U.S. SECURITIES AND EXCHANGE
COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F

(Amendment No. 1)



| ̈ | REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934.
|- | -------------------------------------------------------------------------------------



|x | ANNUAL REPORT PURSUANT TO SECTION 13(a) OF THE SECURITIES EXCHANGE ACT OF 1934
|- | ------------------------------------------------------------------------------



|                                             |  |                                
|-------------------------------------------- |  | -------------------------------
|For the fiscal year ended: December 31, 2011 |  | Commission File Number: 1-31253

PENGROWTH ENERGY CORPORATION

(Exact name of Registrant as specified in its charter)

Alberta, Canada

(Province or other jurisdiction of incorporation or
organization)



|                                                         |  |                                        
|-------------------------------------------------------- |  | ---------------------------------------
|1311                                                     |  | None                                   
|(Primary Standard Industrial Classification Code Number) |  | (I.R.S. Employer Identification Number)

Suite 2100, 222 Third Avenue S.W.

Calgary, Alberta Canada T2P 0B4

(403) 233-0224

(Address and telephone number of Registrants
principal executive offices)

Puglisi & Associates

850 Library Avenue, Suite 204

Newark, Delaware 19711

(302) 738-6680

(Name, address (including zip code) and telephone number (including area code)

of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act.



|                    |  |                                          
|------------------- |  | -----------------------------------------
|Title of each class |  | Name of each exchange on which registered
|Common Shares       |  | New York Stock Exchange                  

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

(Title of Class)

For Annual Reports indicate by check mark the information filed with this Form:

x  Annual information form    x  Audited annual financial statements

Indicate the number of outstanding
shares of each of the issuers classes of capital or common stock as of the close of the period covered by the annual report:

There were 360,282,162 Common Shares, of no par value, outstanding as of December 31, 2011.

Indicate by check mark whether the Registrant filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities
Exchange Act of 1934 (the Exchange Act). If Yes is marked, please indicate the filing number assigned to the Registrant in connection with such
Rule.    Yes   ̈    No  x

Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Exchange Act
during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to filing requirements for the past 90 days.    Yes  x    No   ̈

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule
405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such
files).    Yes   ̈    No   ̈

This Annual Report on Form 40-F/A shall be incorporated by reference into or as an exhibit to, as applicable, the registrants
Registration Statements on Form F-10 and F-3 (File Nos. 333-171682 and 333-171672, respectively) under the Securities Act of 1933, as amended.









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EXPLANATORY NOTE

This Amendment No. 1 to the Annual Report on Form 40-F for the fiscal year ended December 31, 2011 (this Amendment) of Pengrowth Energy Corporation (the Registrant) is being filed
for the purpose of re-filing the Registrants Managements Discussion and Analysis originally filed with the Registrants Annual Report on Form 40-F for the fiscal year ended December 31, 2011 filed with the Securities and Exchange
Commission on February 28, 2012 (the Original Filing) which omitted certain pages and is now attached hereto in its entirety as Appendix A.

Other than as expressly set forth above, this Amendment does not, and does not purport to, update or restate the information in any Item of the Original Filing or reflect any events that have occurred
after the Original Filing was filed. The filing of this Amendment shall not be deemed an admission that the Original Filing, when made, included any known, untrue statement of material fact or knowingly omitted to state a material fact necessary to
make a statement not misleading.

DOCUMENTS FILED AS PART OF THIS ANNUAL REPORT

The following document has been filed as part of this Annual Report on Form 40-F as an Appendix hereto:



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|-------- |  | -------------------------------------
|Appendix |  | Documents                            
|         | 
|A        |  | Managements Discussion and Analysis.

CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES

Certifications. See Exhibits 99.5 and 99.6 to this Annual Report on Form 40-F/A.





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UNDERTAKING

Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission
staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

CONSENT TO SERVICE OF PROCESS

Form F-X signed by the Registrant and its agent for service of process has been filed with the Commission together with Form F-10 (333-171682) in connection with its securities registered on such form.

Any changes to the name or address of the agent for service of process of the Registrant shall be communicated promptly to the Commission by
an amendment to the Form F-X referencing the file number of the Registrant.







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SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F/A and has duly caused this Annual Report to be signed on its
behalf by the undersigned, thereunto duly authorized.



|                        |  |                              |  |                                             
|----------------------- |  | ---------------------------- |  | --------------------------------------------
|Date: February 29, 2012 |  | PENGROWTH ENERGY CORPORATION
|                        |  |                             
|                        |  | By:                          |  | /s/ Derek W. Evans                          
|                        |  |                              |  | Name: (signed) Derek W. Evans               
|                        |  |                              |  | Title: President and Chief Executive Officer







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APPENDIX A

MANAGEMENTS DISCUSSION AND ANALYSIS







---

SUMMARY OF FINANCIAL & OPERATING RESULTS Certain comparative figures have changed due to International Financial Reporting Standards and to conform to current presentation.  (monetary amounts in millions, except per share amounts or as otherwise
stated)

Three months ended


Twelve months endedDec 31, 2011


Dec 31, 2010


% Change


Dec 31, 2011


Dec 31, 2010


% ChangeSTATEMENT OF (LOSS) INCOMEOil and gas sales(1)



$
389.2


$
344.9



13


$
1,453.7


$
1,368.7



6Adjusted Net Income(2)



$
22.3


$
40.7



(45
)

$
110.9


$
208.4



(47
)Net (loss) income



$
(9.0
)

$
(152.0
)


(94
)

$
84.5


$
149.8



(44
)Net (loss) income per share



$
(0.03
)

$
(0.47
)


(94
)

$
0.25


$
0.50



(50
)CASH FLOWFunds flow from operations(1)
(4)



$
171.1


$
139.9



22


$
620.0


$
626.2



(1
)Funds flow from operations per share(1) (3)



$
0.50


$
0.44



14


$
1.87


$
2.09



(11
)Net capital expenditures(5)



$
142.1


$
130.9



9


$
609.1


$
333.8



82Net capital expenditures per share(3)



$
0.41


$
0.41






$
1.83


$
1.11



65Dividends paid(3)



$
71.4


$
67.4



6


$
277.5


$
250.6



11Dividends paid per share(3)



$
0.21


$
0.21






$
0.84


$
0.84



Weighted average number of shares outstanding (000s)(3)




345,163



321,319



7



332,182



299,763



11BALANCE SHEET(6)Working capital deficiency(1)















$
(137.3
)

$
(109.2
)


26Property, plant and equipment















$
4,074.4


$
3,738.0



9Exploration and evaluation assets















$
563.8


$
511.6



10Long term debt















$
1,007.7


$
1,024.4



(2
)Shareholders equity(1)
(3)















$
3,347.3


$
3,182.3



5Shareholders equity per share(3)















$
9.29


$
9.76



(5
)Currency ($ Cdn = $1 U.S.) (closing rate at period end)















$
0.9833


$
1.0054Number of shares outstanding at period end (000s) (3)
















360,282



326,024



11AVERAGE DAILY PRODUCTIONLight oil (bbls)




22,935



21,762



5



21,455



21,743



(1
)Heavy oil (bbls)




6,448



6,673



(3
)


6,425



6,789



(5
)Natural gas liquids (bbls)




10,478



10,177



3



9,659



9,611



1Natural gas (Mcf)




220,977



218,044



1



218,601



219,302



Total production (boe)




76,691



74,953



2



73,973



74,693



(1
)Total Annual Production (Mboe)




7,056



6,896



2



27,000



27,263



(1
)AVERAGE REALIZED PRICES (after commodity risk management)Light oil (per bbl)
(1)



$
91.58


$
76.13



20


$
89.94


$
76.22



18Heavy oil (per bbl)



$
76.13


$
60.42



26


$
68.24


$
60.22



13Natural gas liquids (per bbl)



$
70.54


$
56.74



24


$
69.31


$
56.99



22Natural gas (per Mcf)



$
3.77


$
4.87



(23
)

$
4.08


$
5.00



(18
)Average realized price per boe
(1)



$
54.28


$
49.34



10


$
53.13


$
49.68



7CONTRIBUTION BASED ON OPERATING NETBACKS (2)Light oil




54%



45%







53%



45%Heavy oil




14%



12%







12%



11%Natural gas liquids




20%



16%







17%



14%Natural gas




12%



27%







18%



30%PROVED PLUS PROBABLE RESERVESLight oil (Mbbls)
















116,823



110,297



6Heavy oil (Mbbls)
















31,898



26,472



20Natural gas liquids (Mbbls)
















30,746



29,481



4Natural gas (Bcf)
















906



913



(1
)Total oil equivalent (Mboe)
















330,511



318,429



4CAPITAL PERFORMANCEFinding & Development Cost (F&D) (per boe) (7)















$
20.12


$
15.32



31Finding, Development & Acquisition Cost (FD&A) (per boe) (7)















$
20.04


$
18.46



9Recycle Ratio(1)
(8)
















1.4



1.8



(20
)  (1)
Prior periods restated to conform to presentation in the current period.  (2)
See definition under section Non-GAAP Financial Measures.  (3)
Pengrowth Energy Corporation is the entity resulting from the conversion of Pengrowth
Energy Trust. See note regarding conversion below.  (4)
See definition under section Additional GAAP Measures.  (5)
Net capital expenditures includes Drilling Royalty Credits and capitalized stock based compensation.  (6)
Balance Sheet amounts are at period end.  (7)
Includes the changes in Future Development Capital (FDC) and based on Proved plus Probable Reserves.  (8)
Recycle Ratio is calculated as operating netback per boe divided by F&D costs per boe based on Proved plus Probable Reserves. Note regarding currency: all figures contained within this report are quoted in Canadian dollars unless otherwise indicated. Note regarding oil production: references to light oil contained within this report include light and medium oil.  Note regarding corporate conversion: Pengrowth Energy Corporation is the entity resulting from the conversion of Pengrowth Energy Trust to a dividend
paying corporation effective December 31, 2010. References to shares, shareholder and dividends should be read as references to trust units, trust unitholder and
distributions respectively for periods prior to December 31, 2010.




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|PENGROWTH 2011 Summary of Financial & Operating Results |  |  | 3 


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MANAGEMENTS DISCUSSION & ANALYSIS The following Managements Discussion and Analysis (MD&A) of financial results should be read in conjunction with the audited financial statements for the year ended December 31, 2011 of Pengrowth Energy Corporation. The MD&A is based on information
available to February 28, 2012. STRUCTURE OF THE CORPORATION Pengrowth Energy Corporation (the Corporation) is a Canadian resource company that is engaged in the
production, development, exploration and acquisition of oil and natural gas assets. The Corporation was formed through a reorganization involving Pengrowth Energy Trust (the Trust), Pengrowth Corporation, its subsidiaries and the security holders of the Trust and Pengrowth Corporation pursuant to a Plan of Arrangement (the
Arrangement) under the Business Corporations Act (Alberta). On December 31, 2010 (the Date of Conversion), the Trust completed its conversion from an open-end
investment trust to a corporation through a business combination resulting in the unitholders of the Trust and the exchangeable shareholders of Pengrowth Corporation owning all the common shares of the Corporation. Unitholders of the Trust received
common shares in the Corporation on a one-for-one basis. Exchangeable shareholders of Pengrowth Corporation received 1.02308 common shares of the Corporation for each exchangeable share held. Pursuant to the Arrangement agreement, shareholders
capital was reduced by the amount of the deficit of the Trust on December 31, 2010. The management team and Board of Directors of the Corporation are comprised of the former management team and elected members of the Board of Directors of the
Trust. The Corporation effected an internal reorganization subsequent to the Date of Conversion whereby, among other things, the Trust and its
subsidiaries were dissolved and the Corporation received all the assets and assumed all the liabilities of the Trust. The Arrangement has been accounted
for on a continuity of interest basis and accordingly, the consolidated financial statements for periods prior to the date of conversion reflect the financial position, results of operations and cash flows as if the Corporation had always carried on
the business formerly carried on by the Trust. This MD&A may at times refer to common shares, shareholders, shareholders capital and dividends which prior to the Arrangement were referred to as trust units, trust unitholders, trust
unitholders capital and distributions, respectively. References made to trust units are those issued by the Trust. Comparative amounts in this MD&A will also reflect the history of the Trust and its subsidiaries. FREQUENTLY RECURRING TERMS Pengrowth uses the
following frequently recurring industry terms in this MD&A: bbls refers to barrels,
Mbbls refers to thousands of barrels,
boe refers to barrels of oil equivalent, Mboe refers to a thousand boe, MMboe refers to million boe, Mcf refers to thousand cubic feet, MMcf refers to
million cubic feet, Bcf refers to billion cubic feet, , MMBtu refers to million British thermal units and MW refers to megawatt. Disclosure provided herein in
respect of a boe may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf of natural gas to one barrel of crude oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead. ADVISORY REGARDING FORWARD-LOOKING STATEMENTS This MD&A contains forward-looking statements within the meaning of securities laws, including the safe harbour provisions of Canadian securities
legislation and the United StatesPrivate 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 MD&A include, but are not limited to, statements with respect to: reserves, 2012 production, the proportion of 2012 production of each product
type, production additions from Pengrowths 2012 development program, royalty expenses, 2012 operating expenses, deferred income taxes, goodwill, asset retirement obligations, taxability of dividends, remediation, reclamation and abandonment
expenses, capital expenditures, development activities, general and administration expenses, and proceeds from the disposal of properties. Statements relating to reserves are forward-looking statements, as they involve the implied
assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future. Forward-looking statements and information 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




|        |  |  |                                                   | 
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 4 |  |  | PENGROWTH 2011 Managements Discussion & Analysis | 



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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, our
ability to add production and reserves through our development, exploitation 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, 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: the volatility of oil and gas prices; 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; ability to produce those reserves;
production may be impacted by unforeseen events such as equipment failure and weather related causes; 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; counterparty risk; compliance with environmental laws and
regulations; changes in tax and royalty laws; Pengrowths ability to access external sources of debt and equity capital; the implementation of International Financial Reporting Standards; and the implementation of greenhouse gas emissions
legislation. Further information regarding these factors may be found under the heading Business Risks herein and under Risk Factors in Pengrowths most recent Annual Information Form (AIF), and in Pengrowths most
recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases. Copies of Pengrowths Canadian public filings are available on SEDAR at www.sedar.com.
Pengrowths U.S. public filings, including the most recent annual report form 40-F as supplemented by its filings on form 6-K, are available at www.sec.gov. Pengrowth cautions 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 MD&A are made as of the date of this MD&A and Pengrowth does not undertake any
obligation to update publicly or to revise any of the included forward-looking statements, except as required by law. The forward-looking statements in this document are provided for the limited purpose of enabling current and potential investors to
evaluate an investment in Pengrowth. Readers are cautioned that such statements may not be appropriate, and should not be used for other purposes. The
forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement. ADOPTION OF INTERNATIONAL
FINANCIAL REPORTING STANDARDS (IFRS) On January 1, 2011, Pengrowth adopted International Financial Reporting Standards (IFRS) for financial reporting purposes, using a transition date of January 1, 2010. The financial statements for the year ended December 31, 2011,
have been prepared in accordance with IFRS, and herein after referred to as GAAP. Required comparative information has been restated from previously published financial statements which were prepared in accordance with Canadian Generally Accepted
Accounting Principles (previous GAAP). For additional information regarding the changes see section International Financial Reporting
Standards (IFRS) in this MD&A. CRITICAL ACCOUNTING ESTIMATES The financial statements are prepared in accordance with IFRS. Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial
statements and revenues and expenses for the period ended. Certain of these estimates may change from period to period resulting in a material impact on Pengrowths results of operations, financial position, and change in financial position. The following describes Pengrowths significant critical accounting estimates. Estimating oil and gas reserves Pengrowth engages a qualified, independent oil and gas reserves evaluator to
perform an estimation of the Corporations oil and gas reserves at least annually. Reserves form the basis for the calculation of depletion charges and assessment of impairment of oil and gas assets. Reserves are estimated using the reserve
definitions and guidelines prescribed by National Instrument 51-101 (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (COGEH).




