Pengrowth Energy Corporation
TSX : PGF
NYSE : PGH

Pengrowth Energy Corporation

February 26, 2015 17:05 ET

Pengrowth Delivers Strong 2014 Operational Results and Significant Reserves Growth

CALGARY, ALBERTA--(Marketwired - Feb. 26, 2015) - Pengrowth Energy Corporation (TSX:PGF)(NYSE:PGH) is pleased to announce its financial and operating results for the fourth quarter and the full year 2014, as well as 2014 year-end reserve results.

Pengrowth had another strong year in 2014, delivering on its commitments, exceeding production guidance, getting Lindbergh steaming and adding to its drilling inventory in the liquids-rich Montney fairway. As commodity prices declined, Pengrowth announced extensive and proactive measures for 2015, designed to ensure the company's financial health and sustainability in the current low commodity price environment. In addition to our extensive hedging program, these new initiatives included a significantly reduced capital program, the deferral of Lindbergh Phase II by at least one year and a reduced dividend payout.

2014 Operational, Financial and Reserves Highlights:

  • Pengrowth achieved fourth quarter and full year average production of 71,802 barrels of oil equivalent (boe) per day and 73,288 boe per day, respectively. Full year 2014 average production exceeded the upper end of guidance as strong production performance from Pengrowth's Cardium development program more than offset minor asset dispositions.

  • Delivered on time construction, commissioning and first steam at the first commercial phase of the Lindbergh thermal project.

  • Added to low cost Montney development inventory with the acquisition of 32.6 gross/net sections of prospective liquids-rich lands adjacent to existing lands at Bernadet in north eastern British Columbia for $123.6 million in the fourth quarter.

  • Fourth quarter funds flow from operations was $115.8 million ($0.22 per share) and full year funds flow from operations was $505.7 million ($0.96 per share). Fourth quarter funds flow included realized hedging gains of $21.7 million.

  • As at December 31, 2014, the value of Pengrowth's unrealized foreign exchange, power and commodity price hedges was $469 million.

  • A non-cash, after-tax impairment charge of approximately $858 million was recorded on mature assets in the fourth quarter, resulting in a full year 2014 adjusted net loss of $879.0 million ($1.67 per share). Declining commodity prices coupled with a reduction in the price forecast for oil and natural gas were the main reasons for the impairment.

  • Year-end 2014 estimated Net Asset Value (NAV) per share of $7.32, remained relatively unchanged compared to year-end 2013 estimate of $7.52 per share.

  • Pengrowth replaced 399 percent of 2014 total production, with 106.7 MMboe of Proved plus Probable (2P) reserve additions in 2014, net of dispositions.

  • 2014 Finding and Development (F&D) costs of $22.33 per boe including changes in Future Development Costs (FDC) for 2P reserves.

  • Best estimate contingent resources at Groundbirch increased by 87 percent to 634 billion cubic feet (Bcf) and best estimate contingent resources at Lindbergh were approximately 101 MMbbl at December 31, 2014. In aggregate, the best estimate contingent resources for Groundbirch and Lindbergh were approximately 206 MMboe.

Derek Evans, President and Chief Executive Officer of Pengrowth said, "We are extremely pleased with our 2014 operational results. We exceeded the top end of production guidance driven by superior execution costs and production rates in Pengrowth's conventional assets. Lindbergh was delivered on time with first steam in December 2014 and we added to our low cost Montney drilling inventory with a liquids-rich land acquisition in the fourth quarter. As commodity prices declined, we significantly reduced our 2015 capital program, deferred Lindbergh Phase II development capital and reduced the dividend by 50 percent. We moved quickly and decisively to ensure the financial health and sustainability of Pengrowth. With cash flow stability provided by our hedge book in 2015 and 2016, executing on these measures will help ensure that Pengrowth emerges as a stronger company when commodity prices strengthen."

