Petrus Resources Ltd.
Annual Report 2011

Plain-text annual report

_____________________________________________________________________________ ANNUAL REPORT | DECEMBER 31, 2011 MANAGEMENT’S DISCUSSION AND ANALYSIS INTRODUCTION The following report is management’s discussion and analysis ("MD&A") of financial and operating results for Petrus Resources Ltd. (“Petrus” or the “Company”) for the three month period ended December 31, 2011 as well as the period from inception on December 13, 2010 to December 31, 2011. There is no comparable financial information as Petrus did not commence operations until 2011. This MD&A should be read in conjunction with the audited financial statements for the period from inception on December 13, 2010 to December 31, 2011 and other operating and financial information included in this report. Readers are directed to the advisories at the end of this report regarding forward-looking statements, BOE presentation and non-IFRS measures. DESCRIPTION OF THE COMPANY Petrus is a private Canadian energy company focused on property exploitation, strategic acquisitions and risk- managed exploration, principally in the foothills area of the Alberta Deep Basin. Petrus was incorporated December 13, 2010 and commenced operations in late 2011. During 2011, Petrus completed an initial financing, closed a major asset acquisition, entered into a farm-in agreement and closed a $43 million private placement, establishing itself by December 31, 2011 as an emerging junior producer with significant opportunities to develop new oil and liquids-rich gas reserves. 2011 SIGNIFICANT EVENTS • In April 2011, Petrus held the first close of an initial non-brokered financing. The total seed capital raised in the initial financing was $11.1 million. • On October 31, 2011, Petrus closed the acquisition of oil and natural gas assets in the central Alberta foothills area (the "Acquisition"). The Acquisition was made jointly with Manitok Energy Inc. ("Manitok") for total gross cash consideration of $85 million before closing adjustments and related costs. Petrus’ net 50% share of the Acquisition provided Petrus with immediate cash flow from 1,300 barrels of oil equivalent per day (“Boe/d”) of low-decline gas production, ownership interests in significant gathering, compression, and processing facilities, access to an extensive seismic database and an initial drilling inventory of Cardium oil and gas locations. • • • In conjunction with the Acquisition, Petrus and Manitok established an area of mutual interest and entered into a joint venture agreement on a portion of Manitok’s pre-existing lands in the Stolberg/Cordel and Fallen Timber areas. The farm-in area includes about 8,320 net acres in Stolberg and about 14,080 net acres in Fallen Timber. Petrus participated in the drilling of the first earning well in the Manitok farm-in during the fourth quarter of 2011. In November 2011, Petrus closed a private placement offering of 17.8 million common shares of the Company at an issue price of $2.00 per common share and 3.0 million common shares issued on a "flow- through" basis pursuant to the provisions of the Income Tax Act (Canada) at an issue price of $2.40 per flow-through share, for aggregate gross proceeds of $42.7 million. A portion of the proceeds was used to repay all outstanding indebtedness incurred in connection with the Acquisition. Effective December 31, 2011, Petrus has 6.7 MMboe of company working interest proved plus probable reserves, based on an evaluation prepared by GLJ Petroleum Consultants. Company working interest proved reserves totalled 4.9 MMboe, of which 59% are categorized as proved producing. 2011 | MD&A 2 • Petrus exited the year with production of approximately 1,282 Boe/d, positive working capital of $6.5 million and an undrawn credit facility of $22 million. The Company has 32 million shares outstanding, of which 30% is owned by management and directors (39% fully diluted). 2012 OUTLOOK To date in 2012, Petrus has participated in the completion of three successful Cardium oil wells in the Stolberg/Cordel area. Petrus also participated in the drilling of one exploratory well in the Hamburg area. The primary target was not productive; however, Petrus intends to evaluate a secondary zone of interest later this year. Petrus has analyzed seismic data received through the Acquisition, and purchased additional 3D seismic data over a portion of the acquired lands. New Cardium oil drilling opportunities have been identified and will be pursued as part of the planned $18 million 2012 capital program. The Company has also acquired a 50% working interest in 384 gross hectares of undeveloped land in the heart of the Cardium oil fairway at Stolberg. Petrus is working with Manitok to redeploy/optimize some compression assets, with the goal of reducing maintenance capital and operating costs, as well as recouping stranded capital. During the first quarter of 2012, Petrus hedged approximately 67% of estimated 2012 production at various