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|PENGROWTH 2011 Managements Discussion & Analysis |  |  | 5 


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Proved plus probable reserves are defined as the best estimate of quantities of oil, natural gas and
related substances estimated to be commercially recoverable from known accumulations, from a given date forward, based on drilling, geological, geophysical and engineering data, the use of established technology and specified economic conditions. It
is equally likely that the actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. The estimates are made using all available geological and reservoir data as well as
historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes and reservoir performance or a change in Pengrowths plans with respect to future development
or operating practices. Determination of Cash Generating Units (CGUs) CGUs are the smallest group of assets that generate cash inflows largely independent from other assets or group of assets. Determination of what constitutes a CGU is subject to managements judgment. The asset
composition of a CGU can directly impact the recoverability of the assets included therein. The recoverability of development and production asset carrying values are assessed at the CGU level. In assessing the recoverability of oil and gas
properties, each CGUs carrying value is compared to its recoverable amount, defined as the greater of fair value less costs to sell and value in use. Asset Retirement Obligation Pengrowth estimates obligations under environmental regulations in respect of
decommissioning and site restoration. These obligations are determined based on the expected present value of expenses required in the process of plugging and abandoning wells, dismantling of wellheads, production and transportation facilities and
restoration of producing areas in accordance with relevant legislation, discounted from the date when expenses are expected to be incurred. Most of the abandonment of Pengrowths wells is estimated to take place far in the future. Therefore,
changes in estimated timing of future expenses, estimated logistics of performing abandonment work and the discount rate used to present value future expenses could have a significant effect on the carrying amount of the decommissioning provision. Impairment testing Impairment testing of
property, plant and equipment is completed for each of Pengrowths CGUs. Impairment testing is based on estimates of proved plus probable reserves, production rates, oil and natural gas prices, future costs, discount rates and other relevant
assumptions. The impairment assessment of goodwill is based on the estimated fair value of Pengrowths CGUs. By their nature, these estimates are subject to measurement uncertainty and may impact the financial statements of future periods. Valuation of trade and other receivables, and prepayments to suppliers Management estimates the likelihood of the collection of trade and other receivables and recovery of prepayments based on an analysis of individual accounts. Factors taken into consideration include the aging of
receivables in comparison with the credit terms allowed to customers and the financial position and collection history with the customer. Should actual collections be less than estimates, Pengrowth would be required to record an additional expense. COMPARATIVE FIGURES Certain changes to
the presentation of oil and gas sales, operating expenses, and transportation on the Statements of Income were made in 2011, and as such comparative periods have been restated with no impact to net income. Management believes that these presentation
changes better reflect Pengrowths operating results. ADDITIONAL GAAP MEASURE Funds Flow from Operations Pengrowth uses Funds Flow from
Operations, a Generally Accepted Accounting Principles (GAAP) measure that is not defined under IFRS. Management believes that in addition to cash provided by operations, Funds Flow from Operations, as reported in the Consolidated
Statements of Cash Flow is a useful supplemental measure as it provides an indication of the funds generated by Pengrowths principal business activities prior to consideration of changes in working capital and remediation expenditures.
Pengrowth considers this to be a key measure of performance as it demonstrates its ability to generate cash flow necessary to fund dividends and capital investments. NON-GAAP FINANCIAL MEASURES This MD&A refers to certain financial measures that are not
determined in accordance with 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 GAAP. See the section of this MD&A entitled Operating Netbacks for a discussion of the calculation.




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The current level of capital expenditures funded through retained cash flow, as compared to debt or equity, can
be determined when it is compared to the difference in Funds Flow from Operations and dividends paid as shown on the Statement of Cash Flow. Management
monitors Pengrowths capital structure using non-GAAP financial metrics. The two metrics are Total Debt to the trailing twelve months Earnings Before Interest, Taxes, Depletion, Depreciation, Amortization, Accretion, and other non-cash items
(EBITDA) and Total Debt to Total Capitalization. Total Debt is the sum of working capital deficit and long term debt as shown on the Balance
Sheet, and Total Capitalization is the sum of Total Debt and Shareholders Equity. Payout Ratio is a term used to evaluate financial flexibility
and the capacity to fund dividends. Payout Ratio is defined on a percentage basis as dividends declared divided by Funds Flow from Operations. Adjusted Net Income Management believes that in addition to
net income, Adjusted Net Income is a useful supplemental measure as it reflects the underlying performance of Pengrowths business activities by excluding the after tax effect of certain mark-to-market non-cash items that may significantly
impact net income from period to period based on movements in future commodity prices and foreign exchange rates. OPERATIONAL MEASURES The reserves and production in this MD&A refer to company interest reserves or production that is Pengrowths working interest share of
production or reserves prior to the deduction of Crown and other royalties plus any Pengrowth owned royalty interest in production or reserves at the wellhead. Company interest is more fully described in the AIF. When converting natural gas to equivalent barrels of oil within this MD&A, Pengrowth uses the industry standard of six Mcf to one boe. 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 and does not represent a value equivalency at the wellhead. Production volumes,
revenues and reserves are reported on a company interest gross basis (before royalties) in accordance with Canadian practice. Pengrowths ability
to grow both reserves and production can be measured with the following metrics: Reserves per debt adjusted share and production per debt adjusted share. Reserves per debt adjusted share are measured using year-end proved plus probable reserves and
the number of common shares outstanding at year-end. The measurements are debt-adjusted by assuming additional shares are issued at year-end share prices to replace year-end long-term debt outstanding. Production per debt adjusted share is measured in respect of the average production for the year and the weighted average number of common shares outstanding
during the year. The measurements are debt-adjusted by assuming additional shares are issued at year-end share prices to replace year-end long-term debt outstanding. 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 Capital
(FDC). CURRENCY All amounts are stated in Canadian dollars unless otherwise specified. Pengrowths fourth quarter and annual results for 2011 are contained within this MD&A.




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|PENGROWTH 2011 Managements Discussion & Analysis |  |  | 7 


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2011 AND 2012 GUIDANCE AND 2011 FINANCIAL HIGHLIGHTS The following table provides a summary of the 2011 and 2012 Guidance and a review of 2011 actual results.  2011


2011


2011


2012Guidance


Actual


Variance


GuidanceAnnual Average Production (boe/d)


72,000 - 74,000



73,973







74,500 - 76,500
(1)Exit Production(2)


75,500 - 76,500



76,789







78,000
(1)Royalty Expense (% of Sales)(3)


20.0



19.3



(0.7
)


20.0Operating Expense ($/boe)


14.45
(4)


14.15



(0.30
)


13.89
(4)G&A Expense (cash & non-cash) ($/boe)


3.00
(4)


2.79



(0.21
)


2.68
(4)Net capital expenditures ($ millions)(5)


610.0



609.1



(0.9
)


625.0  (1)
Based on production guidance levels provided on January 24, 2012 and excludes Lindbergh volumes.  (2)
Exit production based on December average.  (3)
Royalty expense as a % of sales excludes the impact of commodity risk management contracts.  (4)
Operating and G&A expense ($/boe) assume the midpoint of production guidance.  (5)
Net capital expenditures includes Drilling Royalty Credits and capitalized stock based compensation. Full year and exit production was at the high end of Guidance due to favourable drilling results in the fourth quarter. Operating expense and G&A per boe were below Guidance primarily due to increased volumes in the fourth quarter. Pengrowth will include net operating income or loss associated with the Lindbergh Steam Assisted Gravity Drainage (SAGD) project in net capital
expenditures until commerciality is declared, pursuant to Pengrowths Exploration and Evaluation Assets (E&E Assets) accounting policy (see Note 7 to the financial statements for additional information). FINANCIAL HIGHLIGHTS  Three months ended


Twelve months ended(monetary amounts in millions, except per boe amounts or as otherwise stated)

Dec 31,2011


Sept 30,2011


Dec 31,2010


Dec 31,2011


Dec 31,2010Production (boe/d)


76,691



74,568



74,953



73,973



74,693Net capital expenditures(1)

$
142.1


$
163.8


$
130.9


$
609.1


$
333.8Funds flow from operations(2)

$
171.1


$
150.4


$
139.9


$
620.0


$
626.2Operating netback ($/boe)(2) (3)

$
29.99


$
27.15


$
25.02


$
28.45


$
26.92Adjusted Net Income(4)

$
22.3


$
22.9


$
40.7


$
110.9


$
208.4Net (loss) income

$
(9.0
)

$
(0.5
)

$
(152.0
)

$
84.5


$
149.8Included in net (loss) income :Realized gain (loss) on commodity risk management(5)

$
2.7


$
14.2


$
19.1


$
16.8


$
75.1Unrealized (loss) gain on commodity risk management(5)

$
(102.9
)

$
58.1


$
(52.5
)

$
(40.0
)

$
6.9Unrealized foreign exchange gain (loss)(5)

$
29.2


$
(76.4
)

$
29.7


$
(19.1
)

$
49.9Non-cash gain on investments(5)

$
23.0


$



$



$
23.0


$
73.8Deferred tax reduction (expense)

$
13.7


$
(16.1
)

$
(165.9
)

$
(22.3
)

$
(171.3
)  (1)
Net capital expenditures includes Drilling Royalty Credits and capitalized stock based compensation.  (2)
Prior periods restated to conform to presentation in the current period.  (3)
Includes the impact of realized commodity risk management contracts.  (4)
See definition under section Non-GAAP Financial Measures.  (5)
Pre-tax amount.




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Funds Flow from Operations  ($ millions)

Q4


% Change


Full Year


% Change2010 Funds Flow from Operations(1)


139.9







626.2Volume variance


9.8



7



(16.0
)


(3
)Price variance


49.2



35



154.4



25Realized gains on risk management contracts


16.3



(12
)


(58.2
)


(9
)Other Income


1.6



1



4.8



1Royalty expense


(11.4
)


(8
)


(25.2
)


(4
)Drilling Credits(2)










(16.7
)


(3
)Expenses:Operating


5.2



4



(24.8
)


(4
)Transportation


0.9







(0.6
)


Cash G&A


(4.2
)


(3
)


(18.0
)


(3
)Interest & Financing


(1.5
)


(1
)


(5.4
)


(1
)Realized foreign exchange


(0.5
)






0.5



Other Expenses


(1.6
)


(1
)


(1.0
)


2011 Funds Flow from Operations(1)


171.1



22



620.0



(1
)  (1)
Prior period restated to conform to presentation in the current period.  (2)
In the second quarter of 2010, a $16.7 million gain was recorded related to purchased
drilling credits and a property disposition where the proceeds received consisted of drilling credits in excess of the value of the assets sold. Funds Flow from Operations increased 22 percent in the fourth quarter of 2011 compared to the same period in 2010. The increase was driven by higher commodity prices for liquids and increased fourth quarter
production partially offset by lower realized gains on risk management contracts and lower natural gas prices. Funds Flow from Operations decreased one percent on a year-over-year basis. The decrease is due to lower realized gains on risk management
contracts, higher operating costs primarily due to increased power costs, higher royalties and G&A costs, lower production volumes, and the absence of gains from purchasing third party drilling credits, mostly offset by higher liquids commodity
prices. Price Sensitivity The following table
illustrates the sensitivity of Funds Flow from Operations to changes in commodity prices.  Estimated Commodity Price Environment(1)




Assumption


Change




Estimated Impact on12 month Cash Flow(2)(3) ($
millions)WTI(4)Oil Price


US$/bbl



$107.75



$1.00Light Oil Production
















7.1Heavy Oil Production
















1.8NGL Production
















2.911.8AECO Natural Gas PriceNatural Gas Production


Cdn$/Mcf



$2.39



$0.10





6.1  (1)
Calculations are performed independently and are not indicative of actual results when multiple variables change at the same time.  (2)
Commodity price is based on an estimation of the 12 month forward price curve at February 28, 2012 and does not include the impact of risk management contracts.  (3)
The calculated impact on revenue/cash flow is only applicable within a limited range of the change indicated and is based on production guidance levels contained herein.  (4)
West Texas Intermediate.




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|PENGROWTH 2011 Managements Discussion & Analysis |  |  | 9 


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Net Income or Loss For the fourth quarter of 2011, a net loss of $9.0 million was recorded, compared to a net loss of $0.5 million in the third quarter of 2011, representing an increase in the loss of $8.5 million. The larger loss in
the fourth quarter of 2011 is primarily due to non-cash losses of $28.0 million (net of deferred tax) noted below and summarized in the Adjusted Net Income reconciliation table, which more than offset the increase in Funds Flow from Operations of
$20.7 million:  

A $120.2 million (net of deferred tax) adverse change from unrealized commodity risk management contracts comprised of an unrealized loss in the fourth quarter
of $102.9 million ($76.8 million, net of deferred tax) compared to an unrealized gain of $58.1 million ($43.4 million, net of deferred tax) in the third quarter of 2011.  

A $92.2 million (net of deferred tax) favourable impact from unrealized foreign exchange comprised of a gain in the fourth quarter of $29.2 million ($25.5
million, net of deferred tax) compared to an unrealized foreign exchange loss of $76.4 million ($66.7 million, net of deferred tax) in the third quarter of 2011. A $143.0 million increase in net income was recorded in the fourth quarter of 2011 compared to the same period last year primarily due to the IFRS non-cash tax effect of changing to a corporate structure of $180.8
million, which was recorded in 2010. Funds Flow from Operations increased $31.2 million in the fourth quarter of 2011 compared to 2010. In addition, other non-cash losses of $59.5 million (net of deferred tax), detailed below, affected net income in
the fourth quarter of 2011 compared to the same period in 2010:  

A $39.1 million (net of deferred tax) adverse change from unrealized commodity risk management contracts comprised of an unrealized loss of $102.9 million ($76.8
million, net of deferred tax) in the fourth quarter of 2011 compared to an unrealized loss of $52.5 million ($37.7 million, net of deferred tax) in the same period in 2010.  

An impairment charge of $27.4 million ($20.4 million, net of deferred tax) in the fourth quarter of 2011 relating to the Groundbirch CGU. On a year-over-year basis net income decreased $65.3 million from $149.8 million in 2010 to $84.5 million in 2011. The reduction
in 2011 is primarily due to changes in certain non-cash items noted below, some of which are summarized in the Adjusted Net Income reconciliation:  

A $34.8 million (net of deferred tax) adverse change from unrealized commodity risk management contracts comprised of an unrealized loss of $40.0 million in 2011
($29.8 million, net of deferred tax) compared to an unrealized gain of $6.9 million ($5.0 million, net of deferred tax) in 2010.  

A $60.3 million (net of deferred tax) unfavourable impact from unrealized foreign exchange comprised of an unrealized loss of $19.1 million in 2011 ($16.7
million, net of deferred tax) compared to an unrealized gain of $49.9 million ($43.6 million, net of deferred tax) in 2010.  

A $53.7 million (net of deferred tax) adverse change from gains on investments comprised of a $23.0 million investment gain in 2011 ($20.1 million, net of
deferred tax) in 2011 as compared to a $73.8 million gain ($73.8 million, net of deferred tax) on Monterey shares in 2010.  

2011 also includes an impairment charge of $27.4 million ($20.4 million, net of deferred tax) relating to the Groundbirch CGU.  