Summary of Financial & Operating Results

Three months ended Twelve months ended
(monetary amounts in millions except per boe and per share amounts) Dec 31, 2014 Dec 31, 2013 % Change (2) Dec 31, 2014 Dec 31, 2013 % Change
PRODUCTION
Average daily production (boe/d) 71,802 77,371 (7 ) 73,288 84,527 (13 )
FINANCIAL
Funds flow from operations (1) $ 115.8 $ 105.9 9 $ 505.7 $ 560.9 (10 )
Funds flow from operations per share (1) $ 0.22 $ 0.20 10 $ 0.96 $ 1.08 (11 )
Oil and gas sales $ 291.5 $ 343.7 (15 ) $ 1,496.9 $ 1,593.4 (6 )
Oil and gas sales per boe $ 44.13 $ 48.29 (9 ) $ 55.96 $ 51.64 8
Realized commodity risk management gains (losses) $ 21.7 $ (15.7 ) (238 ) $ (96.1 ) $ (55.0 ) 75
Realized commodity risk management gains (losses) per boe $ 3.29 $ (2.21 ) (249 ) $ (3.60 ) $ (1.78 ) 102
Operating expenses $ 94.5 $ 109.2 (13 ) $ 415.4 $ 482.5 (14 )
Operating expenses per boe $ 14.31 $ 15.34 (7 ) $ 15.53 $ 15.64 (1 )
Royalty expenses $ 51.2 $ 62.8 (18 ) $ 268.6 $ 275.1 (2 )
Royalty expenses per boe $ 7.75 $ 8.82 (12 ) $ 10.04 $ 8.92 13
Royalty expenses as a percent of sales 17.6 % 18.3 % 17.9 % 17.3 %
Operating netback per boe (1) $ 24.04 $ 20.82 15 $ 25.64 $ 24.35 5
Cash G&A expenses (1) $ 21.2 $ 21.7 (2 ) $ 84.3 $ 87.8 (4 )
Cash G&A expenses per boe (1) $ 3.21 $ 3.05 5 $ 3.15 $ 2.85 11
Capital expenditures $ 258.8 $ 239.7 8 $ 904.0 $ 695.8 30
Capital expenditures per share $ 0.49 $ 0.46 7 $ 1.71 $ 1.34 28
Net cash acquisitions (dispositions) $ (19.8 ) $ (29.2 ) (32 ) $ (67.5 ) $ (977.7 ) (93 )
Net cash acquisitions (dispositions) per share $ (0.04 ) $ (0.06 ) (33 ) $ (0.13 ) $ (1.89 ) (93 )
Dividends paid $ 63.8 $ 62.4 2 $ 253.2 $ 248.1 2
Dividends paid per share $ 0.12 $ 0.12 - $ 0.48 $ 0.48 -
Number of shares outstanding at period end (000's) 533,438 522,031 2 533,438 522,031 2
Weighted average number of shares outstanding (000's) 531,654 520,910 2 527,851 517,365 2
STATEMENT OF INCOME (LOSS)
Adjusted net income (loss) (1) (2) $ (854.8 ) $ (37.3 ) $ (879.0 ) $ (183.8 ) 378
Net income (loss) $ (506.0 ) $ (91.1 ) 455 $ (578.8 ) $ (316.9 ) 83
Net income (loss) per share $ (0.95 ) $ (0.17 ) 459 $ (1.10 ) $ (0.61 ) 80
CASH AND CASH EQUIVALENTS $ - $ 448.5 (100 ) $ - $ 448.5 (100 )
DEBT
Senior debt (3) $ 1,722.0 $ 1,412.7 22
Convertible debentures $ 137.2 $ 236.0 (42 )
Total debt before working capital $ 1,859.2 $ 1,648.7 13
Total debt including working capital $ 1,836.5 $ 1,469.4 25
CONTRIBUTION BASED ON OPERATING NETBACKS (1)
Light oil 50 % 57 % 55 % 65 %
Heavy oil 17 % 16 % 17 % 15 %
Natural gas liquids 11 % 18 % 11 % 12 %
Natural gas 22 % 9 % 17 % 8 %
PROVED PLUS PROBABLE RESERVES
Light oil (Mbbls) 91,695 103,473 (11 )
Heavy oil (Mbbls) 272,610 172,761 58
Natural gas liquids (Mbbls) 34,261 35,091 (2 )
Natural gas (Bcf) 953 996 (4 )
Total oil equivalent (Mboe) 557,350 477,385 17
CAPITAL PERFORMANCE(1)
Finding & Development Cost ("F&D") per boe (4) $ 22.33 $ 21.96 2
Recycle ratio (5) 1.1 1.1 -
(1) See disclosures at end of release for definitions of additional GAAP, Non-GAAP Measures and Operational Measures.
(2) Percentage changes in excess of 500 are excluded.
(3) Debt includes the current and long term portions.
(4) Includes changes in Future Development Costs (FDC) and based on proved plus probable reserves.
(5) Recycle ratio is calculated as operating netback per boe divided by F&D costs per boe based on proved plus probable reserves.

Production

Pengrowth's fourth quarter average daily production of 71,802 boe per day decreased 1 percent compared to the third quarter of 2014, due largely to minor property dispositions which reduced volumes by approximately 1,400 boe per day in the fourth quarter. Offsetting this was increased Sable Island natural gas production, following the completion of maintenance work in the third quarter of 2014 and strong performance from the two well Groundbirch development program.

Full year 2014 average production of 73,288 boe per day exceeded guidance of 71,000 to 73,000 boe per day despite the asset dispositions. Compared to 2013 full year average production of 84,527 boe per day, full year 2014 production decreased 13 percent due to significant property dispositions in late 2013 and dispositions in 2014, partly offset by production additions from the Cardium development program. Successful drilling at Lochend and Garrington in the Cardium formation and at Groundbirch in the Montney, underscores the efficiency and strength of Pengrowth's conventional development program.

Capital Expenditures

Fourth quarter capital expenditures were $258.8 million, with approximately 31 percent invested at Lindbergh and 21 percent invested on conventional operations. The remaining 48 percent of fourth quarter capital expenditures were used for the acquisition of 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in north eastern British Columbia.

Full year 2014 capital spending amounted to $904.0 million, of which, approximately 49 percent was invested at Lindbergh, 37 percent invested on conventional operations and 14 percent invested in the Bernadet land acquisition.

Lindbergh

Lindbergh, Pengrowth's 100 percent owned and operated thermal project, is located in the Cold Lake area of eastern Alberta. The project offers Pengrowth the potential to ultimately develop annual bitumen production of 40,000 to 50,000 bbl per day, starting with the initial 12,500 bbl per day commercial phase coming on-stream in 2015. Lindbergh's robust economics make it a strong, viable project even in the current low commodity price environment.