prices to reduce the impact of current low gas prices. The contract floor prices average $2.46/GJ. Petrus is evaluating asset acquisition and new joint venture opportunities on an ongoing basis. Petrus is a return- driven company that is focused on delivering per share growth. The Petrus team pursues assets that are geographically focused, have predictable, low-risk production, are statistically economic and repeatable, and have drilling targets with multiple production horizons. RESULTS OF OPERATIONS Capital Expenditures (000s) Drilling and completions Geological and geophysical Land and lease retention Office Capitalized G&A, net Total before acquisitions Acquisitions Total capital expenditures Q4 2011 Q3 2011 2011 1,228 571 — 155 32 1,986 41,979 43,965 — — 203 60 85 348 — 348 1,228 571 203 215 117 2,334 41,979 44,313 Petrus’ total capital budget for 2011 was $45 million. At December 31, 2011, $44.3 million was spent, which includes the acquisition ($42 million), drilling and completions ($1.2 million), land and G&G costs ($774 thousand) and office and capitalized G&A ($332 thousand). Drilling costs of $1.2 million incurred to December 31, 2011 relate to the preliminary costs incurred on 3 gross (0.85 net) wells drilled; two (0.40 net) in the Southern Alberta Foothills and one (0.45 net) in Northwestern Alberta. The projects were all underway at year end. Petrus incurred $571 thousand on geological and geophysical costs during the fourth quarter of 2011. These costs were incurred on seismic and seismic reprocessing projects in order to further evaluate and develop the Acquisition land base for exploration opportunities. 2011 | MD&A 3 In addition to the capitalized G&A costs of $117 thousand recorded for the period ended December 31, 2011, Petrus capitalized $10 thousand of non-cash share based compensation for 2011. Petrus has approximately 20 thousand net acres of undeveloped land at December 31, 2011. RESERVES The following table provides a summary of the Company’s reserves, which were evaluated by GLJ Petroleum Consultants with an effective date of December 31, 2011. Reserves (MBoe) Proved Producing Total Proved Total Proved +Probable Net Present Value ($000s) Discounted at 10% Proved Producing Total Proved Total Proved +Probable Dec. 31, 2011 FD&A* ($/boe) 2,887 4,912 6,703 $38,665 $51,968 $67,542 14.94 10.51 8.19 — — — RLI* (yrs) 6.1 10.4 14.2 — — — *FD&A (finding, development and acquisition) cost is defined as capital costs for the time period including change in future development capital divided by change in reserves including revisions and production for that same time period. RLI (reserve life index) is defined as total reserves by category divided by the annualized Nov and Dec production. CASH FLOW Funds from operations is commonly used in the oil and gas industry to analyze operating performance. Funds from operations, as presented does not have any standardized meaning prescribed by IFRS and therefore it may not be comparable with the calculations of similar measures for other companies. Funds from operations as presented is not intended to represent cash flow from operating activities, net loss or other measures of financial performance calculated in accordance with IFRS. All references to funds from operations throughout this report are based on cash flow from operating activities as per the Statement of Cash Flows before changes in noncash working capital and decommissioning obligations. The Company commenced operations in 2011 and production of the Acquisition assets commenced in November 2011. Funds used in operations were $41 thousand for the fourth quarter of 2011 and $204 thousand for the period of inception to December 31, 2011. Petrus generated production revenue during the last two months of 2011 which generated $2 million of oil and gas revenue however the weak commodity price environment resulted in a lower than anticipated operating netback. To mitigate the risk of further commodity price decreases, Petrus entered into financial hedging contracts in 2012 for future periods. Petrus had a net loss of $871 thousand ($0.08 per share) for the period of inception to December 31, 2011 which is due to Petrus commencing operations in 2011 and incurring G&A related expenses as it advanced toward becoming an operational oil and gas company. 2011 | MD&A 4 The following table analyzes the Company’s netbacks on a barrel of oil equivalent (boe) basis, during the last two months of 2011, when Petrus commenced production: ($/boe) Sales price Royalties Operating expenses, net of processing Transportation expenses Operating netback Overriding royalty income Interest income* G&A expense (excluding non-cash)* Cash flow netback Two months ended December 31, 2011* 24.01 (5.66) (13.44) (1.05) 3.86 1.08 0.58 (5.61) (0.09) *For comparability, only November and December interest income and G&A expenses are included as production did not commence until November 1, 2011. FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES Two months ended December 31, 2011* Production* Natural gas (mcf/d) NGLs (boe/d) Oil (boe/d) Total (boe/d) Total (boe) Revenue (000s)* Natural Gas NGLs Oil Commodity revenue Gross overriding royalty revenue Oil and natural gas revenue Average realized prices Natural gas (per mcf) NGLs (per bbl) Oil (per bbl) Combined average (per boe) *The Company’s production commenced on November 1, 2011. 