Partially offsetting the above were two significant deferred tax items in 2010 which resulted in the 2010 deferred tax expense being higher than 2011 by $103.2
million. Tax deductible distributions made by the Trust in 2010 have been replaced by taxable dividends made by the Corporation in 2011, resulting in the deferred tax expense being lower in 2010 by $77.6 million. This was more than offset
by the absence of a $180.8 million IFRS charge to deferred tax expense in 2010 relating to changing to a corporate structure.




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 10 |  |  | PENGROWTH 2011 Managements Discussion & Analysis | 



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Adjusted Net Income The following table provides a reconciliation of net income to Adjusted Net Income:  Three months ended


Twelve months ended(monetary amounts in millions)

Dec 31,2011


Sept 30,2011


Dec 31,2010


Dec 31,2011


Dec 31,2010Net (loss) income

$
(9.0
)

$
(0.5
)

$
(152.0
)

$
84.5


$
149.8Addback (deduct) certain non-cash items included innet (loss) income :Unrealized (gain) loss on commodity risk management


102.9



(58.1
)


52.5



40.0



(6.9
)Unrealized foreign exchange (gain) loss


(29.2
)


76.4



(29.7
)


19.1



(49.9
)Non-cash (gain) on investments


(23.0
)










(23.0
)


(73.8
)Tax effect on non-cash items above


(19.4
)


5.1



(10.9
)


(9.7
)


8.4Tax effect on corporate conversion










180.8







180.8Adjusted net income

$
22.3


$
22.9


$
40.7


$
110.9


$
208.4 Adjusted Net Income of $22.3 million in the fourth quarter of 2011 was slightly lower compared to the Adjusted Net Income of $22.9
million in the third quarter of 2011 primarily due to increased Funds Flow from Operations offset by an impairment of assets. In the fourth quarter of
2011, Pengrowths Adjusted Net Income was $22.3 million as compared to $40.7 million in the fourth quarter of 2010. The $18.4 million decrease was due primarily to the previously mentioned impairment charge of $20.4 million net of deferred
tax ($27.4 million pre-tax) and higher deferred tax expense this year as the prior year had $25.5 million of tax deductible distributions as a Trust. These items were partly offset by an increase in Funds Flow from Operations of $31.2 million. Adjusted Net Income for the full year 2011 was $97.5 million lower than the same period in 2010 mainly as a result of the previously described
impairment charge of $20.4 million net of deferred tax ($27.4 million pre-tax), and a $77.6 million increase to deferred income tax expense this year as tax deductible distributions made by the Trust in 2010 were replaced by taxable dividends made
by the Corporation in 2011. A $6.2 million reduction in Funds Flow from Operations also contributed to the decrease. RESULTS OF OPERATIONS (All volumes, wells and spending amounts stated below reflect Pengrowths net working interest unless otherwise stated.) CAPITAL EXPENDITURES For the full year of 2011,
Pengrowth spent $609.1 million on net capital expenditures excluding property acquisitions and dispositions. Approximately 87 percent of net capital expenditures was spent on drilling, completions and facilities with the remaining 13 percent spent
on capital not directly adding reserves or production.  Three months ended


Twelve months ended($ millions)

Dec 31,2011


Sept 30,2011


Dec 31,2010


Dec 31,2011


Dec 31,2010Drilling, completions and facilities

$
124.6


$
152.7


$
120.4


$
533.5


$
300.8Land & Seismic acquisitions(1)


6.9



(0.4
)


4.5



20.6



11.5Maintenance capital


12.2



10.1



7.5



51.7



41.0Development capital


143.7



162.4



132.4



605.8



353.3Other capital(2) (3)


(0.8
)


3.0



1.9



5.7



4.4Drilling Royalty Credits


(0.8
)


(1.6
)


(3.4
)


(2.4
)


(23.9
)Net capital expenditures(4)


142.1



163.8



130.9



609.1



333.8Property acquisitions






5.5



0.1



8.6



20.2Proceeds on property dispositions


(9.5
)


(1.7
)


(12.4
)


(16.9
)


(60.7
)Net capital expenditures and acquisitions

$
132.6


$
167.6


$
118.6


$
600.8


$
293.3  (1)
Seismic acquisitions are net of seismic sales revenue.  (2)
Other capital includes equipment inventory and material transfers.  (3)
Prior periods restated to conform to presentation in the current period.  (4)
Net capital expenditures includes capitalized stock based compensation of $0.6 million for 2011 and will therefore not agree to the Statement of Cash Flow.




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|PENGROWTH 2011 Managements Discussion & Analysis |  |  | 11 


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---

DRILLING ACTIVITY Pengrowth participated in the drilling of 241 gross wells (122.6 net wells) in 2011.  Q4 2011


Q3 2011


Q2 2011


Q1 2011


Full Year 2011Gross


Net


Gross


Net


Gross


Net


Gross


Net


Gross


NetFocus Areas(1)Swan Hills


16



10.5



17



11.1



23



17.9



14



8.6



70



48.1Groundbirch










1



1.0











3



3.0



4



4.0Lindbergh


13



13.0



1



1.0



2



2.0



2



2.0



18



18.0Bodo Polymer Project










30



30.0



5



5.0











35



35.0Olds


2



0.4



2



1.5











5



2.9



9



4.8Other Areas(1)


27



1.7



35



5.0



22



3.0



21



3.0



105



12.7Total wells drilled


58



25.6



86



49.6



52



27.9



45



19.5



241



122.6  (1)
Drilling activity reflects both operated and partner operated properties. DEVELOPMENT CAPITAL ACTIVITIES Pengrowths capital spending breakdown by area is as follows:  ($ millions)

Q4 2011


Q3 2011


Q2 2011


Q1 2011


Full Year 2011Focus Areas(1)Swan Hills

$
64.8



81.8



93.3



42.2


$
282.1Groundbirch


1.0



18.5



9.0



42.1



70.6Lindbergh


34.1



13.6



10.2



3.5



61.4Bodo Polymer Project


5.1



19.6



4.6







29.3Olds


8.5



11.0



10.3



20.0



49.8113.5



144.5



127.4



107.8



493.2Other Areas(2)


11.1



8.2



7.5



13.5



40.3Drilling, completions & facilities


124.6



152.7



134.9



121.3



533.5Maintenance


12.2



10.1



12.1



17.3



51.7Land & Seismic Acquisitions


6.9



(0.4
)


12.7



1.4



20.6Other(2)


(0.8
)


3.0



2.8



0.7



5.7Drilling Royalty Credits


(0.8
)


(1.6
)










(2.4
)Net capital expenditures(3)

$
142.1



163.8



162.5



140.7


$
609.1  (1)
Spending amounts reflect the activity for both operated and partner operated properties.  (2)
Prior periods restated to conform to presentation in the current period.  (3)
Net capital expenditures includes capitalized stock based compensation of $0.6 million. Focus Areas (Pengrowth references average well test results
for certain properties. These results are not necessarily representative of long-term well performance or ultimate recoveries.) Swan Hills Trend With a net estimated 2.3 billion barrels of 42° API original oil in place in the Beaverhill Lake formation (Energy Resources Conservation Board
estimate), the Swan Hills Trend is the most significant conventional oil resource area across Pengrowths land base. 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. Success in 2010 across the Swan Hills Trend drove increased activity in
2011. During the fourth quarter, 10 operated wells (9.3 net) were drilled. Two of the wells were completed and tested with average five day
initial production (IP) rates of over 600 boe per day per well and are anticipated to be tied-in during the first quarter of 2012. The remaining eight wells drilled in the fourth quarter are expected to be completed, tested and tied-in
during the first quarter of 2012. Activity during the fourth quarter also included bringing on stream 11 operated wells (10.3 net) drilled and completed in the second and third quarters with average five day IP rates in excess of 690 boe per day per
well.




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 12 |  |  | PENGROWTH 2011 Managements Discussion & Analysis | 



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For full year 2011, a total of 46 operated wells (43.7 net) were drilled. Pengrowth brought on stream 36 operated
wells (34.9 net) in 2011 with average five day IP rates in excess of 500 boe per day per well. At year end, Pengrowth had two rigs drilling in the Swan
Hills area and anticipates that a multi-rig drilling program will continue through 2012. Lindbergh Steam Assisted Gravity Drainage
(SAGD) Project Construction of the central processing facility, well-pad and surface pipelines at the Lindbergh SAGD Pilot Facility
continued through the fourth quarter in preparation for commissioning activities which commenced in January 2012. Two SAGD well-pairs (two producers and two injectors) were drilled and completed in the fourth quarter and nine core-holes were
completed as part of the continuing resource assessment and validation in the Lindbergh area. First steam injection commenced essentially on time and budget in early February 2012. For full year 2011, 18 gross wells (18.0 net) were drilled, with four being the well-pairs and 14 being core-holes. Data from the new wells have been incorporated by GLJ Petroleum Consultants Ltd. in re-assessing
the Lindbergh Contingent Resource volumes, which will be filed with Pengrowths AIF. Groundbirch The fourth quarter saw little activity in the Groundbirch area as the natural gas price decline shifted spending to liquids projects with more robust economics. During 2011, four Montney horizontal wells (4.0 net wells) were drilled, completed and tied-in. Of the four wells, one came on stream early in the
second quarter, with the other three wells coming on stream late in the third quarter. The 30 day IP rates for these four wells averaged approximately 550 boe per day. Pengrowth does not anticipate similar activity levels at Groundbirch in 2012. Olds In the fourth quarter of 2011
Pengrowths first Mannville well, drilled in the third quarter, was tied-in and had a 30 day IP rate in excess of 500 boe per day. In 2011
Pengrowth continued with the liquids rich gas program, tying-in a well drilled late in 2010 and drilling and completing three additional wells. These four Elkton wells had average 30 day IP rates of 480 boe per day with 50 bbls per MMcf liquid
yield. These positive results have validated additional well locations for 2012. East Bodo and Cactus The East Bodo and Cactus heavy oil properties which straddle the Alberta-Saskatchewan border produce primarily from the McLaren and Lloydminster
formations. These properties produce heavy oil through a combination of water flooding with enhanced oil recovery through the injection of polymer. In 2011, positive results from Pengrowths ongoing polymer flood in the Lloydminster formation at East Bodo led to an additional 35 wells being drilled
in the third quarter of 2011.  Completion and tie-in operations were executed during the fourth quarter on 26 producers and nine
injectors. At the end of 2011 this project was ramping up and had added approximately 360 boe per day of production to Pengrowths exit rate. 2012 Capital Program Pengrowth currently anticipates a 2012
capital program, excluding acquisitions, of $625 million, an increase of three percent from 2011 net capital expenditures of $609.1 million. Pengrowths operated 2012 capital program is 100 percent focused on development of oil and liquids
rich gas plays, with the majority of the capital to be spent in the three key areas of Swan Hills ($255 million), the Olds area ($85 million) and the Lindbergh SAGD ($59 million).




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|PENGROWTH 2011 Managements Discussion & Analysis |  |  | 13 


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RESERVES AND PERFORMANCE MEASURES Reserves  Company Interest  Reserves Summary

2011


2010


2009Proved ReservesDrill + Revisions + Improved Recovery (mmboe) for the year


41.0



20.5



11.3Net Acquisitions (Dispositions) (mmboe) for the year


(0.2
)


11.2



(0.9
)Total Proved Reserves at period end


234.9



221.0



216.6Proved Reserve replacement ratio excluding net acquisitions


152%



75%



39%Proved Reserve replacement ratio including net acquisitions


151%



116%



36%Proved plus Probable Reserves (P+P)Drill + Revisions + Improved Recovery (mmboe) for the year


39.3



27.1



2.6Net Acquisitions (Dispositions) (mmboe) for the year


(0.3
)


22.8



(1.3
)Total Proved plus Probable Reserves at period end


330.5



318.4



295.7Total Production (MMboe)


27.0



27.3



29.0P+P Reserve replacement ratio excluding net acquisitions


146%



99%



9%P+P Reserve replacement ratio including net acquisitions


145%



183%



4% Net capital expenditures increased 82 percent to $609.1 million in 2011 compared to $333.8 million in 2010. This increased capital
spending resulted in higher reserve additions from drilling and revisions in 2011 compared to the previous year. New reserve additions from drilling and improved recovery projects amounted to 25.5 MMboe proved and 30.0 MMboe total proved plus
probable internally replacing 152 percent of proved and 146 percent of proved plus probable reserves. Most significant were drilling extensions in our resource plays at Groundbirch, Judy Creek, Harmattan and Carson Creek and the implementation of a
polymer flood in the East Bodo heavy oil property. In addition, technical revisions due to improved performance resulted in a net reserve increase of 15.6 MMboe proved and 9.3 MMboe total proved plus probable, primarily in Harmattan, Quirk Creek,
Jenner and Carson Creek. Further details of Pengrowths 2011 year-end reserves, Finding and Development (F&D) and Finding,
Development & Acquisition (FD&A) calculations are provided in the AIF which is filed on SEDAR (www.sedar.com) or the 40-F filed on Edgar (www.sec.gov). Performance Measures  Finding & Development Costs & Recycle Ratio

2011


2010


2009


3 year weightedaverageExcluding Net Acquisitions (F&D)Excluding Changes in FDCRecycle Ratio(1) (3)


1.9



2.2



0.3



1.7F&D costs per boe  proved plus probable

$
15.34


$
12.15


$
78.47


$
16.44Including Changes in FDCRecycle Ratio(1) (3)


1.4



1.8



0.9



1.5F&D costs per boe  proved plus probable

$
20.12


$
15.32


$
30.81


$
18.63Including Net Acquisitions (FD&A)Excluding Changes in FDCRecycle Ratio(2) (3)


1.9



1.8



0.2



1.6FD&A costs per boe  proved plus probable

$
15.23


$
14.61


$
151.41


$
16.84Including Changes in FDCRecycle Ratio(2) (3)


1.4



1.5



0.5



1.4FD&A costs per boe  proved plus probable

$
20.04


$
18.46


$
57.15


$
19.69  (1)
Recycle Ratio is calculated as operating netback per boe divided by F&D costs per boe based on proved plus probable reserves.  (2)
Recycle Ratio is calculated as operating netback per boe divided by FD&A costs per boe based on proved plus probable reserves.  (3)
Prior period restated to conform to presentation in the current period.




