CALGARY, ALBERTA--(Marketwire - Feb. 28, 2012) - Pengrowth Energy Corporation (TSX:PGF) (NYSE:PGH) is pleased to announce our 2011 year-end reserves information.
Highlights
- Our 2011 capital program was $609.1 million and increased proved plus probable (2P) reserves by 3.8 percent to 330.5 million barrels of oil equivalent (MMboe) from year-end 2010 levels.
- Proved reserves grew six percent to 234.9 MMboe from 221.0 MMboe at December 31, 2010.
- 2011 crude oil and natural gas liquids (NGL) reserves increased by 12.2 percent and 7.9 percent on a proved and 2P basis, respectively. This significant increase in liquid content is a direct result of focusing capital on oil projects.
- Proved reserves constitute 71 percent of the total 2P reserves compared to 69 percent at year-end 2010.
- Pengrowth replaced 145 percent of 2011 production, adding 39.3 MMboe of 2P reserves in 2011.
- Economic best estimate contingent resource at Lindbergh increased 53 percent to 296 million barrels (MMbbls) of bitumen compared to 193 MMbbls of bitumen at December 31, 2010.
- Lindbergh Steam Assisted Gravity Drainage (SAGD) pilot results will be monitored over the coming months with the objective of having GLJ Petroleum Consultants Ltd. (GLJ) provide a reserves update in the third quarter.
- Finding and development costs (F&D) of $20.12 per boe for 2P reserves and $20.96 per boe for proved reserves, including changes in future development capital (FDC) ($15.34 per boe and $14.70 per boe, respectively, excluding changes in FDC). Excluding maintenance and enhancement capital of $46.2 million and $61.4 million of capital spent on our Lindbergh SAGD project, the 2P F&D costs, including the change in FDC, decreased to $17.38 per boe.
- Annual finding, development and acquisition (FD&A) costs of $20.04 per boe for 2P reserves and $20.84 per boe for proved reserves, including changes to FDC ($15.23 per boe and $14.56 per boe, respectively, excluding changes in FDC).
- Reserve life index (RLI) for proved and 2P reserves increased to 9.0 years and 12.0 years, respectively.
Reserves
Our 2P reserves at December 31, 2011 were 330.5 MMboe. This represents a 145 percent replacement of 2011 annual production. A total of 39.3 MMboe of reserves were added through drilling activity and improved recovery applications and technical revisions, offset by 27.0 MMboe of production, and minor net dispositions of 0.3 MMboe. Of the 39.3 MMboe addition, 9.3 MMboe are net positive technical revisions, which is inclusive of an estimated 4.3 MMboe reduction due to the effects of lower forecasted commodity prices.
Total proved reserves account for 71 percent of our 2P reserves. Proved producing reserves are estimated at 188.0 MMboe. This represents approximately 80 percent of the total proved reserves.
Using a ten percent present value discount factor and GLJ's January 1, 2012 pricing forecast, proved reserves account for 78 percent, and total proved producing reserves account for 67 percent, of the 2P reserves before tax present value of $4.8 billion, respectively.
Using a 6:1 boe conversion rate for natural gas, approximately 35 percent of our 2Preserves are light/medium crude oil, 10 percent are heavy oil, nine percent are NGL, 43 percent are natural gas and three percent are coal bed methane.