6,988 35 88 1,288 78,574 1,283 151 458 1,892 85 1,977 $3.01 $59.29 $89.57 $24.08 2011 | MD&A 5 Average benchmark prices Natural gas AECO (Cdn $ per mcf) Crude Oil Edmonton Light (Cdn$ per bbl) Foreign Exchange Cdn $/US$ US$/Cdn$ *The Company’s production commenced on November 1, 2011. Two months ended December 31, 2011* $3.04 $97.59 1.02 0.98 2011 production from the Southern Alberta Foothills assets averaged 1,288 boe per day and was generated during the last two months of 2011 as the assets were acquired October 31, 2011. As the Company continues to focus on its oil opportunities it anticipates a reduction in natural gas production in 2012 through natural decline and the addition of new oil production. Petrus’ production weighting in 2011 was approximately 90% natural gas, with the remainder comprised of oil and natural gas liquids. Canadian natural gas prices have seen downward pressure over the past two years and ended 2011 at the lowest point in the past 24 months. During the two months ended December 31, 2011, the benchmark natural gas price in Canada (set at the AECO hub) fell by 12 percent from the same period in 2010. AECO prices averaged $3.04 per mcf throughout the last two months of 2011 compared to Petrus’ average realized price during the same period of $3.01 per mcf. Petrus generated production revenue for the last two months of 2011 from the Acquisition assets. Petrus uses a single marketer to manage its natural gas portfolio and sells its natural gas on a daily NOVA Alberta Index. Natural gas revenue for 2011 was $1.3 million and production of 426,268 mcf accounted for 90% of Petrus’ production volume in 2011. As part of a risk management program, Petrus entered into commodity derivative contracts in 2012 for a portion of its natural gas production to protect against downward pressure on natural gas pricing. These contracts were not in effect as at December 31, 2011. Oil prices continued to recover in the last two months of 2011 with the West Texas Intermediate (WTI) averaging $97.59 per bbl. The benchmark for crude oil prices in North America, and also widely referenced globally, is WTI. As with natural gas, there can still be net price differentials due to differences in regional demand and transportation constraints which affect the actual prices received for the commodities. Petrus includes pentanes and condensates in the oil revenue stream for reporting purposes. The average realized price of Petrus’ crude oil and condensate was $89.57 per bbl for the last two months of 2011 when Petrus commenced production of the Acquisition assets. The oil and condensate revenue for 2011 was $458 thousand and production of 5,368 boe accounted for approximately seven percent of Petrus’ production volume in 2011. In 2011, Petrus’ NGL production mix consisted of ethane, butane, propane and sulphur. The pricing received for Petrus’ NGL production is based on the specific product being produced and can therefore vary from period to period depending on the production mix. In the last two months of 2011, Petrus’ overall realized NGL price averaged $59.29/bbl. The NGL revenue for 2011 was $151 thousand and production of 2,135 boe accounted for approximately three percent of Petrus’ 2011 production volume. 2011 | MD&A 6 Royalties Royalties by Type (000s) Crown royalty expense $/boe Gross overriding royalty revenue* $/boe Two months ended December 31, 2011 445 $5.66 85 $1.08 *Gross overriding royalty revenue is included in oil and natural gas revenues on the Statements of Net loss and Comprehensive loss The following table shows the Company’s crown royalty expense, broken down by commodity. Crown Royalties by Commodity Oil (000s) % of production revenue NGLs (000s) % of production revenue Natural Gas (000s) % of production revenue Total % of production revenue Two months ended December 31, 2011 141 29% 51 40% 253 20% 445 24% Crown royalty payments are made by producers of oil and natural gas to the owners of the mineral rights on the Company’s leases that are paid to provincial governments (Crown). Petrus’ overall effective crown royalty rate was 24% in the two month period ended December 31, 2011. Petrus’ royalties are primarily influenced by the gas royalties with 57% of total royalties in 2011 being gas. Alberta Crown royalties are impacted by reference prices and by production per well. Petrus generated $85 thousand or $1.08/boe of gross overriding royalty revenue from third parties by way of contractual overriding royalties in the two month period ended December 31, 2011. Operating Expenses (000s) Operating expense Processing revenue* Operating expense net of processing