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 14 |  |  | PENGROWTH 2011 Managements Discussion & Analysis | 



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The 2011 total proved plus probable F&D cost, including changes in Future Development Capital
(FDC), was $20.12 per boe, a 31% increase from the 2010 F&D cost. The increase over last year is a reflection of a higher proportion of spending being made on oil and liquids rich gas projects as compared to dry gas projects in prior
years. Also contributing to higher F&D costs is the accelerated pace and increasing costs for services associated with horizontal drilling and multi-stage frac completions for wells Pengrowth drilled in various resource plays. Drilling activity
increased, particularly in the Swan Hills Trend, and proved plus probable reserve additions were 45 percent higher than in 2010. Recycle ratio is an
important performance measure in assessing investment profitability and provides a comparison to our competitors. Pengrowths operating results and capital program in 2011 yielded a recycle ratio, excluding net acquisitions and including
changes in FDC, of 1.4, in line with the three year average of 1.5. The decrease from the prior year is negatively impacted by the effect of declining natural gas prices on the average netback. Pengrowths goal over longer periods is to maintain or modestly grow production and reserves per debt adjusted share, while continuing to pay a prudent
dividend. The trend in recent years for production per debt adjusted share has been relatively flat, but decreased slightly in 2011. Production fell below expectations in 2011 due to some uncontrollable external events in the first half of the year.
Forest fires, power outages and unscheduled pipeline outages in Northern Alberta led to production being shut-in, while prolonged facility maintenance activities and severe wet weather limited access and transportation. On a debt adjusted basis, total proved plus probable reserves per share also decreased in 2011, notwithstanding an overall reserve replacement ratio of 146% for
the year. Pengrowths aggressive capital program for 2012 is targeting to restore reserve and production growth. Exiting 2011 at 76,789 boe per day is a positive step which Pengrowth intends to build on.  Other Performance Measures

2011


2010


2009Production per debt adjusted share (boe/share)(1)


0.06



0.07



0.08Reserves per debt adjusted share (boe/share)(1)


0.73



0.78



0.74  (1)
Debt adjusted shares equals the shares outstanding plus the number of shares needed to retire all of the debt at the year-end share price of $10.76 in 2011, $12.78 in 2010 and
$10.15 in 2009. PRODUCTION  Three months ended


Twelve months endedDaily production

Dec 31,2011


% oftotal


Sept 30,2011


% oftotal


Dec 31,2010


% oftotal


Dec 31,2011


% oftotal


Dec 31,2010


% oftotalLight oil (bbls)


22,935



30



21,163



28



21,762



29



21,455



29



21,743



29Heavy oil (bbls)


6,448



8



6,387



9



6,673



9



6,425



9



6,789



9Natural gas liquids (bbls)


10,478



14



10,426



14



10,177



14



9,659



13



9,611



13Natural gas (Mcf)


220,977



48



219,552



49



218,044



48



218,601



49



219,302



49Total boe per day


76,691







74,568







74,953







73,973







74,693 The increase in the fourth quarter 2011 average daily production compared to the third quarter of 2011 is mainly attributable to
production growth in the Swan Hills and Groundbirch areas as a result of our continued capital reinvestment program, and the recovery of development projects and base production after the extreme weather and pipeline outages in the second and third
quarters. Execution of Pengrowths 2012 capital program is expected to generate full year average production of between 74,500 and 76,500 boe per
day, an increase of approximately two percent from our full year 2011 average production of 73,973 boe per day. Pengrowths average production estimate for 2012 excludes any production associated with the Lindbergh pilot project. Additional
volumes from Lindbergh are anticipated in 2013 pending a successful pilot project. Light Oil Fourth quarter 2011 light oil production increased eight percent from the third quarter of 2011. This increase is mainly attributable to higher sales volumes at
Judy Creek primarily due to new wells. In addition, volumes recovered from extreme weather and third party pipeline outages that occurred in the second and third quarters of 2011.




|                                                  |  |  |            | 
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|PENGROWTH 2011 Managements Discussion & Analysis |  |  | 15 


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---

Light oil production increased five percent in the fourth quarter of 2011 compared to the same quarter last year
due to production from new wells in the Swan Hills area partially offset by natural decline. For the full year 2011 oil volumes were down one percent compared to the full year 2010 as reduced volumes in 2011 due to extreme weather, forest fires and
unscheduled pipeline outages were mostly offset by new wells and optimization in the Swan Hills area. Heavy Oil Heavy oil production increased one percent in the fourth quarter of 2011 compared to the third quarter of 2011 as increased production at East Bodo and successful
optimization activities in Jenner were mostly offset by reductions at Tangleflags due to surface and sub-surface maintenance work. The three percent
decrease between the fourth quarters of 2011 and 2010 and the five percent decrease year-over-year are attributable to increased maintenance activities and natural declines partially offset by the previously mentioned production gains in East Bodo
and Jenner. NGLs NGL production was essentially
unchanged in the fourth quarter of 2011 compared to the third quarter of 2011. Volumes increased three percent in the fourth quarter of 2011 versus the
same period last year due to additional production in Carson Creek and from the Olds Elkton development program. NGL production remained unchanged for the full year 2011 compared to 2010 as the previously mentioned increases at Carson Creek and Olds
were offset by turnaround activities in Harmattan, one less condensate shipment at Sable Offshore Energy Project (SOEP) and normal declines. Natural Gas Fourth quarter natural gas production remained
relatively unchanged compared to the third quarter of 2011 as new production at Groundbirch was offset by turnaround activities in the Harmattan area. Gas production increased one percent in the fourth quarter of 2011 compared to the same period in 2010 and remained steady year-over-year. Increased gas production
from Groundbirch and the Olds Elkton development program was offset by planned maintenance shutdowns and natural declines. COMMODITY
PRICES Average Realized Prices  Three months ended


Twelve months ended(Cdn$ unless otherwise indicated)

Dec 31, 2011


Sept 30, 2011


Dec 31, 2010


Dec 31, 2011


Dec 31, 2010Light oil (per bbl)(1)


95.19



89.61



78.52



92.55



76.07after realized commodity risk management(1)


91.58



91.95



76.13



89.94



76.22Heavy oil (per bbl)


76.13



62.36



60.42



68.24



60.22Natural gas liquids (per bbl)


70.54



66.58



56.74



69.31



56.99Natural gas (per Mcf)


3.26



3.57



3.68



3.61



4.08after realized commodity risk management


3.77



4.05



4.87



4.08



5.00Total per boe(1)


53.88



50.61



46.58



52.50



46.93after realized commodity risk management(1)


54.28



52.68



49.34



53.13



49.68Other production income(1)


0.89



0.81



0.67



0.71



0.52Total oil and gas sales per boe(1)


55.17



53.49



50.01



53.84



50.20Average Benchmark pricesWTI oil (U.S.$ per bbl)


94.06



89.54



85.24



95.11



79.61AECO spot gas (Cdn$ per MMBtu)


3.19



3.66



3.61



3.63



3.99NYMEX gas (U.S.$ per MMBtu)


3.48



4.05



3.98



4.03



4.38Currency exchange rate ($ Cdn = $1 U.S.)


0.98



1.02



0.99



1.01



0.97  (1)
Prior periods restated to conform to presentation in the current period.




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|LOGO
 16 |  |  | PENGROWTH 2011 Managements Discussion & Analysis | 



---

For the full year 2011, WTI benchmark crude oil prices increased 19 percent from 2010, averaging U.S. $95.11 per
barrel compared to an average price of U.S. $79.61 per barrel in 2010. 2011 fourth quarter benchmark crude prices increased five percent from an average price of U.S. $89.54 per bbl in the third quarter 2011 and 10 percent from an average price of
U.S. $85.24 in the fourth quarter 2010. Pengrowths average realized price for light oil, after risk management activities, averaged Cdn $89.94 per barrel in 2011 compared to Cdn $76.22 in 2010, an 18 percent increase. Fourth quarter 2011
realized prices were essentially unchanged from the third quarter 2011, primarily due to lower realized commodity risk management activities. Compared to the same quarter last year, fourth quarter 2011 realized prices were 21 percent higher
primarily due to higher benchmark prices. Natural gas markets continued their downward trend in 2011 as mild weather combined with oversupply issues
largely attributable to increased production from shale gas plays more than offset demand. The U.S. based NYMEX natural gas benchmark averaged U.S. $4.03 per MMBtu in 2011, an eight percent decline from 2010 average prices of U.S. $4.38 per MMBtu.
Fourth quarter 2011 benchmark prices decreased 14 percent from an average price of U.S. $4.05 per MMBtu in the third quarter 2011 and 13 percent from an average price of U.S. $3.98 per MMBtu in the fourth quarter 2010. AECO spot prices continued to trade at a discount to the NYMEX benchmark, although the gap narrowed throughout the year. AECO spot prices declined nine percent
year over year to an average price of Cdn $3.63 per MMBtu in 2011 from Cdn $3.99 per MMBtu in 2010. Fourth quarter 2011 prices decreased approximately 13 percent from the third quarter 2011 average price of Cdn $3.66 per MMBtu and 12 percent from
the fourth quarter 2010 average price of Cdn $3.61 per MMBtu. Pengrowths average realized natural gas price after risk management activities was
Cdn $4.08 per Mcf in 2011, an 18 percent decline compared to the 2010 average realized price of Cdn $5.00 per Mcf. Fourth quarter 2011 prices declined seven percent and 23 percent when compared to third quarter 2011 and fourth quarter 2010 average
realized prices of Cdn $4.05 per Mcf and Cdn $4.87 per Mcf. The decline in average realized prices quarter over quarter is mainly attributable to the decline in the benchmark prices partially offset by risk management activities. On a year over year
basis, realized prices were also lower due to a lower contribution from realized gas commodity risk management activities in 2011. Pengrowths
full year total average realized price, after risk management activities was Cdn $53.13 per boe in 2011, an approximate seven percent increase over the 2010 average of Cdn $49.68 per boe. This increase is primarily a result of higher benchmark
prices for crude oil partially offset by lower natural gas prices and lower contribution from gas commodity risk contracts. Total average realized price of Cdn $54.28 per boe in the fourth quarter of 2011 was three percent higher than Cdn $52.68 per
boe in the third quarter of 2011 and 10 percent higher than the average realized price of Cdn $49.34 per boe in the fourth quarter 2010. The higher realized price compared to the third quarter 2011 was primarily due to higher crude oil benchmark
prices partially offset by weaker benchmark natural gas prices. Compared to the same quarter last year, realized prices in the fourth quarter of 2011 were higher due to stronger benchmark prices for crude oil, partially offset by a lower
contribution from realized gas commodity risk management activities in 2011. Commodity Risk Management Gains (Losses)  Three months ended


Twelve months endedDec 31, 2011


Sept 30, 2011


Dec 31, 2010


Dec 31, 2011


Dec 31, 2010RealizedLight oil ($ millions)


(7.6
)


4.6



(4.8
)


(20.4
)


1.2Light oil ($ per bbl)


(3.61
)


2.34



(2.39
)


(2.61
)


0.15Natural gas ($ millions)


10.4



9.6



23.9



37.3



73.9Natural gas ($ per Mcf)


0.51



0.48



1.19



0.47



0.92Combined ($ millions)


2.8



14.2



19.1



16.9



75.1Combined ($ per boe)


0.40



2.07



2.76



0.63



2.75UnrealizedTotal unrealized risk management (liabilities) assets at period end ($ millions)


(42.0
)


60.8



(2.1
)


(42.0
)


(2.1
)Less: Unrealized risk management assets (liabilities) at beginning of period ($
millions)


60.8



2.7



50.4



(2.1
)


(9.0
)Unrealized (loss) gain on risk management contracts


(102.8
)


58.1



(52.5
)


(39.9
)


6.9




|                                                  |  |  |            | 
|------------------------------------------------- |  |  | ---------- | 
|PENGROWTH 2011 Managements Discussion & Analysis |  |  | 17 


LOGO | 



---

As part of the risk management strategy, Pengrowth uses forward price swaps to manage exposure to commodity price
fluctuations and provide a measure of stability to cash flow. A $7.6 million realized risk management loss in the fourth quarter of 2011 from crude oil
risk management activities, compared to a $4.6 million gain in the third quarter of 2011 was due to benchmark oil prices in the quarter rising higher than the average price achieved through our commodity risk management activities. The $20.4 million
realized risk management loss for the year, compared to a $1.2 million gain in 2010 was due to benchmark crude oil prices exceeding our average fixed contracted oil price in 2011. Realized gains from natural gas commodity risk management activities decreased to $37.3 million for the year ending 2011 compared to $73.9 million for the same period last year; as the 2011 gas fixed contracted
price and volumes were lower than in 2010. These factors also contributed to the lower natural gas realized risk management gain of $10.4 million in the fourth quarter 2011 compared to $23.9 million for the same period last year. The change in fair value of the forward contracts between periods affects net income through the unrealized amounts recorded during the period. The fair value
of forward contracts is determined by comparing the contracted fixed price to the forward price curve at each period end. A $102.8 million unrealized loss in the fourth quarter of 2011 compared to a $58.1 million gain in the third quarter of 2011
was due to an increase in the forward price curve for crude oil at period end December 31, 2011 from September 30, 2011 coupled with additional oil risk management contracts entered into during the fourth quarter. A $39.9 million
unrealized loss at December 31, 2011, compared to a $6.9 million gain at December 31, 2010, is due to an increase in the forward price curve for crude oil, as well significantly lower risk managed gas volumes at lower contracted prices as
at December 31, 2011 as compared to December 31, 2010. As of December 31, 2011, the following commodity risk management contracts were
in place:  Crude Oil:Reference Point

Volume (bbl/d)


Term


Price per bblFinancial:WTI(1)


17,000



Jan 1, 2012 - Dec 31, 2012


$
93.23



CdnWTI(1)


3,500



Jan 1, 2013 - Dec 31, 2013


$
95.29



Cdn  (1)
Associated Cdn $/U.S. $ foreign exchange rate has been fixed.  Natural Gas:Reference Point

Volume (MMBtu/d)


Term


Price per MMbtuFinancial:AECO


14,217



Jan 1, 2012 - Dec 31, 2012


$
4.45



CdnPower:Reference Point

Volume (MW)


Term


Price per MWFinancial:AESO


15



Jan 1, 2012 - Dec 31, 2012


$
72.83



CdnAESO


5



Jan 1, 2013  - Dec 31, 2013


$
74.50



Cdn Based on our 2012 production forecast, the above contracts represent approximately 65 percent of estimated total oil volumes at an
average price of $93.23 per bbl and approximately nine percent of estimated natural gas volumes at $4.45 per MMBtu. The power contracts represent approximately 15 percent of estimated 2012 consumption. Each Cdn $1 per barrel change in future oil prices results in approximately $7.5 million pre-tax change in the value of the crude contracts, while each Cdn $0.25
per MMBtu change in future natural gas prices results in approximately $1.3 million pre-tax change in the value of the natural gas contracts. The changes in the fair value of the forward contracts directly affects reported net income through the
unrealized amounts recorded in the Statement of Income during the period. The effect on cash flow will be recognized separately only upon settlement of the contracts, which could vary significantly from the unrealized amount recorded due to timing
and prices when each contract is settled.