Reserves Summary 2011
(Company interest)
GLJ January 1, 2012 forecast prices and costs
| Light & Medium Crude Oil(Mbbl) | Heavy Oil (1)(Mbbl) | Natural Gas Liquids (Mbbl) | Natural Gas(Bcf) | Total Oil Equivalent(Mboe) | Percent of P+P Oil Equivalent (%) | |||||||
| Proved Producing | 67,100 | 16,015 | 19,904 | 510.1 | 188,038 | 57% | ||||||
| Proved Developed Non-Producing | 1,902 | 1,774 | 930 | 20.7 | 8,062 | 2% | ||||||
| Proved Undeveloped | 16,453 | 6,324 | 1,678 | 86.1 | 38,811 | 12% | ||||||
| Total Proved | 85,455 | 24,112 | 22,512 | 616.9 | 234,910 | 71% | ||||||
| Total Probable | 31,368 | 7,786 | 8,234 | 289.3 | 95,601 | 29% | ||||||
| Total Proved Plus Probable (2P) | 116,823 | 31,898 | 30,746 | 906.3 | 330,511 | 100% |
| (1) Includes 4.4 MMbbl (Proved) & 6.3 MMbbl of bitumen (2P) for Lindbergh | ||||||||||||
| Company Interest | ||||||||||||
| GLJ January 1, 2012 Forecast Prices and Costs | ||||||||||||
Reserves Reconciliation
Reserve additions of 39.3 MMboe resulted from drilling and improved recovery projects and net positive technical revisions. Most significant of these were drilling extensions at Swan Hills, Olds and Groundbirch, enhanced oil recovery at East Bodo, positive revisions due to performance improvements at Olds, Quirk Creek and Jenner and a negative revision at Groundbirch due to performance. As well, there were minor acquisitions and dispositions resulting in a net decrease of 0.3 MMboe. Production during 2011 amounted to 27.0 MMboe or 73,973 boe per day (boepd).
| Reserves Reconciliation 2011 | ||||||||||
| (Company interest) | ||||||||||
| GLJ January 1, 2012 forecast prices and costs | ||||||||||
| Light & | Natural Gas | Natural | Total Oil | |||||||
| Medium Crude | Heavy Oil | Liquids | Gas | Equivalent | ||||||
| Oil (Mbbl | ) | (Mbbl | ) | (Mbbl | ) | (Bcf | ) | (Mboe | ) | |
| Total Proved | ||||||||||
| December 31, 2010 | 81,228 | 15,238 | 21,254 | 619.8 | 221,028 | |||||
| Technical Revisions | 5,326 | 3,258 | 2,305 | 28.2 | 15,587 | |||||
| Drilling (1) | 6,159 | 5,135 | 2,462 | 48.9 | 21,902 | |||||
| Improved Recovery | 647 | 2,827 | 45 | 0.2 | 3,553 | |||||
| Acquisitions | 84 | - | 9 | 0.1 | 110 | |||||
| Dispositions | (157 | ) | - | (39 | ) | (0.4 | ) | (269 | ) | |
| Production | (7,831 | ) | (2,345 | ) | (3,526 | ) | (79.8 | ) | (27,000 | ) |
| December 31, 2011 | 85,455 | 24,112 | 22,512 | 616.9 | 234,910 | |||||
| Total Proved Plus Probable | ||||||||||
| December 31, 2010 | 110,298 | 26,472 | 29,481 | 913.0 | 318,429 | |||||
| Technical Revisions | 4,300 | 2,273 | 1,851 | 5.4 | 9,322 | |||||
| Drilling (1) | 9,369 | 1,010 | 2,923 | 67.8 | 24,608 | |||||
| Improved Recovery | 786 | 4,489 | 62 | 0.4 | 5,405 | |||||
| Acquisitions | 107 | - | 12 | 0.1 | 141 | |||||
| Dispositions | (206 | ) | - | (58 | ) | (0.8 | ) | (394 | ) | |
| Production | (7,831 | ) | (2,345 | ) | (3,526 | ) | (79.8 | ) | (27,000 | ) |
| December 31, 2011 | 116,823 | 31,898 | 30,746 | 906.3 | 330,511 | |||||
| (1) Includes drilling extensions and infill drilling. | ||||||||||
| Net Present Value Summary 2011 | ||||||
| GLJ January 1, 2012 forecasted prices and costs | ||||||
| Before Income Taxes | ||||||
| Discounted | Discounted | Discounted | Discounted | Percent of P+P | ||
| ($ millions, except percentages) | Undiscounted | at 5% | at 10% | at 15% | at 20% | Discounted at 10% |
| Proved Producing | 5,489 | 4,063 | 3,242 | 2,714 | 2,347 | 67% |