Operating expense, net (per boe) *Processing revenues are included in Other income on the Statement of Net loss and Comprehensive loss Two months ended December 31, 2011 1,139 (83) 1,056 $13.44 Operating expenses totalled $1.14 million or $14.49 per boe for the two months ended December 31, 2011. The Company’s operating expenses consist of $336 thousand or $4.28 per boe of processing, gathering and compression charges, and $803 thousand of other operating expenses incurred related to the producing assets which were acquired October 31, 2011. Petrus generated $83 thousand or $1.05 of processing revenue on jointly owned facilities. As a result, Petrus’ net operating expenses totalled $1.1 million or $13.44 per boe, which were all incurrd in the last two months of 2011. 2011 | MD&A 7 Transportation Expenses (000s) Transportation expense $/boe Two months ended December 31, 2011 82 $1.05 Petrus pays commodity and demand charges for transporting its gas on the Nova pipeline system. Transportation expenses totalled $82 thousand or $1.05/boe for 2011, which commenced in November upon close of the asset Acquisition. Finance Expenses (000s) Accretion $/boe Two months ended December 31, 2011 18 $0.23 Petrus’ finance expenses consist of accretion of its decommissioning obligation for the year ended December 31, 2011. Petrus recognized a $3.6 million obligation on October 31, 2011 associated with the asset acquisition. The accretion of this obligation for the two months ended December 31, 2011, using a risk free interest rate of three percent, resulted in $18 thousand of accretion being recognized. General and Administrative Expenses (000s) Gross G&A expense Capitalized G&A Net G&A expense Share based compensation, net Total G&A expense, net Q4 2011 Q3 2011 2011 496 (32) 463 23 486 283 (85) 198 — 198 778 (117) 661 23 684 The 2011 general and administration (“G&A”) expenses, net of capitalized costs directly attributable to exploration and development totalled $684 thousand. For 2011, Petrus capitalized $117 thousand of cash G&A that directly related to exploration and development activities. For the three months ended December 31, 2011, Petrus’ net G&A was $486 thousand compared to $198 thousand in the prior quarter. The overall increase in G&A for the fourth quarter compared to the third quarter in 2011 is due to increased operating expenditures including office rent and salaries reflecting Petrus making advances toward becoming a fully operational oil and gas company. On December 19, 2011, Petrus made its first grant of performance warrants. 4,934,000 performance warrants were granted at an exercise price of $2.00 and during the year no warrants were forfeited or expired. Non-cash expenses related to Petrus’ performance warrants were $32 thousand for 2011, of which $10 thousand was capitalized, representing the portion directly attributable to exploration and development activities. Petrus uses the Black Scholes pricing model to estimate the fair value of the warrants on the date of grant and amortizes the estimated expense using graded vesting over the vesting period. At December 31, 2011, Petrus had 4,934,000 warrants outstanding at an average exercise price of $2.00. No warrants were vested or exercisable at December 31, 2011. All warrants were anti-dilutive at December 31, 2011. 2011 | MD&A 8 Depletion and Depreciation (000s) Depletion Depreciation Total $/boe* Depletion Depreciation Total ($/boe) Q4 2011 Q3 2011 618.3 8.4 626.7 7.87 0.11 7.98 — 0.4 0.4 — — — *Petrus commenced production on November 1, 2011 therefore $/boe amounts are for the two month period ended December 31, 2011. Depletion and depreciation expense is computed on a unit-of-production basis. This fluctuates period to period primarily as a result of changes in the underlying proved plus probable reserve base and in the amount of costs subject to depletion and depreciation, including future development costs. Such costs are segregated and depleted on an area by area basis relative to the respective underlying proved plus probable reserve base. As the Company had production assets effective October 31, 2011, 2011 depletion of $618.3 thousand or $7.87 per boe was recorded for the last two months of 2011. For the period of inception to December 31, 2011, depreciation expense totalled $8.8 thousand which relates to amortization of the Company’s office related assets for the year. The depreciation incurred in the fourth quarter of 2011 was $8.4 thousand, and was significantly higher than the $0.4 thousand incurred in the third quarter as a result of office equipment purchases and leasehold improvements made during the fourth quarter, as Petrus made advances toward becoming an operational oil and gas company. Impairment Analysis Under International Accounting Standard (IAS) 36 – Impairment of Assets, impairment testing is performed at the cash generating unit (CGU) level and is a one step process for testing and measuring impairment of assets wherein each CGU’s carrying value is compared to the