During the fourth quarter 2014, $80.4 million was invested at Lindbergh, bringing the full year 2014 spending to $442.3 million. Construction and commissioning of the initial 12,500 bbl per day commercial phase of Lindbergh was completed on time with steaming operations commencing in December 2014. Steam circulation on the 20 well pairs is following the same time line established for the pilot well pairs. Operations have commenced on all three well pads and production is expected to build through 2015 as downhole pumps are installed. In addition to production from the pilot facility, production rates from the commercial project at well pad D03 reached approximately 1,800 bbl per day during the week of February 21 through 25, 2015. The two additional well pads are continuing through initial phases of steam circulation.

The Lindbergh pilot delivered another strong year of results that demonstrated better than expected steam/oil and diluent blending ratios and stronger than expected production performance. Operations at the pilot project continued to show strong results during the fourth quarter of 2014 with combined field production from the two well pairs averaging 1,689 bbl per day. The average Instantaneous Steam Oil Ratio (ISOR) for the fourth quarter of 2014 was 2.5. Since steaming commenced in February 2012, cumulative production from the two well pairs exceeded 1.6 million bbls by December 31, 2014 with a Cumulative Steam Oil Ratio (CSOR) of 2.1.

Conventional Oil and Gas

Pengrowth's significant conventional oil and gas portfolio includes a large, contiguous land base in the Greater Olds/Garrington area, encompassing over 500 gross (250 net) sections of land, with opportunities in the Cardium, Viking and Mannville sands as well as in the Mississippian carbonate section. The existing, extensive gathering and processing infrastructure provides an efficient platform for continued development in this area. Pengrowth also controls large light oil accumulations in the Swan Hills area of northern Alberta providing low production decline rates and strong cash flow.

Development during the fourth quarter continued in the Greater Olds/Garrington area with an additional seven (3.2 net) wells drilled in the Cardium and an additional two (0.5 net) wells drilled in the Glauconite formation, all 100 percent successful. Two of the new Cardium wells are on stream and two others have been tested, with initial test data and early production results indicating performance that meets or exceeds type curve expectations. Pengrowth's fourth quarter 2014 development program also included three (0.8 net) wells in the Slave Point formation at Sawn Lake and one (1.0 net) injection well at Judy Creek supporting incremental production and reserves in the miscible flood. Pengrowth also completed and tied in two Groundbirch Montney horizontal wells in the fourth quarter of 2014 completed with high intensity multi-stage hydraulic fracturing technology. The initial production results from the two Groundbirch wells indicates performance that significantly exceeds Pengrowth's historic Groundbirch production results.

Pengrowth acquired 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in north eastern British Columbia at the November 5, 2014 Crown land sale. This acquisition extends Pengrowth's legacy position in the Bernadet area of four gross/net sections and is expected to provide significant scalable, low risk development drilling inventory in addition to existing Montney inventory at Groundbirch. With the addition of the Bernadet lands, Pengrowth is now well positioned with a focused multi-year conventional drilling inventory of light oil and liquids-rich natural gas prospects that complement our thermal opportunities.

Operating Expenses

Fourth quarter 2014 operating expenses were $94.5 million ($14.31 per boe) and represented a decrease of $7.9 million or eight percent compared to the third quarter 2014 operating expense of $102.4 million ($15.36 per boe). The improvement in expenses was primarily due to lower power and turnaround costs combined with lower costs resulting from the minor asset sales during the third quarter of 2014. On a per boe basis, fourth quarter operating expenses decreased $1.05 per boe as a result of the lower expenses, as mentioned above.

Full year 2014 operating expenses were $415.4 million ($15.53 per boe), compared to full year 2013 expenses of $482.5 million ($15.64 per boe). 2014 operating expenses decreased $67.1 million or 14 percent due to the absence of operating expenses from properties divested throughout 2013 and 2014 as well as lower power costs, partly offset by increased turnaround costs in 2014. On a per boe basis, 2014 operating expenses decreased $0.11 per boe compared to 2013 driven by lower costs offset by reduced production resulting from the 2013 and 2014 dispositions.

General and Administrative Expenses

Cash general and administrative (G&A) expenses in the fourth quarter 2014 were $21.2 million ($3.21 per boe) compared to $20.6 million ($3.09 per boe) in the third quarter 2014. Fees associated with reporting of the company's year-end reserves were the main reason for the increase in costs. On a per boe basis, cash G&A expenses increased $0.12 per boe compared to the third quarter due to the increase in costs as discussed above.

Full year 2014 cash G&A expenses of $84.3 million ($3.15 per boe) were $3.5 million lower compared to 2013 expenses of $87.8 million ($2.85 per boe) due to staffing decreases associated with the 2013 dispositions as well as lower office rent. On a per boe basis, 2014 cash G&A expenses increased $0.30 per boe due to lower production volumes partly offset by lower expenses, as discussed above.

Funds Flow from Operations

Fourth quarter 2014 funds flow from operations was $115.8 million ($0.22 per share) compared to $129.0 million ($0.24 per share) in the third quarter 2014. The 10 percent decrease in funds flow from operations compared to the third quarter 2014 was primarily due to the absence of volumes associated with minor property dispositions, temporary solution gas restrictions in the Swan Hills area and a decline in commodity prices. Offsetting the impact of lower commodity prices were realized commodity risk management gains, and lower royalties and operating expenses.

Full year 2014 funds flow from operations of $505.7 million ($0.96 per share) decreased 10 percent compared to 2013 funds flow of $560.9 million ($1.08 per share). The decrease in funds flow from operations was due to lower volumes resulting from the 2013 and 2014 property dispositions, which were mostly offset by an increase in natural gas prices and lower operating and interest expenses year over year.