| Proved Developed Non-Producing | 243 | 160 | 119 | 95 | 79 | 2% |
| Proved Undeveloped | 1,155 | 649 | 385 | 233 | 138 | 8% |
| Total Proved | 6,886 | 4,871 | 3,747 | 3,042 | 2,564 | 78% |
| Total Probable | 3,300 | 1,725 | 1,064 | 727 | 531 | 22% |
| Total Proved Plus Probable (2P) | 10,186 | 6,597 | 4,811 | 3,769 | 3,095 | 100% |
Certain of GLJ's January 1, 2012 forecast prices and inflation rate for costs are shown below:
| WTI | Light Crude | Natural Gas | Inflation | |
| Crude Oil | Oil | at AECO | Rate | |
| Year | ($US/bbl) | ($Cdn/bbl) | ($Cdn/MMBtu) (%/year) | |
| 2011 (Actual) | 94.83 | 95.15 | 3.68 | - |
| 2012 | 97.00 | 97.96 | 3.49 | 2.0 |
| 2013 | 100.00 | 101.02 | 4.13 | 2.0 |
| 2014 | 100.00 | 101.02 | 4.59 | 2.0 |
| 2015 | 100.00 | 101.02 | 5.05 | 2.0 |
| 2016 | 100.00 | 101.02 | 5.51 | 2.0 |
| 2017 | 100.00 | 101.02 | 5.97 | 2.0 |
| 2018 | 101.35 | 102.40 | 6.21 | 2.0 |
| 2019 | 103.38 | 104.47 | 6.33 | 2.0 |
| 2020 | 105.45 | 106.58 | 6.46 | 2.0 |
| 2021 | 107.56 | 108.73 | 6.58 | 2.0 |
| Thereafter | +2.0%/yr | +2.0%/yr | +2.0%/yr | 2.0 |
Reserve Life Index
Our proved RLI increased approximately ten percent to 9.0 years from 8.2 years in 2010. Our 2P RLI increased to 12.0 years at year-end 2011, an eight percent increase from the year-end 2010 figure of 11.1 years, mainly due to reserve growth from our ongoing development efforts.
| Reserve Life Index (years) | 2011 | 2010 | 2009 | 2008 |
| Proved Producing | 7.6 | 7.2 | 7.3 | 7.0 |
| Total Proved | 9.0 | 8.2 | 8.3 | 8.0 |
| Total Proved plus Probable | 12.0 | 11.1 | 10.6 | 10.6 |
RLI refers to the number of years determined by dividing the company interest reserves by the next year's forecast company interest production from the GLJ report for the corresponding reserve category.
Finding, Development and Acquisition Costs
During 2011, we spent $603 million, net of drilling credits, on development and optimization activities, which added 41.0 MMboe of proved and 39.3 MMboe of 2P reserves including revisions. The largest 2P additions were a result of drilling extensions in the Swan Hills, Olds and Groundbirch areas and enhanced recovery implementation at East Bodo.
In total, we participated in drilling 241 gross wells (123 net wells) during 2011 with a 99 percent success rate.
Our 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. Future development costs reflect 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.
| 2009 - 2011 | ||||||||
| 2011 | 2010 | Weighted Average | ||||||
| Proved plus | Proved plus | Proved plus | ||||||
| Proved | Probable | Proved | Probable | Proved | Probable | |||
| FD&A Costs Excluding Future Development Capital | ||||||||
| Exploration and Development Capital Expenditures - $MM | 603.4 | 603.4 | 329.5 | 329.5 | 1,135.1 | 1,135.1 | ||
| Exploration and Development Reserve Additions including Revisions - MMboe | 41.0 | 39.3 | 20.5 | 27.1 | 72.8 | 69.0 | ||
| Finding and Development Cost - $/boe | 14.70 | 15.34 | 16.07 | 12.15 | 15.58 | 16.44 | ||
| F&D Recycle Ratio, $/$ | 1.94 | 1.85 | 1.68 | 2.22 | 1.74 | 1.65 | ||
| Net Acquisition Capital - $MM | (8.3 | ) | (8.3 | ) | 400.6 | 400.6 | 386.1 | 386.1 |
| Net Acquisition Reserve Additions - MMboe | (0.2 | ) | (0.3 | ) | 11.2 | 22.8 | 10.1 | 21.3 |
| Net Acquisition Cost - $/boe | 52.06 | 32.85 | 35.67 | 17.55 | 38.09 | 18.13 | ||