higher of “value in use” and “fair value less costs to sell.” Value in use is defined as the present value of future cash flows expected to be derived from the CGU. Impairment tests were performed at December 31, 2011 using future cash flows given a present value using a discount rate of 10%. For the Company’s Southern Alberta Foothills CGU at December 31, 2011, no impairment was identified. Other Income In 2011, the Company invested excess cash balances into Guaranteed Investment Certificates with its bank. Interest income was $68 thousand in the period ended December 31, 2011. Also included in other income is processing revenue of $83 thousand which relates to processing fees charged to joint venture partners at jointly owned processing facilities. 2011 | MD&A 9 Deferred Taxes At December 31, 2011, deferred income tax assets have not been recognized due to the uncertainty as to future realization. Management will review the carrying amount of deferred tax assets at the end of the next reporting period and determine if sufficient taxable income will be available to allow all or part of the asset to be recovered. Net loss before taxes Combined federal and provincial tax rate Computed “expected” tax (recovery) Increase/(decrease) in taxes resulting from: Permanent items Impact of flow through shares Share issuance costs Change in rates Deferred tax benefits deemed not probable to be recovered Deferred tax (recovery) Effective tax rate Year ended December 31, 2011 (871,193) 26.5% (230,866) 6,619 331,563 (551,600) (6,075) 450,359 — 25.0% The Corporation had non-capital losses of approximately $2.5 million which may be applied against future income for Canadian tax purposes. These noncapital losses expire in 2031. These losses have not been recorded in the Corporation’s records as they are deemed not probable to be recovered. The Corporation had tax allowances of approximately $5.9 million which may be applied against future income for Canadian tax purposes. These allowances are not subject to expiry. These allowances have been recorded in the Corporation’s records as they are deemed not probable to be recovered. Equity In November 2011, the Company closed a private placement offering of 17.8 million common shares of the Company at an issue price of $2.00 per common share and 3.0 million common shares issued on a "flow-through" basis pursuant to the provisions of the Income Tax Act (Canada) at an issue price of $2.40 per flow-through share, for aggregate gross proceeds of $42.7 million. A portion of the proceeds was used to repay all outstanding indebtedness incurred in connection with the Acquisition. The remainder of the proceeds from the November offering will be used to fund the Company's capital expenditure program and for working capital purposes. The Company has a stock option plan (the “Plan”) in place whereby it may issue stock options and performance warrants to employees, consultants and directors of the Company. The shares to be offered under the Plan consist of common shares of the Company’s authorized but unissued common shares. The aggregate number of shares issuable upon the exercise of all options granted under the Plan shall not exceed 20% of the issued and outstanding shares from time to time. If any option or warrant granted hereunder shall expire or terminate for any reason in accordance with the terms of the Plan without being exercised, the unpurchased shares subject thereto shall again be available for the purpose of this Plan. Excluded from diluted per share amounts for the year ended December 31, 2011 is the effect of 4,934,000 warrants as their effect is anti-dilutive. 2011 | MD&A 10 At April 26, 2012, there are 32 million shares outstanding and 4,934,000 performance warrants outstanding. The exercise price of the performance warrants outstanding is $2.00. Funds from Operations, Cash Flow from Operating Activities and Net Loss December 31, 2011 Funds (used in) operations ($) Funds (used in) operations ($ per share) Basic Diluted Cash flow (used in) operations Net loss ($) Net loss ($ per share) Basic Diluted Shares outstanding Basic Diluted Weighted average shares outstanding Basic Diluted Three months ended Twelve months ended (40,718) (203,826) (0.002) (0.002) (705,769) (707,726) (0.03) (0.03) 32,033,016 32,033,016 21,619,878 21,619,878 (0.02) (0.02) (839,248) (871,193) (0.08) (0.08) 32,033,016 32,033,016 10,615,543 10,615,543 Liquidity and Capital Resources As at December 31, 2011, the Company had a demand revolving credit facility of $22 million with a major Canadian lender. At December 31, 2011, the Company has not drawn against the credit facility and the Company had a working capital surplus of $6.5 million. The credit facility was obtained for general corporate purposes as well as to provide bridge financing for the Acquisition which closed October 31, 2011. The facility is available on a revolving basis for a period until June 30, 2012 and then for a further year under the term out provisions. The initial term