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 18 |  |  | PENGROWTH 2011 Managements Discussion & Analysis | 



---

If each contract were to settle at the contract price in effect at December 31, 2011, future revenue and
cash flow would be $42.0 million lower than if the contracts were not in place based on the estimated fair value of the risk management liability at period end. The $42.0 million liability is composed of a net liability of $38.6 million relating to
contracts expiring within one year and a net liability of $3.4 million relating to contracts expiring beyond one year. Pengrowth currently fixes the Canadian dollar exchange rate at the same time it swaps U.S. dollar denominated commodity in order
to protect against changes in the foreign exchange rate. Each Cdn $1 per MW change in future power prices would result in approximately $0.2 million
pre-tax change in the fair value of the risk management contracts. Pengrowth has not designated any outstanding commodity contracts as hedges for
accounting purposes and therefore records these contracts on the Balance Sheet at their fair value and recognizes changes in fair value on the Statement of Income as unrealized commodity risk management gains or losses. There will continue to be
volatility in earnings to the extent that the fair value of commodity contracts fluctuate, however these non-cash amounts do not impact Pengrowths operating cash flow. Realized commodity risk management gains or losses are recorded in oil and
gas sales on the Statement Income and impacts cash flow at that time. In accordance with policies approved by the Board of Directors, Pengrowth may
sell forward its production by product volume or power consumption as follows:  Percent of Monthly Interest Production or estimated Power Consumption

Forward PeriodUp to 65%


1  -  12 MonthsUp to 45%


13  -  24 MonthsUp to 30%


25  -  36 Months Each commodity risk management transaction for natural gas or crude oil shall not exceed 20,000 MMBtu per day and 2,500 bbls per
day respectively. Each power consumption risk management transaction shall not exceed 25 MW. OIL AND GAS SALES Contribution Analysis The following table shows the
contribution of each product category to the overall sales revenue inclusive of realized commodity risk management activities  Three months ended


Twelve months ended($ millions except percentages) Sales Revenue

Dec 31,2011


% oftotal


Sept 30,2011


% oftotal


Dec 31,2010


% oftotal


Dec 31,2011


% oftotal


Dec 31,2010


% oftotalLight oil(1)


193.2



49



179.1



49



152.4



44



704.3



49



604.9



44Heavy oil


45.2



12



36.6



10



37.1



11



160.0



11



149.2



11Natural gas liquids


68.0



17



63.9



17



53.1



15



244.4



17



199.9



15Natural gas


76.5



20



81.8



22



97.6



29



325.9



22



400.4



29Brokered sales/sulphur(1)


6.3



2



5.5



1



4.7



1



19.1



1



14.3



1Total oil and gas sales(1)


389.2







366.9







344.9







1,453.7







1,368.7  (1)
Prior period restated to conform to presentation in the current period.




|                                                  |  |  |            | 
|------------------------------------------------- |  |  | ---------- | 
|PENGROWTH 2011 Managements Discussion & Analysis |  |  | 19 


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---

Price and Volume Analysis The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales including the impact of realized commodity risk management activities, for the fourth quarter of
2011 compared to the fourth quarter of 2010. The increased commodity prices realized for liquids after commodity risk management activities during the fourth quarter of 2011 are the primary reason for higher oil and gas sales.  ($ millions)

Light oil(1)


Natural gas


NGLs


Heavy oil


Other(1) (2)


Total(1)Quarter ended December 31, 2010


152.4



97.6



53.1



37.1



4.7



344.9Effect of change in product prices


35.2



(8.6
)


13.3



9.3







49.2Effect of change in realized commodity risk management activities


(2.8
)


(13.5
)














(16.3
)Effect of change in sales volumes


8.5



1.0



1.6



(1.3
)






9.8Other


(0.1
)










0.1



1.6



1.6Quarter ended December 31, 2011


193.2



76.5



68.0



45.2



6.3



389.2  (1)
Prior period restated to conform to presentation in the current period.  (2)
Primarily sulphur sales The following table
illustrates the effect of changes in prices and volumes on the components of oil and gas sales including the impact of realized commodity risk management activity, for the full year of 2011 compared to the same period of 2010. The increased
commodity prices realized for liquids during the full year of 2011 have more than offset the impact of lower production volumes, reduced gains from commodity risk management activities and lower realized prices for natural gas.  ($ millions)

Light oil(1)


Natural gas


NGLs


Heavy oil


Other(1) (2)


Total(1)Twelve month period ended December 31, 2010


604.9



400.4



199.9



149.2



14.3



1,368.7Effect of change in product prices


129.1



(37.0
)


43.5



18.8







154.4Effect of change in realized commodity risk management activities


(21.6
)


(36.6
)














(58.2
)Effect of change in sales volumes


(8.0
)


(1.0
)


1.0



(8.0
)






(16.0
)Other


(0.1
)


0.1











4.8



4.8Twelve month period ended December 31, 2011


704.3



325.9



244.4



160.0



19.1



1,453.7  (1)
Prior period restated to conform to presentation in the current period.  (2)
Primarily sulphur sales ROYALTY EXPENSE  Three months ended


Twelve months ended($ millions except per boe amounts)

Dec 31,2011


Sept 30,2011


Dec 31,2010


Dec 31,2011


Dec 31,2010Royalty expense


72.3



73.1



60.9



277.9



252.7$ per boe


10.25



10.65



8.83



10.29



9.27Royalties as a percent of sales(1)


18.6%



19.9%



17.7%



19.1%



18.5%Royalties as a percent of sales excluding realized risk management contracts(1)


18.7%



20.7%



18.7%



19.3%



19.5%  (1)
Prior period restated to conform to presentation in the current period. Royalties include Crown, freehold, overriding royalties and mineral taxes. Royalty payments are based on revenue before commodity
risk management activities; however gains or losses from realized commodity risk management activities are reported as part of revenue and therefore affect royalty rates as a percentage of sales. Fourth quarter royalty rates decreased compared to
the third quarter of 2011 due to prior period royalty credits and gas cost allowance claims. The higher royalty rate in the fourth quarter of 2011 compared to the same period last year is due to higher gas cost allowance claims in the fourth quarter
of 2010. On a year-over-year basis, royalties as a percentage of sales are higher in 2011 as the percentage of sales revenues from light oil and natural gas liquids have increased resulting in a higher overall royalty rate.




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|-------- |  |  | ------------------------------------------------- | 
|LOGO
 20 |  |  | PENGROWTH 2011 Managements Discussion & Analysis | 



---

Royalty expense for 2012 is forecasted to be approximately 20 percent of Pengrowths sales excluding the
impact of risk management contracts. OPERATING EXPENSES  Three months ended


Twelve months ended($ millions except per boe amounts)

Dec 31,2011


Sept 30,2011


Dec 31,2010


Dec 31,2011


Dec 31,2010Operating expenses(1)


99.7



99.5



104.9



382.0



357.2$ per boe


14.13



14.51



15.21



14.15



13.10  (1)
Prior period restated to conform to presentation in the current period. Operating expenses in the fourth quarter of 2011 were relatively unchanged from the third quarter of 2011 however, decreased two
percent on a per boe basis. Fourth quarter operating cost savings, primarily in well servicing and general maintenance offset a slight increase in power costs quarter-over-quarter. Subsurface activity and lease and right-of-way maintenance in the
fourth quarter of 2011 were significantly down from the same period in 2010 and more than offset the impact of higher power costs when comparing the same two periods. For the full year of 2011 compared to 2010, operating expenses increased seven percent. Increased expenses were primarily attributable to significantly higher power prices, which represented two-thirds of the
year-over-year increase. In addition, increased subsurface maintenance and optimization, increased road, lease and right-of-way maintenance attributable to flooding and extreme wet weather conditions and increased turnaround activity also
contributed to higher operating costs in 2011. 2012 operating expenses are forecast to be $384 million or $13.89 per boe. Power costs are approximately
20 percent of Pengrowths operating costs and will continue to be actively managed through optimizing power usage and risk management programs. TRANSPORTATION COSTS  Three months ended


Twelve months ended($ millions except per bbl and per Mcf amounts)

Dec 31,2011


Sept 30,2011


Dec 31,2010


Dec 31,2011


Dec 31,2010Oil transportation(1)


3.7



6.3



4.1



18.4



16.6$ per bbl


1.75



3.25



2.07



2.34



2.09Natural gas transportation


1.7



1.8



2.4



7.1



8.5$ per Mcf


0.09



0.09



0.12



0.09



0.11NGL transportation


0.2











0.2



$ per bbl


0.20











0.05



  (1)
Prior period restated to conform to presentation in the current period. Oil transportation decreased approximately 41 percent in the fourth quarter of 2011 compared to the third quarter of 2011 primarily
due to a decrease in Pengrowths clean product trucking costs as the Rainbow Pipeline, which experienced an unscheduled interruption in May 2011, resumed shipping in September 2011. Overall transportation costs increased two percent
year-over-year as higher clean product trucking costs were mostly offset by reduced natural gas transportation, primarily due to renegotiated rates. Pengrowth incurs transportation costs for its natural gas production once the product enters a pipeline at a title transfer point. Pengrowth has the option to
sell some of its natural gas directly to markets outside of Alberta by incurring additional transportation costs. Pengrowth sells most of its natural gas without incurring significant additional transportation costs. Pengrowth also incurs
transportation costs on its oil and NGL production that includes clean oil trucking charges and pipeline costs up to the custody transfer point. Pengrowth has elected to sell approximately 75 percent of its crude oil at market points beyond the
wellhead incurring transportation costs to the first major trading point. The transportation cost is dependent upon third party rates and distance the product travels on the pipeline prior to changing ownership or custody.




|                                                  |  |  |            | 
|------------------------------------------------- |  |  | ---------- | 
|PENGROWTH 2011 Managements Discussion & Analysis |  |  | 21 


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---

OPERATING NETBACKS There is no standardized measure of operating netbacks and therefore operating netbacks, as presented below, may not be comparable to similar measures presented by other companies. Pengrowths operating
netbacks have been calculated by taking GAAP balances directly from the Statement of Income and dividing by production. Certain assumptions have been made in allocating operating expenses, other income and royalty injection credits between light
oil, heavy oil, natural gas and NGL production. Pengrowth realized an average operating netback of $29.99 per boe in the fourth quarter of 2011
compared to $27.15 per boe in the third quarter of 2011 and $25.02 per boe for the fourth quarter of 2010. The increase in the netback in the fourth quarter of 2011 compared to the third quarter of 2011 is primarily due to higher NGL and heavy oil
commodity prices. Operating netback for the full year of 2011 is higher than the same period of 2010 as a result of higher liquids commodity prices partially offset by higher operating and royalty expenses, and lower natural gas prices. The sales price used in the calculation of operating netbacks is after realized commodity risk management gains or losses.  Three months ended


Twelve months endedCombined Netbacks ($ per boe)

Dec 31, 2011


Sept 30, 2011


Dec 31, 2010


Dec 31, 2011


Dec 31, 2010Oil & gas sales(1)


55.17



53.49



50.01



53.84



50.20Royalties


(10.25
)


(10.65
)


(8.83
)


(10.29
)


(9.27
)Operating expenses


(14.13
)


(14.51
)


(15.21
)


(14.15
)


(13.09
)Transportation costs(1)


(0.80
)


(1.18
)


(0.95
)


(0.95
)


(0.92
)Operating netback(1)


29.99



27.15



25.02



28.45



26.92Three months ended


Twelve months endedLight Oil Netbacks ($ per bbl)

Dec 31, 2011


Sept 30, 2011


Dec 31, 2010


Dec 31, 2011


Dec 31, 2010Oil & gas sales(1)


92.49



92.89



76.83



90.75



76.83Royalties


(21.29
)


(20.46
)


(17.32
)


(20.37
)


(17.32
)Operating expenses(1)


(15.40
)


(17.78
)


(18.22
)


(16.26
)


(15.91
)Transportation costs(1)


(1.75
)


(3.25
)


(2.07
)


(2.36
)


(2.10
)Operating netback(1)


54.05



51.40



39.23



51.76



41.50Three months ended


Twelve months endedHeavy Oil Netbacks ($ per bbl)

Dec 31, 2011


Sept 30, 2011


Dec 31, 2010


Dec 31, 2011


Dec 31, 2010Oil & gas sales(1)


76.13



62.36



60.42



68.24



60.22Royalties


(13.65
)


(14.23
)


(11.25
)


(13.81
)


(11.84
)Operating expenses(1)


(13.91
)


(15.54
)


(16.23
)


(14.45
)


(15.76
)Operating netback


48.57



32.59



32.94



39.98



32.62Three months ended


Twelve months endedNGLs Netbacks ($ per bbl)

Dec 31, 2011


Sept 30, 2011


Dec 31, 2010


Dec 31, 2011


Dec 31, 2010Oil & gas sales


70.54



66.58



56.74



69.31



56.99Royalties


(14.51
)


(19.42
)


(13.97
)


(16.92
)


(14.80
)Operating expenses


(12.34
)


(17.03
)


(13.56
)


(14.65
)


(12.17
)Transportation costs


(0.20
)










(0.05
)


Operating netback


43.49



30.13



29.21



37.69



30.02Three months ended


Twelve months endedNatural Gas Netbacks ($ per Mcf)

Dec 31, 2011


Sept 30, 2011


Dec 31, 2010


Dec 31, 2011


Dec 31, 2010Oil & gas sales(1)


3.98



4.22



5.03



4.24



5.12Royalties


(0.26
)


(0.31
)


(0.31
)


(0.33
)


(0.42
)Operating expenses(1)


(2.31
)


(1.98
)


(2.28
)


(2.11
)


(1.89
)Transportation costs


(0.09
)


(0.09
)


(0.12
)


(0.09
)


(0.11
)Operating netback


1.32



1.84



2.32



1.71



2.70  (1)
Prior period restated to conform to presentation in the current period.




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GENERAL AND ADMINISTRATIVE EXPENSES  Three months ended


Twelve months ended($ millions except per boe amounts)

Dec 31, 2011


Sept 30, 2011


Dec 31, 2010


Dec 31, 2011


Dec 31, 2010Cash G&A expense


16.3



14.5



12.1



64.3



46.3$ per boe


2.31



2.11



1.76



2.38



1.70Non-cash G&A expense


2.0



2.4



(1.0
)


11.0



4.6$ per boe


0.28



0.35



(0.16
)


0.41



0.17Total G&A


18.3



16.9



11.1



75.3



50.9$ per boe


2.60



2.46



1.61



2.79



1.87 Fourth quarter cash G&A expenses are higher when compared to the third quarter mainly due to increased information technology
(IT) costs and professional services. Cash G&A expenses for 2011 include certain costs relating to IT, office facilities and operations support previously charged to operating expenses in 2010. The impact of this change for the
fourth quarter and the full year of 2011 is approximately $2.3 million and approximately $12.7 million, respectively. In addition, severance costs, performance bonus true-up and non-recurring items contribute to higher cash G&A expenses in 2011
when compared to 2010. The non-cash component of G&A represents the compensation expense associated with Pengrowths Long Term Incentive Plans
(LTIP) (see Note 14 to the financial statements). The compensation costs associated with these plans are expensed over the applicable vesting period. The $6.4 million increase in the 2011 non-cash G&A as compared to 2010 was primarily due
to the higher expense calculation for the new LTIP. Also contributing was a higher performance multiplier of 0.5 applicable to the Deferred Entitlement Share Units (DESU) in 2011 as compared to a zero performance multiplier booked in
2010 applicable to the DESUs that vested in 2011. Total G&A costs are expected to decrease for 2012 to $2.68 per boe when compared to the full year
2011 of $2.79 per boe. Included in Pengrowths 2012 G&A forecast are non-cash G&A costs of approximately $0.49 per boe compared to $0.41 per boe in 2011. DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION  Three months ended


Twelve months ended($ millions except per boe amounts)

Dec 31, 2011


Sept 30, 2011


Dec 31, 2010


Dec 31, 2011


Dec 31, 2010Depletion, depreciation and amortization


117.6



112.8



108.2



437.9



432.4$ per boe


16.67



16.44



15.69



16.22



15.86Accretion


4.0



3.9



4.0



15.6



17.7$ per boe


0.57



0.57



0.58



0.58



0.65 Depletion and depreciation of property, plant and equipment is calculated using the unit of production method based on proved plus
probable reserves and is based on the dollar value of the property, plant and equipment asset base. Depletion expense in the fourth quarter of 2011 compared to the third quarter of 2011 reflects a higher depletion cost as a result of increased
production offset by positive reserve revisions booked in the fourth quarter. Depletion expense in the fourth quarter and for the year ended 2011 compared to the same periods last year were higher due mainly to the impact of the increased capital
program in 2011 as compared to 2010 and higher costs associated with horizontal drilling and multi-stage frac completions for wells drilled in the year. Accretion is a charge to earnings that increases the Asset Retirement Obligations (ARO) liability for the passage of time (unwinding of the discount). Accretion is
charged to net income over the lifetime of the producing oil and gas assets. Accretion has remained relatively stable compared to the third quarter of 2011. Accretion has decreased year over year due a reduction in the discount rates late in 2010
with further reduction in the third and fourth quarters of 2011. IMPAIRMENT In the fourth quarter of 2011, Pengrowth recognized a $27.4 million pre-tax impairment charge on the producing portion of the Groundbirch CGU as the carrying value exceeded the fair value on December 31, 2011.
Fair value was determined based on the total proved plus probable reserves estimated by Pengrowths independent reserves evaluator using the period end commodity price forecast of Pengrowths independent reserves evaluator and discounted
at a market rate.