| Total Capital Expenditures including Net Acquisitions - $MM | 595.1 | 595.1 | 730.1 | 730.1 | 1,521.1 | 1,521.1 | ||
| Reserve Additions including Net Acquisitions - MMboe | 40.9 | 39.1 | 31.7 | 50.0 | 83.0 | 90.3 | ||
| Finding Development and Acquisition Cost - $/boe | 14.56 | 15.23 | 23.00 | 14.61 | 18.33 | 16.84 | ||
| FD&A Costs Including Future Development Capital | ||||||||
| Exploration and Development Capital Expenditures - $MM | 603.4 | 603.4 | 329.5 | 329.5 | 1,135.1 | 1,135.1 | ||
| Exploration and Development Change in FDC - $MM | 257.0 | 188.0 | 32.0 | 86.0 | 246.2 | 151.2 | ||
| Exploration and Development Capital including Change in FDC - $MM | 860.4 | 791.4 | 361.5 | 415.5 | 1,381.3 | 1,286.3 | ||
| Exploration and Development Reserve Additions including Revisions - MMboe | 41.0 | 39.3 | 20.5 | 27.1 | 72.8 | 69.0 | ||
| Finding and Development Cost - $/boe | 20.96 | 20.12 | 17.63 | 15.32 | 18.96 | 18.63 | ||
| F&D Recycle Ratio, $/$ | 1.36 | 1.41 | 1.53 | 1.76 | 1.43 | 1.46 | ||
| Net Acquisition Capital - $MM | (8.3 | ) | (8.3 | ) | 400.6 | 400.6 | 386.1 | 386.1 |
| Net Acquisition FDC - $MM | 0.0 | 0.0 | 34.0 | 106.0 | 34.8 | 106.8 | ||
| Net Acquisition Capital including FDC - $MM | (8.3 | ) | (8.3 | ) | 434.6 | 506.6 | 420.9 | 492.9 |
| Net Acquisition Reserve Additions - MMboe | (0.2 | ) | (0.3 | ) | 11.2 | 22.8 | 10.1 | 21.3 |
| Net Acquisition Cost - $/boe | 52.06 | 32.85 | 38.69 | 22.19 | 41.53 | 23.14 | ||
| Total Capital Expenditures including Net Acquisitions - $MM | 595.1 | 595.1 | 730.1 | 730.1 | 1,521.1 | 1,521.1 | ||
| Total Change in FDC - $MM | 257.0 | 188.0 | 66.0 | 192.0 | 281.0 | 258.0 | ||
| Total Capital including Change in FDC - $MM | 852.1 | 783.1 | 796.1 | 922.1 | 1,802.1 | 1,779.1 | ||
| Reserve Additions including Net Acquisitions - MMboe | 40.9 | 39.1 | 31.7 | 50.0 | 83.0 | 90.3 | ||
| Finding Development and Acquisition Cost including FDC - $/boe | 20.84 | 20.04 | 25.08 | 18.46 | 21.72 | 19.69 | ||
| 2009 - 2011 | ||||||||
| 2011 | 2010 | Weighted Average | ||||||
| Operating Netback ($/boe) (1) | 28.45 | 26.92 | 27.12 | |||||
(1) The operating netbacks are equal to sales revenue plus other income less royalties, operating expenses and transportation costs. Please see Pengrowth's 2011 year-end Management Discussion & Analysis and Annual Information Form (AIF) dated February 28, 2012 for further description.
(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, 2012 forecast pricing and costs:
| Revenue | Revenue | ||||||||||||
| Operating | Development | Abandonment | Before | Income | After | ||||||||
| ($millions) | Revenue | Royalties | Costs | Costs | Costs (1) | Income Tax | Tax (2) | Income Tax | |||||
| Proved Producing | 12,977 | (2,499 | ) | (4,480 | ) | (274 | ) | (234 | ) | 5,489 | (585 | ) | 4,904 |
| Proved Developed Non-Prouducing | 544 | (115 | ) | (146 | ) | (37 | ) | (4 | ) | 243 | (59 | ) | 184 |
| Proved Undeveloped | 3,020 | (571 | ) | (731 | ) | (548 | ) | (14 | ) | 1,155 | (292 | ) | 863 |
| Total Proved | 16,542 | (3,185 | ) | (5,358 | ) | (860 | ) | (252 | ) | 6,886 | (929 | ) | 5,957 |
| Total Probable | 7,305 | (1,500 | ) | (2,067 | ) | (407 | ) | (31 | ) | 3,300 | (776 | ) | 2,524 |
| Total Proved Plus Probable | 23,847 | (4,685 | ) | (7,425 | ) | (1,267 | ) | (284 | ) | 10,186 | (1705 | ) | 8,481 |
(1) Includes GLJ's estimate of well abandonment costs and abandonment of 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.