out date may be extended for further 364 day periods at the request of Petrus, subject to approval by the lender. The credit facility provides that advances may be made by way of overdraft borrowings, direct Canadian and U.S. dollar advances, bankers’ acceptances or standby letters of credit/guarantees. The amount of the credit facility is subject to a borrowing base test performed on a semi-annual review by the lender, based primarily on reserves and using commodity prices estimated by the lender as well as other factors. A decrease in the borrowing base could result in a reduction to the available credit facility. The next semi-annual review of the credit facility is to take place on June 30, 2012. ‐ The Company’s general capital management policy is to maintain a sufficient capital base in order to manage its business to enable the Company to increase the value of its assets and therefore its underlying share value. The Company’s objectives when managing capital are (i) to manage financial flexibility in order to preserve the Company’s ability to meet financial obligations; (ii) maintain a capital structure that allows Petrus the ability to finance its growth using internally generated cashflow and (iii) to maintain a flexible capital structure which optimizes the cost of capital at an acceptable risk level and provides an optimal return to equity holders. In the management of capital, Petrus includes share capital and total net debt, which is made up of debt and working capital (current assets less current liabilities). Petrus manages its capital structure and makes adjustments in light of economic conditions and the risk characteristics of the underlying assets. In order to maintain or adjust the capital structure, Petrus may issue new equity, increase or decrease debt, adjust capital expenditures and acquire or dispose of assets. 2011 | MD&A 11 Petrus anticipates that it will have adequate liquidity to fund future working capital and forecasted capital expenditures in 2012 through a combination of cash flow and additional use of its existing credit facility. Petrus is able to modify its capital program in response to changes in commodity prices and cash flows. Should the Company choose to expand its capital program, actual funding alternatives will be influenced by the then current market environment and the ability to access capital on reasonable terms, balanced with the investment opportunities presented. Related Party and Off Balance Sheet Transactions Included in share issue costs are structuring fees of $359 thousand which relate to the Company’s initial financing. The fees were paid to a company controlled by a director of Petrus. The Company entered into a bridge financing agreement with a lender who is also a director of the Company. The bridge term loan was used to finance the Acquisition which Petrus closed October 31, 2011 prior to the November 2011 private equity placement. Prior to year end, the Company repaid the bridge loan and terminated the agreement. Provisions and Contingencies The Company is committed to incur exploration expenditures of $5.88 million on or before December 31, 2012, related to the flow through share issuance completed on November 14, 2011, as indicated in note 10. Petrus may be subject to Part XII.6 tax based upon the prescribed rate, on the balance of exploration expenditures not yet incurred at the end of each month subsequent to January 31, 2012 however it is expected that the Company will satisfy the obligation during the first quarter of 2012. Petrus is the subject of litigation arising out of the termination of an officer of the Company. Damages claimed under this litigation are indeterminate however they may be material to the Company’s financial condition or results of operations. Petrus has made a provision for the estimated costs associated with this litigation based upon guidance provided by its legal counsel. The likelihood of success of the litigation is not yet known. Commitments The commitments for which the Company is responsible are as follows: Commitments (000s) Office equipment lease Capital commitments Corporate office lease Total Commitments Total < 1 year 1-3 years 4-5 years >5 years 20 10,696 3,294 14,010 5 5,296 271 5,572 10 5,400 631 6,031 5 — 661 666 — — 1,731 1,731 Petrus enters into many contractual obligations in the course of conducting its day to day business. Material contractual obligations consist of long-term debt with a syndicate of major banks, firm transportation charges and operating lease arrangements. The Company estimates it will incur approximately $6.6 million to settle its decommissioning liabilities to abandon and reclaim petroleum and natural gas assets including well sites, gathering systems and processing facilities. The present value of the expected cash flows is $3.6 million and has been recorded on the Company’s balance sheet as at December 31, 2011. These costs will be incurred over the operating lives of the assets with the majority being at or after the end of production. The Company may enter into farm-in agreements where it commits to capital expenditures in order to earn and retain certain lands. These are considered routine in nature and form part of the normal course of operations for active oil and gas companies and are not included in the table above. 