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This impairment charge resulted from a low natural gas price forecast by Pengrowths independent reserves
evaluator and allocation of 2012 capital to properties with better economic returns. As a result, goodwill attributed to the Groundbirch CGU was reduced by $16.3 million to $Nil and the PP&E was reduced by $11.1 million. See Note 6 to the
financial statements for detailed disclosure of the assumptions used to determine the fair value and the sensitivity of these assumptions on the impairment recognized. INTEREST AND FINANCING CHARGES  Three months ended


Twelve months ended($ millions)

Dec 31, 2011


Sept 30, 2011


Dec 31, 2010


Dec 31, 2011


Dec 31, 2010Interest and Financing charges


21.1



19.3



19.6



75.9



70.5 At December 31, 2011, Pengrowth had $1 billion in long term debt. The majority of long term debt consists of U.S. dollar
denominated fixed rate notes at a weighted average interest rate of 6.3 percent. Pengrowth has an undrawn syndicated bank facility which is subject to prevailing market rates. Pengrowth renewed the syndicated bank facility in the fourth quarter which extended the facility to a four year term due November 29, 2015. As a result, the amount of capitalized renewal fees on the previous
2010 bank renewal were expensed in the fourth quarter which led to the increased interest and financing fees in 2011. The fees charged under the
previous syndicated credit facility increased upon its renewal in the fourth quarter of 2010 when rates were reset. The higher fees combined with higher debt levels as a result of greater capital spending in 2011 resulted in higher interest and
financing charges year over year. In addition, 2011 interest and financing charges include the amount expensed for the capitalized fees on the previous syndicated credit facility as noted above. GAIN ON INVESTMENTS Pengrowth owns
1.0 million shares of a private corporation with an estimated fair value of $35 million. The fair value of these shares has increased to $35 million as at December 31, 2011 resulting in an unrealized gain of $23 million in the fourth
quarter of 2011. The fair value is based on the most recent private placement equity offering closed by the private company. See Note 5 to the financial statements for additional information. TAXES Deferred income tax is a non-cash item relating to temporary differences between the accounting
and tax basis of Pengrowths assets and liabilities and has no immediate impact on Pengrowths cash flows. During the year ended December 31, 2011, Pengrowth recorded deferred tax expense of $22.3 million (December 31, 2010
 $171.3 million). No current income taxes were paid by Pengrowth in 2011 and 2010. See Note 12 to the financial statements for additional information. FOREIGN CURRENCY GAINS & LOSSES  Three months ended


Twelve months ended($ millions)

Dec 31, 2011


Sept 30, 2011


Dec 31, 2010


Dec 31, 2011


Dec 31, 2010Unrealized foreign exchange gain (loss) on U.S. dollar denominated debt


28.8



(75.5
)


31.0



(19.5
)


50.7Unrealized foreign exchange gain (loss) on U.K. pound sterling denominated
debt


2.8



(4.3
)


3.3



(1.4
)


7.431.6



(79.8
)


34.3



(20.9
)


58.1Unrealized (loss) gain on foreign exchange risk management contract on U.K. pound sterling
denominated debt


(2.4
)


3.4



(4.5
)


1.8



(8.1
)Total Unrealized foreign exchange gain (loss)


29.2



(76.4
)


29.7



(19.1
)


49.9Realized foreign exchange (loss) gain


(0.6
)


(0.8
)






(1.6
)


(2.1
)




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 24 |  |  | PENGROWTH 2011 Managements Discussion & Analysis | 



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Pengrowths unrealized foreign exchange gains and losses are primarily attributable to the translation of
the foreign denominated long term debt. The gains or losses are calculated by comparing the translated Canadian dollar balance of foreign denominated long term debt from one period to another. The total unrealized foreign exchange gain in the fourth
quarter was $29.2 million compared to an unrealized foreign exchange loss of $76.4 million and a gain of $29.7 million in the third quarter of 2011 and fourth quarter of 2010, respectively. The unrealized foreign exchange gain this quarter compared
to the loss in the third quarter was mainly the result of an increase in the closing exchange rate of the Canadian dollar to U.S. dollar since September 2011. The total unrealized foreign exchange loss as at December 31, 2011 was $19.1 million,
compared to an unrealized gain of $49.9 million as at December 31, 2010. The unrealized loss this year compared to the gain in the prior year was mainly the result of a decrease in the closing exchange rate of the Canadian dollar to U.S. dollar
since 2010. As some realized commodity prices are derived from U.S. denominated benchmarks, a weaker U.S. dollar negatively impacts oil and gas
revenues. To mitigate this, Pengrowth elects to hold a portion of its long term debt in U.S. dollars as a natural hedge. Therefore, a decline in revenues as a result of foreign exchange fluctuations will be partially offset by a reduction in U.S.
dollar interest expense. ASSET RETIREMENT OBLIGATIONS  ($ millions)

Dec 31, 2011


Dec 31, 2010


ChangeARO, opening balance


447.1



450.6



(3.5
)Revisions due to discount rate changes


206.6



90.9



115.7Expenditures on remediation


(21.9
)


(20.9
)


(1.0
)Accretion and Other(1)


29.1



(73.5
)


102.6ARO, closing balance


660.9



447.1



213.8  (1)
2010 includes revision for inflation. The
total future ARO is based on managements estimate of costs to remediate, reclaim and abandon wells and facilities having regard for Pengrowths working interest and the estimated timing of the costs to be incurred in future periods.
Pengrowth has developed an internal process to calculate these estimates which considers applicable regulations, actual and anticipated costs, type and size of well or facility and the geographic location. For the year ended December 31, 2011, Pengrowths ARO liability increased by $213.8 million. The increase is mainly due to the ARO discount rate being
revised from three and one half percent per annum in the first six months of 2011 to three percent per annum in the third quarter, and then to two and one half percent per annum in the fourth quarter to reflect changes to the underlying risk free
long term Government of Canada bond yield. Pengrowth has estimated the net present value of its total ARO to be $660.9 million as at December 31,
2011 (December 31, 2010  $447.1 million), based on a total escalated future liability of $1.8 billion (December 31, 2010  $1.8 billion). These costs are expected to be incurred over 65 years with the majority of the costs incurred
between 2036 and 2077. A risk free rate of two and one half percent per annum and an inflation rate of one and one half percent were used to calculate the net present value of the ARO. REMEDIATION TRUST FUNDS AND REMEDIATION AND ABANDONMENT EXPENSE During 2011, Pengrowths
contributions were $7.1 million (December 31, 2010  $7.6 million), into trust funds established to fund certain abandonment and reclamation costs associated with Judy Creek and SOEP. The total balance of the remediation trust funds was $49.7
million at December 31, 2011 (December 31, 2010  $42.1 million). Every five years Pengrowth must evaluate the value of the assets in the
Judy Creek remediation trust fund and the outstanding ARO, and make recommendations to the former owner of the Judy Creek properties as to whether contribution levels should be changed. The next evaluation is anticipated to occur in 2012.
Contributions to the Judy Creek remediation trust fund may change based on future evaluations of the fund. As a working interest holder in SOEP,
Pengrowth is under a contractual obligation to contribute to a remediation trust fund. The funding levels are based on the raw gas delivered and processed at the various facilities; funding levels for this fund may change each year pending a review
by the owners. Pengrowth takes a proactive approach to managing its well abandonment and site restoration obligations. There is an on-going program to
abandon wells and reclaim well and facility sites. Through December 31, 2011, Pengrowth spent $21.9 million on abandonment and reclamation (December 31, 2010  $20.9 million). Pengrowth expects to spend approximately $18.5 million in 2012
on reclamation and abandonment, excluding contributions to remediation trust funds and orphan well levies from the Alberta Energy Resources Conservation Board.




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CLIMATE CHANGE PROGRAMS Since becoming effective July 1, 2007, Alberta regulates Greenhouse Gas (GHG) emissions under the
Climate Change and Emissions Management Act, the Specified Gas Reporting Regulation (the SGRR), which imposes GHG emissions
reporting requirements, and the Specified Gas Emitters Regulation (the SGER) which imposes GHG emissions limits. These regulations
require Alberta facilities that emit more than 100,000 tonnes of greenhouse gases a year to reduce emissions intensity by 12 percent over the average baseline emission levels of 2003, 2004 and 2005. Companies can make their reductions through
improvements to their operations; by purchasing Alberta-based offset credits or by contributing to the Climate Change and Emissions Management Fund. Pengrowth in 2011 operated two facilities that are subject to the Alberta climate change
regulations where a 12 percent reduction from the baseline is required. Collectively, these facilities have reduced emissions by approximately 34 percent exceeding current-day requirements. Further reductions to baseline targets may occur and
Pengrowth is assessing options for meeting future changes to greenhouse gas emission requirements. If the emissions remain at the current levels and the baseline is modified, Pengrowth may experience additional annual costs of as much as $0.5
million for the acquisition of credits relating to the facilities. Unutilized credits from one year may be carried forward to future years. For further information, see Pengrowths AIF. Pengrowth is waiting on additional information from other
jurisdictions to assess the impact it will have on its operations. GOODWILL In accordance with IFRS, goodwill is tested for impairment at each year end, or when there is an indication of impairment, in conjunction with the assessment of impairment of property, plant and equipment. As at
December 31, 2011, Pengrowth recorded goodwill of $700.7 million.Goodwill decreased by $16.3 million in the current year due to an impairment of
the producing portion of the Groundbirch property acquired in the Monterey Exploration Ltd. business combination. See Notes 4 and 8 to the financial statements for details. Management has assessed the remaining goodwill for impairment and determined
there is no additional impairment at December 31, 2011. WORKING CAPITAL The working capital deficiency at December 31, 2011 was $137.3 million, compared to $109.2 million at December 31, 2010. FINANCIAL RESOURCES AND LIQUIDITY  As at:

Dec 31, 2011


Dec 31, 2010


Change($ millions)
Term credit facilities

$



$
39.0


$
(39.0
)Senior unsecured notes


1,007.7



985.4



22.3Long term debt


1,007.7



1,024.4



(16.7
)Working capital deficiency


137.3



109.2



28.1Total debt

$
1,145.0


$
1,133.6


$
11.4Years Ended

Dec 31 2011


Dec 31 2010


ChangeNet income

$
84.5


$
149.8


$
(65.3
)Add:Interest and financing charges


75.9



70.5



5.4Deferred tax expense


22.3



171.3



(149.0
)Depletion, depreciation, amortization and accretion


453.5



450.1



3.4Impairment of assets


27.4







27.4Other non-cash expenses (income)


34.8



(145.4
)


180.2EBITDA

$
698.4


$
696.3


$
2.1Total debt to EBITDA


1.6



1.6Total Capitalization(1)

$
4,492.3


$
4,315.9


$
176.4Total debt as a percentage of total capitalization


25.5
%


26.3
%  (1)
Total capitalization includes total outstanding debt plus Shareholders Equity. Total outstanding debt includes working capital deficit (excess).




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As at December 31, 2011, long term debt decreased by $16.7 million from December 31, 2010. In November
2011, Pengrowth completed an equity offering for net proceeds of $288.1 million which was used primarily to pay down amounts owing on the revolving credit facility as a result of an increased capital program in 2011. The decrease in long term debt
was offset by an increase of $21.0 million due to foreign currency translation losses of approximately $19.6 million on the U.S. dollar denominated debt, and $1.4 million on the U.K. pound sterling denominated debt. The decrease in debt resulted in
a trailing 12 month Total Debt to EBITDA ratio at December 31, 2011 of 1.6x which is within corporate targets. Term Credit Facilities At December 31, 2011, Pengrowths revolving credit facility was undrawn (December 31, 2010  $39 million) and letters of credit of
$24 million (December 31, 2010  $18 million) were outstanding. The credit facility includes a committed value of $1 billion and a $250 million expansion feature providing Pengrowth with up to $1.25 billion of credit capacity from a syndicate
of seven Canadian and three foreign banks. The revolving credit facility matures on November 29, 2015 and can be extended at Pengrowths discretion any time prior to maturity subject to syndicate approval. Pengrowth also maintains a $50 million demand operating facility with one Canadian bank. As at December 31, 2011, this facility was undrawn (December 31, 2010
 $22 million) and $1.5 million (December 31, 2010  $5 million) in outstanding letters of credit were outstanding. When utilized, this facility appears on the Balance Sheet as a current liability in Bank indebtedness. Together, these two facilities provide Pengrowth with approximately $1,062 million of available credit capacity at December 31, 2011, with the ability to
expand the facilities by an additional $250 million. Financial Covenants Pengrowths senior unsecured notes and credit facilities are subject to a number of covenants, all of which were met at all times during the preceding twelve months, and at December 31, 2011. All loan
agreements can be found on SEDAR (www.sedar.com) filed under Other or Material Document. The calculation for each
financial covenant is based on specific definitions, is not in accordance with GAAP and cannot be readily replicated by referring to Pengrowths financial statements. The financial covenants are substantially similar between the credit
facilities and the senior unsecured notes. Key financial covenants are summarized below:  1.
Total senior debt must not exceed 3.0 times EBITDA for the last four fiscal quarters;  2.
Total debt must not exceed 3.5 times EBITDA for the last four fiscal quarters;  3.
Total senior debt (excluding working capital) must be less than 50 percent of total book capitalization; and  4.
EBITDA must not be less than four times interest expense. There
may be instances, such as financing an acquisition, where it would be acceptable for total debt to trailing EBITDA to be temporarily offside. In the event of a significant acquisition, certain credit facility financial covenants are relaxed for two
fiscal quarters after the close of the acquisition. Pengrowth may prepare pro forma financial statements for debt covenant purposes and has additional flexibility under its debt covenants for a set period of time. This would be a strategic decision
recommended by management and approved by the Board of Directors with steps taken in the subsequent period to restore Pengrowths capital structure based on its capital management objectives. Failing a financial covenant may result in one or more of Pengrowths loans being in default. In certain circumstances, being in default of one loan will,
absent a cure, result in other loans also being in default. In the event that non-compliance continued, Pengrowth would have to repay, refinance or re-negotiate the terms and conditions of the debt and may have to suspend dividends to shareholders. If certain financial ratios reach or exceed certain levels, management may consider steps to improve these ratios. These steps may include, but are not
limited to, raising equity, property dispositions, reducing capital expenditures or dividends. Details of these measures are included in Note 17 to the December 31, 2011, financial statements. Dividend Reinvestment Plan Pengrowths Dividend
Reinvestment Plan (DRIP) entitles shareholders to reinvest cash dividends in additional shares of the Corporation. Under the DRIP, the shares
are issued from treasury at a five percent discount to the weighted average closing price of all shares traded on the TSX for the five trading days preceding a dividend payment date.




