s ability to replace and expand oil and gas reserves; geological, technical, drilling and processing problems and other difficulties in producing reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; fluctuations in interest rates; inadequate insurance coverage; compliance with environmental laws and regulations; actions by governmental or regulatory agencies, including changes in tax laws; Pengrowth''s ability to access external sources of debt and equity capital; the impact of foreign and domestic government programs and the occurrence of unexpected events involved in the operation and development of oil and gas properties. Further information regarding these factors may be found under the heading "Business Risks" in our most recent management''s discussion and analysis and under "Risk Factors" in Pengrowth''s AIF.
The foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this press release are made as of the date of this press release, and Pengrowth does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable laws.
The forward-looking statements contained in this press release are expressly qualified by this cautionary statement.
Non-GAAP Financial Measures
This news release refers to certain financial measures that are not determined in accordance with International Financial Reporting Standards (IFRS). These measures do not have standardized meanings and may not be comparable to similar measures presented by other oil and gas companies. Measures such as operating netbacks do not have standardized meanings prescribed by Generally Accepted Accounting Principles (GAAP). Additional information regarding these measures may be found in the most recent Management''s Discussion and Analysis report dated February 28, 2013.
Note to US Readers
Current SEC reporting requirements permit oil and gas companies, in their filings with the SEC, to disclose probable and possible reserves, in addition to the required disclosure of proved reserves. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. Because we are permitted to prepare our reserves information in accordance with Canadian disclosure requirements, we have included contingent resources, disclosed reserves before the deduction of royalties and interests of others and determined and disclosed our reserves and the estimated future net cash therefrom using forecast prices and costs. See "Presentation of our Reserve Information" in our most recent Annual Information Form or Form 40-F for more information.
We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.
We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves. The SEC permits, but does not require, the disclosure of reserves based on forecast prices and costs.
We include herein estimates of proved, 2P and possible reserves, as well as contingent resources. The SEC permits, but does not require the inclusion of estimates of probable and possible reserves in filings made with it by United States oil and gas companies. The SEC does not permit the inclusion of estimates of contingent resources in reports filed with it by United States companies.