Adjusted Net Income (Loss)

Pengrowth recorded an adjusted net loss of $854.8 million ($1.61 per share) in the fourth quarter of 2014 and $879.0 million ($1.67 per share) for the full year, mainly due to a non-cash impairment charge of $994.6 million (approximately $858 million after-tax). As a result of the significant downturn in the outlook for oil and natural gas prices, Pengrowth wrote down the book value of Property, Plant and Equipment by $486.3 million, reduced the amount of recorded goodwill by $451.3 million and wrote down $57.0 million of Exploration and Evaluation assets for the period ended December 31, 2014. These non-cash charges did not affect the company's cash flows. Additional details regarding the impairment charges are available in the Management's Discussion and Analysis accompanying Pengrowth's 2014 year-end consolidated financial statements.

Summary of Reserves Results

  • Pengrowth replaced 399 percent of 2014 total production, with 106.7 MMboe of Proved plus Probable (2P) reserve additions in 2014, net of dispositions.

  • 2014 total 2P reserves increased 17 percent to approximately 557.4 MMboe compared to 477.4 MMboe at year-end 2013. Total proved reserves (1P) at 2014 year-end, increased one percent to approximately 310.1 MMboe from 307.0 MMboe at year-end 2013.

  • 2P reserve life index (RLI) increased to 19.8 years at year-end 2014, a 14 percent increase from the year-end 2013 RLI of 17.4 years, due primarily to increased 2P reserves at Lindbergh.

  • 2014 Finding and Development (F&D) costs were $22.33 per boe including changes in Future Development Costs (FDC) for 2P reserves. The 2014 F&D costs, excluding changes to FDC, were $8.03 per boe for 2P reserves.

  • Pengrowth's three year weighted average Finding, Development and Acquisition (FD&A) and F&D costs for 2P reserves were $20.09 per boe and $20.22 per boe, respectively, including FDC ($8.42 per boe and $7.30 per boe, respectively, excluding FDC).

Pengrowth's reserves and present values at year-end 2014 were based on an independent engineering evaluation conducted by GLJ Petroleum Consultants Ltd. (GLJ), effective December 31, 2014, in their report dated February 25, 2015, using GLJ's January 1, 2015 price forecast and prepared in accordance with National Instrument 51-101 (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (COGEH).

Table 1. Company Interest Reserves Summary*

As at December 31, 2014

Light & Medium crude oil (Mbbl) Heavy oil (Mbbl) Bitumen (Mbbl) Natural Gas
Liquids
(Mbbl)
Natural
Gas (Bcf)
Total oil equivalent (Mboe) Percent of 2P oil equivalent
Proved Producing 50,394 12,627 829 22,873 487.6 167,994 30%
Proved Developed Non-producing 800 113 25,906 575 19.1 30,576 5%
Proved Undeveloped 13,137 5,484 77,113 832 89.5 111,480 20%
Total Proved 64,331 18,224 103,848 24,279 596.2 310,051 56%
Total Probable 27,365 11,047 139,490 9,983 356.5 247,299 44%
Total Proved Plus Probable 91,695 29,272 243,338 34,261 952.7 557,350 100%

* Numbers in table may not add due to rounding

Reserves Reconciliation

Total 2P reserves increased 17 percent in 2014 based on a total net reserves addition of 106.7 MMboe, primarily due to drilling additions, positive technical revisions and acquisitions, partially offset by dispositions and reductions due to economic factors. The additional 2P reserves represented a replacement of 399 percent of 2014 production. The most significant of these additions were reserves attributed to the Lindbergh thermal project where 2P reserves increased by 101.4 MMboe in 2014 over year-end 2013 numbers.

On a 1P basis, year-end 2014 reserves increased by one percent compared to 2013. In total, 29.8 MMboe of 1P reserves were added, including revisions and net of dispositions, replacing 111 percent of 2014 production.

Table 2. Company Interest Reserves Reconciliation 2014*

Light & Medium crude oil (Mbbl) Heavy oil (Mbbl) Bitumen (Mbbl) Natural Gas Liquids (Mbbl) Natural
Gas (Bcf)
Total oil equivalent (Mboe)
Total Proved
December 31, 2013 73,293 19,312 81,727 25,342 644.1 307,016
Technical Revisions 982 1,402 (1,103) 2,345 12.6 5,724
Economic Factors (1,798) (473) - (621) (21.3) (6,433)
Drilling 2,533 397 23,839 874 35.8 33,617
Improved Recovery 35 - - 3 - 43
Acquisitions 594 4 - 108 1.0 865
Dispositions (3,559) (20) - (75) (2.3) (4,030)
Production (7,748) (2,397) (615) (3,698) (73.8) (26,750)
December 31, 2014 64,331 18,224 103,848 24,279 596.2 310,051
Total Proved Plus Probable
December 31, 2013 103,473 30,195 142,565 35,091 996.4 477,385
Technical Revisions (2,250) 932 (166) 1,626 6.3 1,199
Economic Factors (1,243) (295) - (543) (23.0) (5,908)
Drilling 3,741 927 101,554 1,809 54.0 117,029
Improved Recovery - - - 9 0.2 38
Acquisitions 907 4 - 154 1.3 1,276
Dispositions (5,184) (95) - (186) (8.7) (6,918)
Production (7,748) (2,397) (615) (3,698) (73.8) (26,750)
December 31, 2014 91,696 29,272 243,338 34,262 952.7 557,350

* Numbers in table may not add due to rounding

Table 3. Select prices from GLJ's January 1, 2015 forecast prices and inflation rates