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During the year ended December 31, 2011, 5.0 million shares were issued for cash proceeds of $54.7
million under the DRIP compared to 2.3 million trust units for cash proceeds of $24.1 million for the same period last year. On January 3,
2012, Pengrowth announced that it has introduced a Premium Dividend program in addition to the DRIP, effective February 2012. Pengrowth does not
have any off balance sheet financing arrangements. FINANCIAL INSTRUMENTS Financial instruments are utilized by Pengrowth to manage its exposure to commodity price fluctuations, foreign currency and interest rate exposures. Pengrowths policy is not to utilize financial instruments
for trading or speculative purposes. Please see Note 2 to the financial statements for a description of the accounting policies for financial instruments and Note 18 to the financial statements for additional information regarding market risk,
credit risk, liquidity risk and fair value of Pengrowths financial instruments. FUNDS FLOW FROM OPERATIONS AND DIVIDENDS The following table provides Funds Flow from Operations, net income and dividends declared with the excess (shortfall) over dividends and Payout Ratio:  Three months ended


Twelve months ended($ millions, except per share amounts)

Dec 31, 2011


Sept 30, 2011


Dec 31, 2010


Dec 31, 2011


Dec 31, 2010Funds flow from operations


171.1



150.4



139.9



620.0



626.2Net (loss) income


(9.0
)


(0.5
)


(152.0
)


84.5



149.8Dividends declared


73.5



69.2



45.1
(1)


280.2



232.6
(1)Dividends declared per share


0.21



0.21



0.14
(1)


0.84



0.77
(1)Excess of funds flow from operations less dividends declared


97.6



81.2



94.8



339.8



393.6Per Share


0.28



0.25



0.30



1.02



1.31Shortfall of net (loss) income less dividends declared


(82.5
)


(69.7
)


(197.1
)


(195.7
)


(82.8
)Per Share


(0.24
)


(0.21
)


(0.61
)


(0.59
)


(0.28
)Payout Ratio


43
%


46
%


32
%


45
%


37
%  (1)
Reflects one month less of distributions declared as a result of the corporate
conversion. As a result of the depleting nature of Pengrowths oil and gas assets, capital expenditures are required
to offset production declines while other capital is required to maintain facilities, acquire prospective lands and prepare future projects. Capital spending and acquisitions may be funded by the excess of Funds Flow from Operations less
dividends declared, through additional debt or the issuance of equity. Pengrowth does not deduct capital expenditures when calculating Funds Flow from Operations. Funds Flow from Operations is derived from producing and selling oil, natural gas and related products. As such, Funds Flow from Operations is highly dependent on commodity prices. Pengrowth enters into forward
commodity contracts to mitigate price volatility and to provide a measure of stability to monthly cash flow. Details of commodity contracts are contained in Note 18 to the financial statements. DIVIDENDS The board of directors and management
regularly review the level of dividends. The board considers a number of factors, including expectations of future commodity prices, capital expenditure requirements, and the availability of debt and equity capital. As a result of the volatility in
commodity prices, changes in production levels and capital expenditure requirements, there can be no certainty that Pengrowth will be able to maintain current levels of dividends and dividends can and may fluctuate in the future. Pengrowth has no
restrictions on the payment of its dividends other than maintaining its financial covenants in its borrowings. During 2011, cash dividends were paid to
shareholders on the 15th or next business day of the month. Pengrowth paid $0.07 per share in each of the months January through December 2011, for an aggregate cash dividend of $0.84 per share.




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 28 |  |  | PENGROWTH 2011 Managements Discussion & Analysis | 



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SUMMARY OF QUARTERLY RESULTS The following table is a summary of quarterly information for 2011 and 2010.  2011

Q1


Q2


Q3


Q4Oil and gas sales ($ millions)(1)


340.9



356.7



366.9



389.2Net income (loss) ($ millions)


5.4



88.5



(0.5
)


(9.0
)Net income (loss) per share ($)


0.02



0.27







(0.03
)Net income (loss) per share - diluted ($)


0.02



0.27







(0.03
)Funds flow from operations ($ millions)


146.8



151.7



150.4



171.1Dividends declared ($ millions)


68.6



68.9



69.2



73.5Dividends declared per share ($)


0.21



0.21



0.21



0.21Daily production (boe)


73,634



70,958



74,568



76,691Total production (Mboe)


6,627



6,457



6,860



7,056Average realized price ($ per boe)


51.15



54.41



52.68



54.28Operating netback ($ per boe)


27.64



28.97



27.15



29.992010

Q1


Q2


Q3


Q4Oil and gas sales ($ millions)(1)


362.7



340.8



320.3



344.9Net income (loss) ($ millions)


139.0



18.2



144.6



(152.0
)Net income (loss) per share ($)


0.48



0.06



0.49



(0.47
)Net income (loss) per share - diluted ($)


0.48



0.06



0.48



(0.47
)Funds flow from operations ($ millions)


161.5



175.5



149.3



139.9Dividends declared ($ millions)


61.0



61.2



65.3



45.1
(2)Distributions declared per unit ($)


0.21



0.21



0.21



0.14
(2)Daily production (boe)


75,627



75,517



72,704



74,953Total production (Mboe)


6,806



6,872



6,689



6,896Average realized price ($ per boe)(1)


52.79



49.17



47.39



49.34Operating netback ($ per boe)(1)


28.24



27.75



26.64



25.02  (1)
Prior period restated to conform to presentation in the current period.  (2)
Reflects one month less of distribution declared as a result of the corporate conversion. In addition to natural decline, production changes over these quarters was a result of production limitations due to first quarter 2011 unscheduled pipeline
outage, second quarter 2011 scheduled maintenance shutdowns and restrictions due to flooding and forest fires and unscheduled maintenance in the third quarter of 2010 partly offset by the Monterey acquisition in the third quarter of 2010. Changes in
commodity prices have affected oil and gas sales, which have been partially muted by risk management activity to mitigate price volatility and to provide a measure of stability to monthly cash flow. Quarterly net income (loss) has also been impacted
by non-cash charges, in particular depletion, depreciation and amortization, impairment charges, unrealized gains on investments, accretion of ARO, unrealized mark-to-market gains and losses, unrealized foreign exchange gains and losses, and future
taxes. Funds flow was also impacted by changes in royalty expense, operating and general and administrative costs.




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Selected Annual Information The table below provides a summary of selected annual financial information for the years ended 2011, 2010, and 2009.  Twelve months ended December 31($ millions unless otherwise indicated)

2011


2010


2009(2)Oil and gas sales(1)


1,453.7



1,368.7



1,351.5Net income(2)


84.5



149.8



84.9Net income per share(3)($)


0.25



0.50



0.32Net income per share(3) diluted ($)


0.25



0.49



0.32Dividends declared per share ($)(4)


0.84



0.77



1.08Total assets


5,644.7



5,226.6



4,693.6Long term debt(5)


1,007.7



1,024.4



982.4Shareholders equity(3)


3,347.3



3,182.3



2,795.2Number of shares outstanding at year end (thousands)


360,282



326,024



289,835  (1)
Prior period restated to conform to presentation in the current period.  (2)
Pengrowths IFRS transition date was January 1, 2010. 2009 comparative information has not been restated.  (3)
Comparative amounts are Trust units and Trust Unitholders equity.  (4)
2010 reflects one month less of distribution declared as a result of the corporate conversion.  (5)
Includes long term debt and convertible debentures, as applicable. COMMITMENTS AND CONTRACTUAL OBLIGATIONS  ($ millions)

2012


2013


2014


2015


2016


Thereafter


TotalLong term debt(1)

$



$
50.9


$



$
151.7


$



$
808.8


$
1,011.4Interest payments on long term debt(2)


63.1



61.2



60.4



58.0



52.7



70.7



366.1Other(3)


15.7



15.4



15.0



14.2



14.0



15.9



90.2$
78.8


$
127.5


$
75.4


$
223.9


$
66.7


$
895.4


$
1,467.7Purchase obligationsPipeline transportation


28.5



22.5



19.4



17.5



2.1



0.5



90.5CO2purchases(4)


2.9



2.9



2.9



2.9



0.8







12.4$
31.4


$
25.4


$
22.3


$
20.4


$
2.9


$
0.5


$
102.9Remediation trust fund payments


0.3



0.3



0.3



0.3



0.3



11.0



12.5$
110.5


$
153.2


$
98.0


$
244.6


$
69.9


$
906.9


$
1,583.1  (1)
The debt repayment includes the principal owing at maturity on foreign denominated fixed rate debt translated using the year end exchange rate. (See Note 10 to
the financial statements).  (2)
Interest payments are calculated at period end exchange rates and interest rates except for foreign denominated fixed rate debt which is calculated at the actual
interest rate.  (3)
Includes office rent and vehicle leases.  (4)
For the Weyburn
CO2 project, prices are denominated in U.S. dollars and have been translated at the year-end exchange rate.




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SUMMARY OF COMMON SHARE TRADING DATA  High


Low


Close


Volume (000s)


Value ($ millions)TSX - PGF (Cdn $)2011

1st quarter

$
13.80


$
11.98


$
13.41



61,957



795.72nd quarter

$
13.96


$
11.56


$
12.15



39,337



500.23rd quarter

$
12.84


$
9.33


$
9.47



39,079



431.74th quarter

$
11.18


$
8.48


$
10.76



58,503



610.7Year

$
13.96


$
8.48


$
10.76



198,876



2,338.42010

1st quarter

$
11.96


$
10.15


$
11.75



33,376



372.72nd quarter

$
12.00


$
8.50


$
9.73



34,038



361.03rd quarter

$
11.44


$
9.40


$
11.34



47,522



488.84th quarter

$
13.38


$
11.29


$
12.78



70,469



896.9Year

$
13.38


$
8.50


$
12.78



185,405



2,119.4NYSE - PGH (U.S. $)2011

1st quarter

$
14.14


$
12.09


$
13.83



21,853



284.82nd quarter

$
14.60


$
11.81


$
12.58



25,342



332.43rd quarter

$
13.60


$
8.94


$
8.99



31,966



357.34th quarter

$
11.00


$
7.99


$
10.53



25,754



258.1Year

$
14.60


$
7.99


$
10.53



104,916



1,232.62010

1st quarter

$
11.78


$
9.78


$
11.66



20,473



218.82nd quarter

$
11.97


$
7.67


$
9.16



26,059



268.73rd quarter

$
11.10


$
8.85


$
11.06



20,153



200.04th quarter

$
13.25


$
11.02


$
12.86



19,810



245.0Year

$
13.25


$
7.67


$
12.86



86,493



932.5 BUSINESS RISKS The
amount of dividends available to shareholders and the value of Pengrowth common shares are subject to numerous risk factors. Pengrowths principle source of net cash flow is from Pengrowths portfolio of producing oil and natural gas
properties, the principal risk factors that are associated with the oil and gas business include, but are not limited to, the following influences: Risks associated with Commodity Prices 

The prices of Pengrowths products (crude oil, natural gas, and NGLs) fluctuate due to many factors including local and global market supply and demand,
weather patterns, pipeline transportation, discount for Western Canadian light and heavy oil and natural gas, and political and economic stability.  

Production could be shut-in at specific wells or fields in low commodity prices.  

Substantial and sustained reductions in commodity prices or equity markets, including Pengrowths share price, in some circumstances could result in
Pengrowth recording an impairment loss as well as affecting the ability to maintain the current dividends, spend capital and meet obligations. Risks associated with Liquidity 

Capital markets may restrict Pengrowths access to capital and raise its borrowing costs. To the extent that external sources of capital become limited or
cost prohibitive, Pengrowths ability to fund future development and acquisition opportunities may be impaired.  

Pengrowth is exposed to third party credit risk through its oil and gas sales, financial hedging transactions and joint venture activities. The failure of any of
these counterparties to meet their contractual obligations could adversely impact Pengrowth.  

Changing interest rates influence borrowing costs and the availability of capital.




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

Failing a financial covenant may result in one or more of Pengrowths loans being in default. In certain circumstances, being in default of one loan will
result in other loans also being in default. In the event that non-compliance continued, Pengrowth would have to repay the debt, refinance the debt or negotiate new terms with the debt holders and may have to suspend dividends to shareholders.  

Pengrowths indebtedness may limit the amount of dividends that we are able to pay our shareholders, and if we default on our debts, the net proceeds of any
foreclosure sale would be allocated to the repayment of our lenders, note holders and other creditors and only the remainder, if any, would be available for dividend to our shareholders.  

Uncertainty in international financial markets concerning could lead to constrained capital markets, increased cost of capital and negative impact on economic
activity and commodity prices. Risks associated with Legislation and Regulatory Changes 

Government royalties, income taxes, commodity taxes and other taxes, levies and fees have a significant economic impact on Pengrowths financial results.
Changes to federal and provincial legislation governing such royalties, taxes and fees could have a material impact on Pengrowths financial results and the value of Pengrowths common shares.  

Environmental laws and regulatory initiatives impact Pengrowth financially and operationally. We may incur substantial capital and operating expenses to comply
with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, we may be required to incur significant costs to comply with future regulations to reduce greenhouse gas and other
emissions.  

Regulations surrounding the fracture stimulation of wells, including increasing disclosure and restrictions, differ and depend on the area of operation.
Pengrowth may have to adjust operational practice, increase compliance and incur additional cost as a result.  

Changes to accounting policies may result in significant adjustments to our financial results, which could negatively impact our business, including increasing
the risk of failing a financial covenant contained within our credit facility. Risks associated with Operations 

The marketability of our production depends in part upon the availability, proximity and capacity of gathering systems, pipelines and processing facilities.
Operational or economic factors may result in the inability to deliver our products to market.  

Increased competition for properties could drive the cost of acquisitions up and expected returns from the properties down.  

Timing of oil and gas operations is dependent on gaining timely access to lands. Consultations, that are mandated by governing authorities, with all
stakeholders (including surface owners, First Nations and all interested parties) are becoming increasingly time consuming and complex, and are having a direct impact on cycle times.  

Availability of specialized equipment and goods and services, during periods of increased activity within the oil and gas sector, may adversely impact timing of
operations.  

Oil and gas operations can be negatively impacted by certain weather conditions, including floods, forest fires and other natural events, which
may restrict production and/or delay drilling activities.  

A significant portion of Pengrowths properties are operated by third parties whereby Pengrowth has less control over the pace of capital and operating
expenditures. If these operators fail to perform their duties properly, or become insolvent, we may experience interruptions in production and revenues from these properties or incur additional liabilities and expenses as a result of the default of
these third party operators.  

Geological and operational risks affect the quantity and quality of reserves and the costs of recovering those reserves. Our actual results will vary from our
reserve estimates and those variations could be material.  

Oil and gas operations carry the risk of damaging the local environment in the event of equipment or operational failure. The cost to remediate any environmental
damage could be significant.  

Delays in business operations could adversely affect Pengrowths dividends to shareholders and the market price of the common shares.  

During periods of increased activity within the oil and gas sector, the cost of goods and services may increase.  

During times of increased activity it may be more difficult to hire and retain staff and the cost for certain skills may increase.




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

Attacks by individuals against facilities and the threat of such attacks may have an adverse impact on Pengrowth and the implementation of security measures as a
precaution against possible attacks would result in increased cost to Pengrowths business.  

Actual production and reserves will vary from estimates, and those variations could be material and may negatively affect the market price of the common shares
and dividends to our shareholders.  

Delays or failure to secure regulatory approvals for Steam Assisted Gravity Drainage (SAGD) projects may result in capital being spent with reduced
economics, reduced or no further reserves being booked, and reduced or no associated future production and cash flow.  

The performance and results of a SAGD project such as Lindbergh is dependent on the ability of the steam to access the reservoir and efficiently move additional
heavy oil that would otherwise remain trapped within the reservoir rock. The amount and cost of steam required, the additional oil recovered, the quality of the oil produced, the ability to recycle produced water into steam and the ability to manage
costs will determine the economic viability for a SAGD project. Risks associated with Strategy 

Capital re-investment on our existing assets may not yield the expected benefits and related value creation. Drilling opportunities may prove to be more
costly or less productive than anticipated. In addition, the dedication of a larger percentage of our cash flow to such opportunities may reduce the funds available for dividend payment to shareholders. In such an event, the market value
of the common shares may be adversely affected.  