Tax Pools
Our tax pools totaled approximately $3.0 billion as at December 31, 2011. The table below provides an estimate of tax pools by category as at December 31, 2011. These estimates are based upon forecasts prepared internally and have not been verified by any provincial or federal taxing authority. We do not anticipate being subject to any cash income taxes prior to 2016.
| ($ millions) | |
| Tax Pools | |
| COGPE | 1,215 |
| CDE | 503 |
| UCC | 632 |
| CEE | 17 |
| Other (Injectants, etc.) | 587 |
| Total Tax Pools | 2,954 |
Core Focus Areas
Greater Swan Hills Area
The Swan Hills area in northern Alberta is a Beaverhill Lake carbonate reservoir that contains 42º API light oil and liquids-rich gas (150-180 bbls of liquids/MMcf) in which we have an extensive land position covering approximately 251 net sections. Pengrowth's Swan Hills area production averaged 19,669 boepd in 2011 (85 percent crude oil and liquids and 15 percent natural gas), a production level that has grown by five percent since 2010. The oil and liquids content produced in this area has increased from 82 percent in 2010 to a current 85 percent, a trend we see continuing as we continue to target light oil, low risk development drilling and production optimization through waterflood enhancement and high volume lift strategies currently in progress.
In 2011, our Swan Hills area operating netback increased to $41.55 per boe from $33.99 per boe in 2010. 2P F&D costs in the Swan Hills area, excluding the change in FDC, averaged $19.77 per boe in 2011, yielding a premium recycle ratio of 2.1 times. Including the change in FDC, the 2011 2P F&D costs increased to $30.63 per boe. In 2011, we added 14.3 MMboe of reserves at Swan Hills, representing a reserve replacement of 199 percent, to bring total area 2P reserves at December 31, 2011 to 92.6 MMboe.
During 2011, significant success was realized utilizing horizontal drilling and multi-stage acid fracturing technology in the tighter platform and reef margin, with additional development opportunities being identified for 2012.
We plan to spend $255 million at Swan Hills in 2012 on budgeted activities that will focus on the development of oil and liquids-rich gas plays in four key areas: Carson Creek, the Judy Creek A and Judy Creek B pools, and Virginia Hills. We expect to drill 37 gross (34 net) wells in the area in 2012. At Carson Creek, we will continue with the development of our reef gas condensate play which has been a key driver of development activities for us since 2009. Production from this play is liquids-rich gas, with approximately 150 to 180 bbls of liquids/MMcf of gas. At Judy Creek, we will continue to exploit numerous development opportunities in the Judy Creek A and B pools, including new drills, re-entries, re-completions, workovers and ongoing miscible flood expansion. The remainder of our activity will focus on expanding our operations within the Swan Hills trend by exploiting development opportunities identified at Virginia Hills, where we currently hold 17 net sections of land.
The greater Swan Hills area provides significant near and long-term growth opportunities with continued development drilling, initiation of waterfloods and expansion of our infrastructure.
Lindbergh (SAGD)
The Lindbergh SAGD project is a key component of our growth strategy with the potential to increase oil and liquids production by up to 30,000 boepd, and reserves by up to 200 MMboe over the next four years, based on the contingent resource assessment. The Lindbergh property, located in the Cold Lake area, is 100 percent owned and operated by Pengrowth. At December 31, 2011, the Lindbergh lease had economic best estimate contingent resources of 296 million barrels of bitumen in the Lloydminster formation, compared to 193 million barrels of bitumen at December 31, 2010 (more information on the contingent resource assessment is provided in our AIF). This 11°API oil has favorable viscosity characteristics and is in a clean, continuous, high permeability reservoir that is expected to provide us with the potential to develop a significant commercial project of low cost, low decline, stable oil production, with a 25 year reserve life.