Year WTI Crude Oil ($US/bbl) Edm Light Crude Oil ($Cdn/bbl) WCS Crude Oil ($Cdn/bbl) Natural Gas
at AECO ($Cdn/MMBtu)
Inflation Rate (%/year)
2014 (Actual) 93.06 94.77 81.62 4.52 -
2015 62.50 64.71 54.35 3.31 2.0
2016 75.00 80.00 67.20 3.77 2.0
2017 80.00 85.71 72.00 4.02 2.0
2018 85.00 91.43 76.80 4.27 2.0
2019 90.00 97.14 81.60 4.53 2.0
2020 95.00 102.86 86.40 4.78 2.0
2021 98.54 106.18 89.19 5.03 2.0
2022 100.51 108.31 90.98 5.28 2.0
2023 102.52 110.47 92.79 5.53 2.0
2024 104.57 112.67 94.65 5.71 2.0
Thereafter +2.0 %/yr +2.0 %/yr +2.0 %/yr +2.0 %/yr 2.0

Table 4. Before Income Tax Net Present Value Summary

As at December 31, 2014

Discounted at Percent of 2P
($ millions, except percentages) Undiscounted 5% 10% 15% 20% Discounted at 10%
Proved Producing 3,456 2,511 1,965 1,616 1,376 37%
Proved Developed Non-producing 839 700 598 520 458 11%
Proved Undeveloped 3,283 1,636 875 488 276 17%
Total Proved 7,578 4,846 3,438 2,624 2,109 65%
Total Probable 7,238 3,442 1,820 1,031 607 35%
Total Proved Plus Probable 14,816 8,288 5,259 3,656 2,716 100%

Net Asset Value

The following table provides a calculation of Pengrowth's estimated NAV based on the estimated future net revenues associated with Pengrowth's proved plus probable reserves.

Table 5. Net Asset Value - Before Income Tax

As at December 31, 2014

($ millions, except percentages and share numbers) Discounted at 5% Discounted at 10%
Value of Total Proved plus Probable reserves(1)
8,288

5,259
Undeveloped Land(2) 208 208
Long-term debt, including convertible debentures and working capital(3) (1,809) (1,809)
Reclamation Funds(4) 60 60
Other Assets/Liabilities (Asset Retirement Obligations, commodity contracts)(3)(5) 73 185
Net Asset Value 6,821 3,903
Shares outstanding (millions) 533 533
NAV per share ($ per share) 12.79 7.32
(1) Discounted net present value of GLJ total proved plus probable reserves.
(2) Internal undeveloped land value estimate.
(3) See 2014 Audited Consolidated Financial Statements and Notes.
(4) Pre-paid reclamation costs for Sable Offshore Energy Project, Nova Scotia and Judy Creek, Alberta.
(5) Estimated value of commodity contracts and other liabilities.

As of December 31, 2014, Pengrowth's estimated NAV, discounted at 10 percent, was $7.32 per share. The approximate three percent decrease from the 2013 year-end estimated NAV of $7.52 per share is primarily due to a lower reserve value resulting from lower commodity prices.

Finding, Development and Acquisition Costs

During 2014, excluding information technology and office expenditures, Pengrowth spent $902.5 million on development and optimization activities, which added 32.9 MMboe of 1P and 112.4 MMboe of 2P reserves including revisions, resulting in a 2P F&D cost of $22.33 per boe (including FDC). The largest 2P additions were at Lindbergh, where 2P reserves increased by 101.4 MMboe due to further delineation drilling, submitting a regulatory application to expand the SAGD project and continued superior pilot performance. Included in this capital expenditure was $123.6 million spent to acquire 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in north eastern British Columbia, which have no reserves attributed to them at this time. Excluding the Bernadet land costs, the 2P F&D cost (including FDC) decreased by $1.10 per boe to $21.23 per boe.

Pengrowth's 2014 F&D and FD&A costs are summarized below. These are determined separately for exploration and development activities, acquisition and disposition transactions, and with and without the change in 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.