Pengrowths oil and gas reserves will be depleted over time and our level of cash flow from operations and the value of our common shares could be reduced
if reserves and production are not replaced. The ability to replace production depends on the amount of capital invested and success in developing existing reserves, acquiring new reserves and financing this development and acquisition activity
within the context of the capital markets.  

Incorrect assessments of value at the time of acquisitions could adversely affect the value of our common shares and dividends to our shareholders.  

Our dividends and the market price of the common shares could be adversely affected by unforeseen title defects, which could reduce dividends to our
shareholders. General Business Risks 

Investors interest in the oil and gas sector may change over time which would affect the availability of capital and the value of Pengrowth common shares.  

Inflation may result in escalating costs, which could impact dividends and the value of Pengrowth common shares.  

Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and capital costs. Pengrowth is also exposed to foreign currency
fluctuations on the U.S. dollar denominated notes for both interest and principal payments.  

The ability of investors resident in the United States to enforce civil remedies may be negatively affected for a number of reasons.  

As the unit of measure is smaller under IFRS, it may lead to more frequent impairments at the individual CGU level as a surplus from one asset will no longer
shelter a deficit in another.  

Failure to receive regulatory approval or the expiry of the rights to explore for E&E assets could lead to the impairment of E&E assets. These factors should not be considered exhaustive. Additional risks are outlined in the AIF of the Corporation available on SEDAR at
www.sedar.com. OUTLOOK Pengrowth currently anticipates a 2012 capital program, excluding acquisitions, of $625 million, an increase of three percent from 2011 net capital expenditures of
$609.1 million. Pengrowths operated 2012 capital program is 100 percent focused on development of oil and liquids rich gas plays, with the majority of the capital to be spent in the three key areas of Swan Hills ($255 million), the
Olds area ($85 million) and the Lindbergh SAGD ($59 million). Execution of Pengrowths 2012 capital program is expected to generate full year
average production of between 74,500 and 76,500 boe per day, an increase of approximately two percent from our full year 2011 average production of 73,973 boe per day. Pengrowths average production estimate for 2012 excludes any production
associated with the Lindbergh pilot project.




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2012 operating expenses are forecast to be $384 million, essentially flat to 2011, however Pengrowth expects
operating costs per boe to decrease to $13.89 due to additional production volumes. Total G&A costs are expected to decrease for 2012 to $2.68 per
boe when compared to the full year 2011 costs of $2.79 per boe. Included in Pengrowths 2012 G&A forecast are non-cash G&A costs of approximately $0.49 per boe compared to $0.41 per boe in 2011. INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS) On January 1, 2011, Pengrowth adopted International Financial Reporting Standards (IFRS) for financial reporting purposes, using a transition date of January 1, 2010. The financial statements for the year ended December 31, 2011 have been prepared in accordance with IFRS. Required
comparative information has been restated from the previously published financial statements which were prepared in accordance with Canadian Generally Accepted Accounting Principles (previous
GAAP). The adoption of IFRS has not had an impact on Pengrowths operations, capital expenditures and overall cash flows. The most significant changes under IFRS relate to Pengrowths
accounting policies on Property, Plant and Equipment (PP&E), Asset Retirement Obligations (ARO) and Deferred Income Taxes. Pengrowth also adopted certain presentation policies that differ from previous GAAP. The following discusses the
significant differences on the balances as at and for the three months and twelve months ended December 31, 2010 under IFRS compared to the amounts published under previous GAAP.  

Property, Plant & Equipment (PP&E)  

Depletion  

Under previous GAAP, Pengrowth used total proved reserves in determining depletion. Under IFRS, the carrying amount of property, plant and equipment is depleted
or amortized over the useful life of the assets. Pengrowth has determined that depleting on a total proved plus probable reserves basis better approximates the useful life of the assets.  

Depletion was calculated using a unit of production method on the full cost pool of assets under previous GAAP. Under IFRS, depletion is calculated on a unit of
production method at a field or group of fields.  

These changes resulted in a lower depletion expense under IFRS compared to previous GAAP by approximately $27 million for the three months ended
December 31, 2010 and $112 million for the year ended December 31, 2010.  

Divestitures  

Under previous GAAP, proceeds of divestitures of assets were deducted from the full cost pool without the recognition of a gain or loss unless the divesture
resulted in a change in the full cost depletion rate of 20 percent or more. Under IFRS, gains or losses on disposition of assets are measured as the difference between the proceeds and carrying value of the assets divested.  

Pengrowth recorded a gain of approximately $7 million in the three months ended December 31, 2010 and $18 million for the year ended December 31, 2010.  

Under IFRS, the gain on equity investment was disclosed below the determination of operating income.  

Impairment testing  

Under IFRS, PP&E is grouped into Cash Generating Units (CGU) based on their ability to generate largely independent cash flows. Impairment is recognized if the carrying value of a CGU exceeds the greater of the fair value of the CGU or its value in use.  

As CGUs are smaller groups of assets, impairments are expected to be recognized more frequently under IFRS. As of January 1, 2010 and December 31,
2010, no impairment was determined.  

Under previous GAAP, impairment was recognized if the aggregated carrying value of the full cost pool exceeded the undiscounted cash flows from proved reserves.
The amount of the impairment was the excess of the carrying value of the assets over the fair value of the proved plus probable reserves and the cost of unproven properties.  

ARO  

Discount Rate  

Under previous GAAP, Pengrowth was required to use a credit adjusted discount rate in estimating the ARO, which was eight percent at the date of transition.
Under IFRS, Pengrowths policy is to estimate the ARO using a risk free discount rate on January 1, 2010.




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

The effect of using a risk free discount rate of four percent resulted in an increase of $360 million to the ARO liability as at January 1, 2010 which was
partly offset by changes to timing and cost estimates of $198 million on transition to IFRS. Accretion of ARO has decreased by approximately $1 million per quarter in 2010 as a result of using a lower discount rate.  

As of December 31, 2010, an inflation rate of one and one half percent per annum and a discount rate of three and one half percent per annum was used to
calculate the ARO liability. Under previous GAAP, a credit adjusted discount rate of eight percent per annum and inflation rate of one and one half percent per annum was used. As a result, the ARO liability under IFRS was $447 million as at
December 31, 2010 as compared to $260 million as at December 31, 2010 under previous GAAP. Expected future escalated costs related to ARO were increased to $1,823 million as at December 31, 2010 as compared to $1,790 million as at
December 31, 2010 under previous GAAP.  

In addition, more frequent revisions of the ARO liability are expected due to fluctuations in the risk free rate.  

Deferred Income Taxes  

Each of the adjustments discussed above resulted in a change in deferred income taxes based on Pengrowths effective tax rate.  

In addition, taxable temporary differences in the legal entity financial statements of Pengrowth Energy Trust were required to be measured using the top marginal
personal tax rate of 39 percent, resulting in a reduction to deferred income tax liability of $164 million on transition on January 1, 2010. This IFRS adjustment, plus an additional $23 million of temporary differences incurred during 2010, was
reversed through deferred tax expense and shareholders capital upon conversion to a corporation on December 31, 2010.  

Deferred tax expense of $35 million was recorded on IFRS adjustments to the 2010 income statement.  

Reclassifications  

Under previous GAAP, interest and financing charges, realized foreign exchange loss (gain), unrealized foreign exchange loss (gain), and accretion were disclosed
as separate line items in the Statement of (Loss) Income. Under IFRS, these amounts were unchanged, but reported below the determination of operating income.  

Under previous GAAP, amortization of injectants for miscible floods was disclosed separately; under IFRS amortization of injectants for miscible floods is
included with depletion, depreciation and amortization. Interest paid is disclosed as a financing item in the Statement of Cash Flow.  

Purchases of injectants are classified as a use of cash for investing activities under IFRS.  

The Statement of Cash Flow includes a subtotal for Funds Flow from Operations which is determined as cash flow from operations after interest and
financing charges but before changes in working capital and expenditures on remediation. Management believes that in addition to cash provided by operations, Funds Flow from Operations is a useful supplemental measure as it demonstrates
the companys ability to generate cash flow necessary to fund dividends and capital investments. Pengrowths IFRS
accounting policies are provided in Note 2 to the December 31, 2011 annual financial statements. In addition, Note 23 to the annual financial statements presents reconciliations between Pengrowths 2010 previous GAAP results and the 2010
IFRS results. The reconciliations include January 1, 2010, and December 31, 2010 Balance Sheets as well as Statements of Income and Statements of Cash Flow for the year ended December 31, 2010. FUTURE CHANGES IN ACCOUNTING POLICIES IFRS 9:
Financial Instruments (IFRS 9) IFRS 9 is expected to be published in three parts. The first part, Phase 1classification and
measurement of financial instruments (IFRS 9, Phase 1), was published in October 2010. IFRS 9, Phase 1, sets out the requirements for
recognizing and measuring financial assets, financial liabilities and some contracts to buy or sell non-financial items. IFRS 9, Phase 1 simplifies measurement of financial asset by classifying all financial assets as those being recorded at
amortized cost or being recorded at fair value. For financial assets recorded at fair value, any change in the fair value would be recognized in profit or loss. IFRS 9, Phase 1, is required to be adopted for years beginning on or after
January 1, 2015 although earlier adoption is allowed. Pengrowth has not made any decision as to early adoption. Pengrowth is currently assessing the impact of this new standard.




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IFRS 10  Consolidated Financial Statements (IFRS 10) IFRS 10 was published in May 2011. IFRS 10 establishes principles for the presentation and preparation of consolidated financial statements when an entity controls
one or more other entities, including special purpose or variable interest entities. IFRS 10 also defines the principle of control and establishes control as the basis for determining which entities are consolidated in the consolidated financial
statements. IFRS 10 is required to be adopted for years beginning on or after January 1, 2013. Earlier adoption is allowed and must be adopted in conjunction with IFRS 12  Disclosure of Interest in Other Entities. Based on
Pengrowths current corporate structure, no significant changes are anticipated as a result of adopting IFRS 10. IFRS 11  Joint
Arrangements (IFRS 11) IFRS 11 was published in May 2011. IFRS 11 establishes principles for financial reporting by parties to a joint
arrangement. IFRS 11 divides all joint arrangements into two categories: joint operations where the jointly controlling parties have rights to the assets and obligations for the liabilities relating to the arrangements, and joint ventures where the
jointly controlling parties have rights to the net assets of the arrangement. Joint operations would be accounted for using the proportionate consolidation method where Pengrowths proportionate interest in the revenues, expenses, assets and
liabilities would be disclosed, consistent with Pengrowths current accounting for joint operations. Joint ventures would be accounted for using the equity method of accounting, where the investment in the joint venture would be adjusted for
Pengrowths proportion of the net income or loss of the joint venture. IFRS 11 is required to be adopted for years beginning on or after January 1, 2013 although earlier adoption is allowed. A significant portion of Pengrowth petroleum and
natural gas development and production activities are conducted with others and accordingly Pengrowth is undertaking an examination of each of these joint arrangements. The impact of adoption cannot be determined until this examination is complete. IFRS 12  Disclosure of Interest in Other Entities (IFRS 12) IFRS 12 was published in May 2011. IFRS 12 established the requirements for disclosure of ownership interests in subsidiaries, joint arrangements, associates and other entities. IFRS 12 requires disclosure of
information that enables users of financial statements to evaluate the nature of, and risks associated with, its interests in other entities and the effects of those interests on its financial position, financial performance and cash flows. IFRS 12
is required to be adopted for years beginning on or after January 1, 2013. Earlier adoption is allowed. Pengrowth is currently assessing the impact of this new standard. IFRS 13  Fair Value Measurements (IFRS 13) IFRS 13 was published in May 2011. IFRS 13
defines fair value, sets out a framework for measuring fair value and requires disclosures about fair values. IFRS 13 applies to all other IFRSs that require or permit fair value measurements or disclosures about fair value measurements. IFRS 13
defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. That definition of fair value emphasizes a market-based
measurement, not an entity-specific measurement. IFRS 13 is required to be adopted for years beginning on or after January 1, 2013. Earlier adoption is allowed. Pengrowth is currently assessing the impact of this new standard. IAS 28  Investments in Associates (IAS 28) IAS 28 was published in May 2011. IAS 28 prescribes the accounting for investments in associates and contains the requirements for the application of the equity
method to investments in associates and joint ventures. The standard is applied prospectively for annual periods beginning on or after January 1, 2013. Earlier adoption is permitted. Based on Pengrowths current corporate structure, no
significant changes are anticipated as a result of adopting IAS 28. DISCLOSURE CONTROLS AND PROCEDURES As a Canadian reporting issuer with securities listed on both the TSX and the NYSE, Pengrowth is required to comply with Multilateral Instrument
52-109Certification of Disclosure in Issuers Annual and Interim Filings, as well as the Sarbanes Oxley Act (SOX) enacted in the United States. Both the Canadian and U.S. certification rules include similar requirements where both the CEO
and the Chief Financial Officer (CFO) must assess and certify as to the effectiveness of the disclosure controls and procedures as defined in Canada by Multilateral Instrument 52-109Certification of Disclosure in Issuers Annual and
Interim Filings and in the United States by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. The CEO, Derek Evans,
and the CFO, Christopher Webster, evaluated the effectiveness of Pengrowths disclosure controls and procedures for the year ending December 31, 2011. This evaluation considered the functions performed by its Disclosure Committee, the
review and oversight of all executive officers and the board, as well as the process and systems in place for filing regulatory and public information. Pengrowths established review process and disclosure controls are designed to provide
reasonable assurance that all required information, reports and filings required under Canadian securities legislation and United States securities laws are properly submitted and recorded in accordance with those requirements.




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Based on that evaluation, the CEO and CFO concluded that the design and operation of our disclosure controls and
procedures were effective at the reasonable assurance level as at December 31, 2011, to ensure that information required to be disclosed by us in reports that we file under Canadian and U.S. securities laws is gathered, recorded, processed,
summarized and reported within the time periods specified under Canadian and U.S. securities laws and is accumulated and communicated to the management of Pengrowth Energy Corporation, including the CEO and CFO, to allow timely decisions regarding
required disclosure as required under Canadian and U.S. securities laws. It should be noted that while Pengrowths CEO and CFO believe that
Pengrowths disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that Pengrowths disclosure controls and procedures or internal control over financial reporting will
prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. INTERNAL CONTROL OVER FINANCIAL REPORTING Our
management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended and in Canada as defined in Multilateral
Instrument 52-109Certification of Disclosure in Issuers Annual and Interim Filings. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of our financial reporting and the
preparation of our financial statements for external purposes in accordance with IFRS for note disclosure purposes. Our internal control over financial reporting includes those policies and procedures that: pertain to the maintenance of records that
in reasonable detail accurately and fairly reflect our transactions and disposition of the assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with
generally accepted accounting principles and that receipts and expenditures of our assets are being made only in accordance with authorizations of our management and directors; and provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate. Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of
our internal control over financial reporting as of December 31, 2011. In making this evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal
Control-Integrated Framework. Based on our evaluation, management concluded that our internal control over financial reporting was effective as of
December 31, 2011. The effectiveness of internal control over financial reporting as of December 31, 2011 was audited by KPMG LLP, an
independent registered public accounting firm, as stated in their report, which is included with our audited consolidated financial statements for the year ended December 31, 2011. No changes were made to our internal control over financial
reporting during the year ending December 31, 2011 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.




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|PENGROWTH 2011 Managements Discussion & Analysis |  |  | 37 


LOGO | 



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EXHIBIT INDEX



|        |  |                                                                                                                        
|------- |  | -----------------------------------------------------------------------------------------------------------------------
|Exhibit |  | Description                                                                                                            
|        | 
|99.5    |  | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
|        | 
|99.6    |  | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934