2011 | MD&A 12 Subsequent Events Financial derivative contracts Subsequent to December 31, 2011, the Company entered into the following commodity financial derivative contracts: Natural Gas Period Hedged Type Daily Volume February 1, 2012 to March 31, 2012 February 1, 2012 to December 31, 2012 April 1, 2012 to October 31, 2012 May 1, 2012 October 31, 2012 November 1, 2012 March 31, 2013 April 1, 2013 to October 31, 2013 Fixed price Costless collar Fixed price Fixed price Fixed price Costless collar 1,500 GJ 1,500 GJ 1,500 GJ 2,000 GJ 4,000 GJ 1,500 GJ Price (CAD) $2.71/GJ $2.70 - $2.95/GJ $2.77/GJ $2.25/GJ $2.25/GJ $2.50 - $3.02/GJ Crude Oil Period Hedged Type Daily Volume Price (USD) May 1, 2012 to December 31, 2012 Costless collar 75 Bbl WTI $95.00 - $106.55/Bbl Common share issuance On April 11, 2012 the Company issued 80,000 common shares at a price of $2.00 per share for gross proceeds of $160,000. The issuance was a subsequent additional closing related to the November 2011 private equity placement. Outlook Petrus’ capital will focus primarily on its oil opportunities in 2012 and capital spending of approximately $18 million will be funded by cash flow and available debt financing. Petrus has a high-quality, low-risk asset base and numerous oil resource opportunities to provide sustained growth. To date in 2012, Petrus has incurred sufficient capital expenditures to satisfy its $5.88 million flow through commitment related to the flow through share issuance completed on November 14, 2011. 2011 | MD&A 13 _____________________________________________________________________________________________________________ CRITICAL ACCOUNTING ESTIMATES AND SOURCES OF JUDGMENT The timely preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of the condensed interim consolidated financial statements are outlined below. ‐ ‐ Depletion and reserve estimates Petroleum and natural gas assets are depleted on a unit of production basis at a rate calculated by reference 101 - Standards of to proved and probable reserves determined in accordance with National Instrument 51 Disclosure for Oil and Gas Activities (“NI 51 101”). The calculation incorporates the estimated future cost of developing and extracting those reserves. Proved and probable reserves are estimated using independent reservoir engineering reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. Reserves estimates, although not reported as part of the Company’s condensed consolidated financial statements, can have a significant effect on net loss, assets and liabilities as a result of their impact on depletion and depreciation, decommissioning liabilities, deferred taxes, asset impairments and business combinations. Independent reservoir engineers perform evaluations of the Company’s petroleum and natural gas reserves on an annual basis. The estimation of reserves is an inherently complex process requiring significant judgment. Estimates of economically recoverable petroleum and natural gas reserves are based upon a number of variables and assumptions such as geoscientific interpretation, production forecasts, commodity prices, costs and related future cash flows, all of which may vary considerably from actual results. These estimates are expected to be revised upward or downward over time, as additional information such as reservoir performance becomes available or as economic conditions change. Impairment indicators and cash-generating units For purposes of impairment testing, petroleum and natural gas assets are aggregated into cash generating units (“CGU’s”), based on separately identifiable and largely independent cash inflows. The determination of the Company’s CGU’s is subject to judgment. ‐ ‐ ‐ in The recoverable amounts of CGU’s and individual assets have been determined based on the higher of the value use calculations and fair values less costs to sell. These calculations require the use of estimates and assumptions, including the discount rate, future petroleum and natural gas prices, expected production volumes and anticipated recoverable quantities of proved and probable reserves. These assumptions are subject to change as new information becomes available and changes in economic conditions take place. Changes may impact the estimated life of the field and economical reserves recoverable and may require a material adjustment to the carrying value of petroleum and natural gas assets. The Company monitors internal and external indicators of impairment relating to its tangible assets. Technical feasibility and commercial viability of exploration and evaluation assets The determination of technical feasibility and commercial viability, based on the presence of proved and probable reserves, results in the transfer of assets from exploration and evaluation assets to petroleum and natural gas assets. As discussed above, the estimate of proved and probable reserves is inherently complex and requires significant judgment. Thus any material change to reserve estimates could affect the technical feasibility and commercial viability of the underlying assets. 