Table 6. 2014 F&D and FD&A Costs


2014

2013
2012 - 2014
Weighted Average

Proved
Proved plus
Probable

Proved
Proved plus
Probable

Proved
Proved plus
Probable

FD&A Costs Excluding Future Development Cost
Exploration and Development Capital Expenditures - $ millions 902.5 902.5 692.4 692.4 2,055.9 2,055.9
Exploration and Development Reserve Additions including Revisions - MMboe 32.9 112.4 83.4 65.3 137.3 281.5
Finding and Development Cost - $/boe 27.43 8.03 8.30 10.61 14.97 7.30
F&D Recycle Ratio, $/$ 0.9 3.2 2.9 2.3 1.6 3.4
Net Acquisition (Disposition) Capital - $ millions (67.5 ) (67.5 ) (977.8 ) (977.8 ) 608.9 608.9
Net Acquisition (Disposition) Reserve Additions - MMboe (3.1 ) (5.6 ) (45.6 ) (69.0 ) 30.2 34.8
Net Acquisition Cost - $/boe 21.77 12.05 21.43 14.17 20.16 17.50
Total Capital Expenditures including Net Acquisitions (Dispositions) - $ millions 835.0 835.0 (285.3 ) (285.3 ) 2,664.8 2,664.8
Reserve Additions including Net Acquisitions (Dispositions) - MMboe 29.8 106.7 37.8 (3.7 ) 167.5 316.3
Finding Development and Acquisition Cost - $/boe1 28.02 7.82 (7.55 ) 76.66 15.91 8.42
FD&A Costs Including Future Development Cost
Exploration and Development Capital Expenditures - $ millions 902.5 902.5 692.4 692.4 2,055.9 2,055.9
Exploration and Development Change in FDC - $ millions (51.7 ) 1,607.2 1,031.7 741.2 1,084.6 3,636.4
Exploration and Development Capital including Change in FDC - $ millions 850.8 2,509.7 1,724.1 1,433.6 3,140.5 5,692.3
Exploration and Development Reserve Additions including Revisions - MMboe 32.9 112.4 83.4 65.3 137.3 281.5
Finding and Development Cost - $/boe 25.86 22.33 20.67 21.96 22.87 20.22
F&D Recycle Ratio, $/$ 1.0 1.1 1.2 1.1 1.1 1.2
Net Acquisition (Disposition) Capital -$ millions (67.5 ) (67.5 ) (977.8 ) (977.8 ) 608.9 608.9
Net Acquisition (Disposition) FDC - $ millions (5.3 ) (32.2 ) (224.7 ) (381.2 ) (0.2 ) 53.8
Net Acquisition (Disposition) Capital including Change in FDC - $ millions (72.8 ) (99.7 ) (1,202.5 ) (1,359.0 ) 608.7 662.7
Net Acquisition (Disposition) Reserve Additions - MMboe (3.1 ) (5.6 ) (45.6 ) (69.0 ) 30.2 34.8
Net Acquisition Cost - $/boe 23.48 17.80 26.36 19.70 20.16 19.04
Total Capital Expenditures including Net Acquisitions (Disposition) - $ millions 835.0 835.0 (285.3 ) (285.3 ) 2,664.8 2,664.8
Total Change in FDC - $ millions (57.0 ) 1,575.0 807.0 360.0 1,084.4 3,690.2
Total Capital including Change in FDC - $ millions 778.0 2,410.0 521.7 74.6 3,749.2 6,355.0
Reserve Additions including Net Acquisitions (Disposition) - MMboe 29.8 106.7 37.8 (3.7 ) 167.5 316.3
Finding Development and Acquisition Cost including FDC - $/boe2 26.11 22.57 13.80 (20.05 ) 22.38 20.09

2014

2013
2012 - 2014
Weighted Average
Operating Netback ($/boe) 3 25.64 24.35 24.50
(1) The negative 2013 FD&A Cost excluding FDC for Proved Reserves is due to the proceeds from dispositions exceeding capital expenditures plus acquisition costs.
(2) The negative 2013 FD&A Cost including FDC for P+P Reserves is due to the reserve decrease from dispositions exceeding the reserve additions, including revisions, from development activity and acquisitions.
(3) The operating netbacks are equal to sales revenue plus other income less royalties, operating expenses and transportation costs. Please see Pengrowth's 2014 year-end Management Discussion and Analysis (MD&A) and Annual Information Form (AIF) dated February 26, 2015 for further information.

Table 7. Total Future Net Revenue (Undiscounted)

As at December 31, 2014

($ millions) Revenue Royalties Operating Costs Development Costs Abandonment Costs1 Revenue Before Income Tax Income Tax2 Revenue After
Income Tax
Proved Producing 10,159 1,665 4,576 157 305 3,456 - 3,456
Proved Developed Non-producing 1,897 312 614 121 10 839 5 834
Proved Undeveloped 9,468 2,089 2,382 1,667 47 3,283 915 2,368
Total Proved 21,524 4,066 7,572 1,944 363 7,578 920 6,658
Total Probable 20,026 4,320 5,364 3,013 92 7,238 1,942 5,296
Total Proved Plus Probable 41,550 8,386 12,937 4,957 455 14,816 2,862 11,954
  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 2014 proved RLI decreased marginally to 11.7 years from 11.8 years in 2013. The RLI for proved plus probable reserves increased to 19.8 years at year-end 2014, a 14 percent increase from year-end 2013 RLI of 17.4 years.

Table 8. Historical Reserve Life Index

Reserve Line Index (Years) 2014 2013 2012 2011 2010
Proved Producing 7.2 7.4 7.6 7.6 7.2
Total Proved 11.7 11.8 9.2 9.0 8.2
Total Proved Plus Probable 19.8 17.4 14.7 12.0 11.1

RLI refers to the number of years determined by dividing Company Interest in a category of reserves by the next year's forecast Company Interest production for the corresponding reserve category. The reserves and next year's forecast production come from the relevant year's GLJ Report.

Reserves and Contingent Resources Classification

The following table summarizes GLJ's estimates of reserves and contingent resources, as of year-end 2014, for the Lindbergh thermal property and Groundbirch natural gas property.

Table 9. Summary of Reserves and Contingent Resources

Reserves Contingent Resources
Field Proved Proved + Probable Proved +
Probable +
Possible
Low Estimate Best Estimate High Estimate
Lindbergh (MMbbl) 103.8 243.3 316.6 50.6 100.6 149.0
Groundbirch (Bcf) 85.2 228.2 279.6 474.5 634.4 990.9

The reserves attributed to Lindbergh increased in 2014 due to ongoing reservoir delineation and the submission of the regulatory application for expansion of development of the commercial SAGD project. Contingent resources decreased as a result of significant volumes being reclassified as reserves. The contingencies which prevent the remaining contingent resources from being classified as reserves at Lindbergh include: the need for additional evaluation well drilling within the area, firm development plans beyond the initial expansion phase, high quality project design and cost estimates and commitment by Pengrowth for future development.