We began steam injection in early February 2012 in a two well pair SAGD pilot at Lindbergh and anticipate sanctioning the first commercial phase in the second quarter of 2013, pending favorable pilot performance and regulatory approvals. Environmental Protection and Enhancement Act (EPEA), Energy Resources Conservation Board (ERCB) and Alberta Environment approvals of this phase are expected by the second quarter of 2013, and first steam is targeted for the fourth quarter of 2014. This initial commercial phase is expected to produce up to 12,500 barrels of oil per day (bopd).
We will monitor and analyze SAGD pilot results over the next several months with the objective of having GLJ provide a material reserves update late in the third quarter.
Regulatory approval for the 17,500 bopd second commercial phase at Lindbergh is targeted for early 2015, with construction anticipated to commence in the second quarter of 2015. Production ramp-up is expected to start in early 2016, with full production achieved by 2017. The second commercial phase is projected to increase production to approximately 30,000 bopd.
Olds
In the Olds area, throughout 2011 we continued with the liquids-rich Elkton gas program, drilling three wells and tying-in a fourth well drilled late in 2010. These four wells had average 30 day initial production (IP) rates of 480 boepd, consisting of 2.2 MMcf per day (MMcfpd) of gas and 110 bbl per day (bblpd) of NGL. The positive results from the Elkton liquids-rich gas wells have provided additional drilling locations for 2012. A new liquids-rich gas play concept was tested in the third quarter with the drilling and completion of a Mannville gas well. The well was tied-in early in the fourth quarter and had a 30 day IP rate in excess of 500 boepd, consisting of approximately 1.9 MMcfpd of gas and 190 bblpd of NGL.
Reserves Classification
Reserves 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 National Instrument 51-101 (NI 51-101) Standards of Disclosure for Oil and gas Activities and the Canadian Oil and Gas Evaluation Handbook (COGEH). In addition to the information disclosed in this news release more detailed information is included in our AIF.
Our AIF dated February 28, 2012 can be accessed immediately on our 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.
Independent Reserves Evaluation
GLJ conducted an independent evaluation of reserves and contingent resources effective December 31, 2011 and prepared in accordance with the definitions, standards and procedures contained in COGEH and NI 51-101.
About Pengrowth:
Pengrowth Energy Corporation is a dividend-paying, intermediate Canadian producer of oil and natural gas, headquartered in Calgary, Alberta. Pengrowth's focus is on the development of conventional and unconventional resource-style plays in the Western Canadian Sedimentary Basin. Pengrowth's projects include the Swan Hills (light oil) play in north-central Alberta, the Olds (light oil/gas) play in south-central Alberta, the Lindbergh (Steam Assisted Gravity Drainage) project in east-central Alberta, the Bodo (EOR polymer) play in east-central Alberta and the Groundbirch (Montney gas) play in north-eastern British Columbia. 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 W. Evans, President and Chief Executive Officer
Advisory Regarding Reserves 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 royalties and using GLJ's December 31, 2011 forecast prices and costs as disclosed herein. Numbers presented may not add due to rounding.
Caution Regarding Engineering Terms
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 NGL 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 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of crude oil as compared to the current price of natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
The estimated values of future net revenue disclosed in this press release do not represent fair market value.
In addition, Pengrowth uses the following frequently-recurring industry terms in this press release: "bbls" refers to barrels, "Mbbls" refers to a thousand barrels, "MMbbls" refers to a million barrels, "Mboe" refers to a thousand barrels of oil equivalent, "MMboe" refers to a million barrels of oil equivalent, "Mcf" refers to thousand cubic feet, "MMcf" refers to million cubic feet, "Bcf" refers to billion cubic feet.
Caution Regarding Well Test Results
This news release makes references to well test results for certain properties. These results are not necessarily representative of long-term well performance or ultimate recoveries and are subject to various performance factors including geological formation, duration of test, pressure and production declines. Some wells will experience immediate and significant declines in production.
Contingent Resource Assessments
Contingent resources are those quantities of petroleum estimated 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. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Contingent resources are further classified in accordance with the level of certainty associated with the estimates. Contingent resources do not constitute, and should not be confused with, reserves. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.