Contingent resources at Groundbirch in 2014 increased primarily due to production performance from the additional drilling that was carried out in 2014 coupled with offsetting development activity in the play. The Groundbirch tight gas resource is in early stage evaluation, delineation and development. Additional drilling, completion and testing data is required for planning and design purposes. The reclassification of these Contingent Resources as reserves is contingent upon creating a development plan with corporate approval and commitment to proceed within an acceptable time period.

Reserves and contingent resources included herein are stated on a Company interest basis 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) dated February 26, 2015, which is available on SEDAR at www.SEDAR.com and on EDGAR at www.sec.gov/edgar.shtml.

Financial Flexibility

Pengrowth remains committed to ensuring its financial health and flexibility during these volatile times. On January 21, 2015, the company announced several measures intended to safeguard its financial health and sustainability in 2015. These measures included a significantly reduced capital program for 2015, the deferral of the second commercial phase of Lindbergh, a continued focus on hedging and a revised dividend payout rate.

To mitigate commodity price risk and provide a measure of stability and predictability to cash flows, Pengrowth continues its active hedging strategy. At February 26, 2015, Pengrowth has approximately 26,000 bbl per day of 2015 crude oil production (75 percent of 2015 estimated oil production) hedged at Cdn $93.96 per bbl and approximately 21,000 bbl per day of 2016 crude oil production (61 percent of 2015 estimated oil production) hedged at Cdn $89.79 per bbl.

For natural gas, Pengrowth has approximately 102 million cubic feet (MMcf ) per day of 2015 natural gas production (54 percent of 2015 estimated gas production) hedged at Cdn $3.73 per Mcf and approximately 81 MMcf per day of 2016 natural gas production (43 percent of estimated 2015 gas production) hedged at Cdn $3.46 per Mcf. Pengrowth has also entered into significant natural gas hedges for 2017 and 2018 at prices in excess of AECO $3.50 per Mcf.

Details of Pengrowth's commodity risk management contracts in place as at February 26, 2015 are summarized in the table below:

Table 10. Summary of Commodity Risk Management Contracts

Volume Average Price
($Cdn)
Crude Oil (bbl per day)
2015 26,000 $93.96
2016 20,852 $89.79
Natural Gas (Mcf per day)
2015 101.8 $3.73
2016 80.5 $3.46
2017 47.9 $3.72
2018 54.5 $3.64

Following the repayment of approximately $100 million of convertible debentures that came due on December 31, 2014, Pengrowth's senior unsecured debt totaled approximately Cdn $1.72 billion. This included $191 million drawn on its $1 billion credit facility. The senior unsecured revolving credit facility has a maturity date of July 26, 2017. In addition to balancing cash inflows and outflows in 2015, Pengrowth is targeting further reductions to total debt. Pengrowth remains fully compliant with the various financial covenants that it is subject to under its long-term debt and bank facilities and does not anticipate breaching any of its financial covenants.

2015 Forecast Guidance Summary

Pengrowth's Board of Directors approved a $200 million capital budget for 2015, representing a decrease of 78 percent from its 2014 actual capital expenditures of $904.0 million. The reduced capital budget will focus on optimization and enhancement activities targeting ongoing production and does not contemplate an active drilling program. Pengrowth's 2015 capital program has been designed with an emphasis on preserving its financial health and sustainability in a low commodity price environment while paying shareholders a monthly dividend of $0.02 per share.

Previous capital spending at Lindbergh has established a low decline production base going forward, that Pengrowth expects to maintain with a lower level of capital investment through 2016, which serves to preserve the financial flexibility to take advantage of the significant growth opportunities that the company has at Lindbergh, in the Montney and in the Cardium, when commodity prices improve.

Pengrowth is maintaining spending on its asset integrity and maintenance programs in order to mitigate risk to its employees and the environment.

Pengrowth's 2015 capital budget was based on the assumption of a WTI crude oil price of US $50/bbl, an AECO natural gas price of Cdn $2.75/Mcf and a $0.85 USD/Cdn exchange rate.

The 2015 capital budget and revised dividend rate reflect a balance whereby capital expenditures and dividends are expected to be less than internally generated funds flow from operations, with any and all excess funds flow being directed toward reducing debt. There will be a strong emphasis in 2015 on reducing Pengrowth's indebtedness.

A summary of Pengrowth's 2015 operating and financial guidance is provided below:

Average daily production volume (boe per day) 73,000 to 75,000
Total capital expenditures ($ millions) 190 to 210
Royalties (% of sales)1 12 to 15
Net operating costs ($ per boe)2 15.50 to 16.50
Cash G & A expense ($ per boe)2 3.20 to 3.30
  1. Royalties are before impacts of commodity risk management activities
  2. Per boe estimates based on high and low ends of production guidance

Outlook

Pengrowth's management team and its Board of Directors have moved quickly and decisively to take steps to ensure that the financial health and sustainability of the company remains intact. These steps include substantially decreasing capital expenditures, deferring Lindbergh Phase II spending, reducing the dividend by 50 percent and significantly enhancing our focus on all aspects of capital, operating and G&A cost structures. Delivering on these measures will help ensure that Pengrowth emerges as a stronger company when commodity prices strengthen.

Pengrowth's audited Consolidated Financial Statements for the three and twelve months ended December 31, 2014 and related Management's Discussion and Analysis, as well as Pengrowth's AIF dated February 26, 2015, can be viewed on Pengrowth's website at www.pengrowth.com. They will also be available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.shtml.

Conference call:

Pengrowth will host a conference call for investors at 6:30 A.M. Mountain Time on Friday, February 27, 2015. To participate, callers may dial in via telephone or participate online in listen only mode via the audio webcast. To ensure timely participation in the teleconference, callers are encouraged to dial in 10 minutes prior to commencement of the call to register.

Dial-in numbers:

Toll free: (800) 355-4959 or Toronto local (416) 340-2216

Live listen only audio webcast: http://www.gowebcasting.com/6323

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 Cardium light oil, Lindbergh thermal and Swan Hills light oil 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

Advisories:

Currency:

All amounts are stated in Canadian dollars unless otherwise specified.

Advisory Regarding Reserves, Contingent Resources and Production Information

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, 2015 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 does 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.

Possible Reserves are those additional reserves that are less certain to be recovered than Probable Reserves. There is a ten percent probability that the quantities actually recovered will equal or exceed the sum of Proved Plus Probable plus Possible Reserves;

Probable Reserves refers to those additional reserves that are less certain to be recovered than Proved Reserves; it is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable Reserves;

Proved Developed Producing Reserves refers to those reserves expected to be recovered from completion intervals open at the time of the estimate; these reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty;

Proved Developed Reserves refers to those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production; the developed category may be subdivided into Proved Developed Producing Reserves and Developed Non-producing Reserves;

Proved Reserves refers to those reserves that can be estimated with a high degree of certainty to be recoverable; it is likely that the actual remaining quantities recovered will exceed the estimated Proved Reserves;

Total Proved Plus Probable Reserves" or "P+P" means the aggregate of Proved Reserves and Probable Reserves

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 thermal oil 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 ten percent confidence level. The Contingent Resources as disclosed herein are considered economic based on forecast prices and costs as at December 31, 2014. Additional information relating to the Contingent Resources estimate for Pengrowth's Lindbergh thermal oil 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 26, 2015, which can be accessed immediately on Pengrowth's website at www.pengrowth.com and has been filed on SEDAR at www.sedar.com and on Form 40-F on EDGAR at www.sec.gov/edgar.shtml.

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 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.

Caution Regarding Forward Looking Information:

In the interest of providing our shareholders and potential investors with information regarding us, including management's assessment of our future plans and operations, certain statements in this press release are 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 the company's financial health and sustainability in a low commodity price environment; reduced capital programs; deferral of Lindbergh Phase II; reduced dividend payout; low cost Montney drilling inventory; liquids rich potential of Bernadet acquisition; cash flow stability provided by 2015 and 2016 hedges; Pengrowth's ability to emerge as a stronger company when commodity prices strengthen; production potential of Lindbergh and the timing thereof; timing and production from the first commercial phase of Lindbergh; Lindbergh economics and viability even in a low commodity price environment; anticipated build-up of production from Lindbergh through 2015; the installation of downhole pumps at Lindbergh; expected continued development of the Greater Olds/Garrington area; expected ongoing development in the Swan Hills area with low declines and strong cash flow; scalable, low risk, multi-year development drilling inventory at Bernadet; estimated future value of commodity contracts and liabilities; estimated future production for reserve life index calculations; future contingencies impacting contingent resources; the potential re-classification of contingent resources as reserves; reduced capital program for 2015; continued focus on hedging efforts; dividend payout rate; the balancing of cash inflows and outflows; expected compliance with debt covenants; $200 million capital budget; focus of capital budget in 2015; future financial health and sustainability; expected low decline production base from Lindbergh; expected lower level of capital investment through 2016; future growth opportunities at Lindbergh, in the Montney and in the Cardium; expected spending on asset integrity and maintenance; assumptions regarding future WTI crude oil prices, AECO natural gas prices and USD/Cdn exchange rate; 2015 expected excess funds flow and the application thereof to reducing indebtedness; expected emphasis on reducing indebtedness and 2015 guidance for average daily production, total capital expenditures, royalties, net operating costs and cash G&A expense.

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 our Annual Information Form dated February 26, 2015.

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.

Additional and Non-GAAP Measures

In addition to providing measures prepared in accordance with International Financial Reporting Standards (IFRS), Pengrowth presents additional and non-GAAP measures, Adjusted Net Income (Loss), operating netbacks, adjusted payout ratio and Funds Flow from Operations. These measures do not have any standardized meaning prescribed by GAAP and therefore are unlikely to be comparable to similar measures presented by other companies.

These measures are provided, in part, to assist readers in determining Pengrowth's ability to generate cash from operations. Pengrowth believes these measures are useful in assessing operating performance and liquidity of Pengrowth's ongoing business on an overall basis.

These measures should be considered in addition to, and not as a substitute for, net income (loss), cash provided by operations and other measures of financial performance and liquidity reported in accordance with IFRS. Further information with respect to these additional and non-GAAP measures can be found in Pengrowth's most recent management's discussion and analysis.

Operational Measures

Recycle ratio is a measure of value creation for each dollar spent. This measure is calculated as operating netback per boe divided by Finding and Development (F&D) cost per boe and can also be calculated using Finding, Development & Acquisition (FD&A) cost per boe. Recycle ratio can be calculated including or excluding Future Development Costs (FDC).

Note to US Readers

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.

Current SEC reporting requirements permit, but do not require United States 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. The SEC does not permit the inclusion of estimates of contingent resources in reports filed with it by United States companies. 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 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.

Contact Information