The accuracy of resource estimates is, in part, a function of the quality and quantity of available data and of engineering and geological interpretation and judgment. These resource volumes are classified as a resource rather than a reserve because they are contingent upon further reservoir studies, delineation drilling and facility design, preparation of firm development plans, regulatory application approval and company approvals. The size of the resource estimate could be positively impacted, potentially in a material amount, if additional delineation wells determine that the aerial extent, reservoir quality and/or the thickness of the reservoir is larger than what is currently estimated based on the interpretation of seismic and well control. The size of the resource estimate could be negatively impacted, potentially in a material amount, if additional delineation wells determine that the aerial extent, reservoir quality and/or the thickness of the reservoir are less than what is currently estimated based on the interpretation of the seismic and well control.
A best estimate is the estimate of the quantity of resource that will be recovered from the accumulation, which under probabilistic methodology reflects a fifty 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 ninety 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 ten percent confidence level.
Caution Regarding Forward Looking Information
This press release contains forward-looking statements within the meaning of securities laws, including the "safe harbour" provisions of 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. In particular, forward-looking statements in this press release include, but are not limited to, statements with respect to; 2012 production and product mix expectations, reserves, expected capital program and focus and allocation of capital expenditures, drilling and completion plans, reserve life indices, operating expenses, operating netbacks, royalty rates, net present value of future net revenue from reserves, forecast commodity prices and costs, exchange rates, the impact of contracts for commodities, future development costs, development plans and programs, tax horizon, future income taxes, abandonment and reclamation costs, tax pools, the possibility of receiving a reserves update and our Lindbergh SAGD development plans and timing and the results therefrom, including production and reserve additions. Statements relating to reserves and resources are 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 proved in the future.
Forward-looking statements and information contained in this press release are based on Pengrowth's current beliefs as well as assumptions made by, and information currently available to, Pengrowth concerning general economic and financial market conditions; anticipated financial performance; business prospects; strategies; regulatory developments; including in respect of taxation; royalty rates and environmental protection; future capital expenditures and the timing thereof; future oil and natural gas commodity prices and differentials between light, medium and heavy oil prices; future oil and natural gas production levels; future exchange rates and interest rates; the proceeds of anticipated divestitures; the amount of future cash dividends paid by Pengrowth; the cost of expanding our property holdings; our ability to obtain labour and equipment in a timely manner to carry out development activities; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition; our ability to obtain financing on acceptable terms and our ability to add production and reserves through our development and exploration activities. 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, the forward-looking statements included in this press release 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: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve and resource estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth's ability to replace and expand oil and gas 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; inadequate insurance coverage; changes in environmental or other legislation applicable to our operations, and our ability to comply with current and future environmental and other laws and regulations; actions by governmental or regulatory authorities including changes in royalty structures and programs and income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; our ability to access external sources of debt and equity capital, various risks associated with our Lindbergh SAGD project, and the implementation of greenhouse gas emissions legislation. Further information regarding these factors may be found under the heading "Risk Factors" in our most recent Annual Information Form under the heading "Business Risks" in our most recent year-end Management's Discussion and Analysis and in our most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases. Copies of our Canadian public filings are available on SEDAR at www.sedar.com. Our U.S. public filings, including our most recent annual report form 40-F as supplemented by our filings on form 6-K, are available at www.sec.gov.edgar.shtml.
Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions with respect to Pengrowth, 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 we do 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 law.
The forward-looking statements contained in this press release are expressly qualified by this cautionary statement.
Additional Information – Supplemental Non-IFRS Measures
In addition to providing measures prepared in accordance with International Financial Reporting Standards (IFRS), Pengrowth presents a supplemental non-IFRS measure, operating netbacks. This measure does not have any standardized meaning prescribed by IFRS and therefore is unlikely to be comparable to similar measures presented by other companies. This supplemental non-IFRS measure is provided to assist readers in determining Pengrowth's ability to generate cash from operations. Pengrowth believes this measure is useful in assessing operating performance and liquidity of Pengrowth's ongoing business on an overall basis.
This measure should be considered in addition to, and not as a substitute for other measures of financial performance and liquidity reported in accordance with IFRS.
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.
Contact Information:
Investor Relations
(403) 233-0224 or Toll Free: 1-888-744-1111
investorrelations@pengrowth.com
www.pengrowth.com