2011 | MD&A 14 Decommissioning obligations At the end of the operating life of the Company’s facilities and properties and upon retirement of its petroleum and natural gas assets, decommissioning costs will be incurred by the Company. This requires judgment regarding abandonment date, future environmental and regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the removal cost and discount rates to determine the present value of these cash flows. Income taxes Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in income or loss both in the period of change, which would include any impact on cumulative provisions, and in future periods. Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a judgment as to whether or not there will be sufficient taxable income available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in income or loss in the period in which the change occurs. Additionally, future changes in tax laws in the jurisdictions in which the Company operates could limit the ability of the Company to obtain tax deductions in future periods. Measurement of share Share values, forfeiture rates and the future attainment of performance criteria. based payments recorded pursuant to share based payments ‐ ‐ ‐ based compensation plans are subject to estimated fair Business combinations Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of exploration and evaluation assets and petroleum and natural gas assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill in the purchase price allocation. Future net earnings can be affected as a result of changes in future depletion and depreciation, asset impairment or goodwill impairment. Contingencies By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently involves the exercise of significant judgment and estimates of the outcome of future events. Financial Reporting Update International Financial Reporting Standards (“IFRS”) Publicly accountable enterprises are required to apply IFRS, in full and without modification, for financial periods beginning on January 1, 2011. Private enterprises are not yet required to apply IFRS, however Petrus has elected to adopt the standards. Given that 2011 is Petrus’ first year of operations, Petrus had no financial statements balances to restate as at January 1, 2010. As a result, a reconciliation of Canadian GAAP to IFRS was not required. These audited financial statements present the Company’s financial results of operations issued under International Financial Reporting Standards (“IFRS”) as at and for the period ended December 31, 2011. These audited financial statements have been prepared by management using accounting policies consistent with IFRS as issued by the 2011 | MD&A 15 International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”). Financial Instruments Financial instruments are comprised of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities. The fair values of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate their carrying amounts due to their short-term maturities. Disclosure Controls and Procedures Disclosure controls and procedures have been designed to ensure that information required to be disclosed by Petrus is accumulated and communicated to the Company’s management as appropriate to allow timely decisions regarding required disclosures. Petrus’ President and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective to provide reasonable assurance that material information related to Petrus, is made known to them by others within the Company. Internal Control over Financial Reporting (“ICFR”) Petrus’ President and Chief Financial Officer have designed internal controls over financial reporting related to the Company to provide reasonable assurance regarding the reliability of Petrus’ financial reporting and preparation of financial statements for external purposes in accordance with GAAP. It should be noted that while Petrus’ President and Chief Financial Officer believe that the Company’s disclosure and internal control procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure and internal control procedures 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. Risk Factors There are a number of risk factors facing companies that participate in the Canadian oil and gas industry. A summary of certain risk factors relating to Petrus’ business are disclosed below. Risks to Petrus’ Revenues Volatility of Commodity Prices and Markets Petrus’ financial performance and condition are substantially dependent on the prevailing prices of oil and natural gas which are unstable and subject to fluctuation. Fluctuations in oil or natural gas prices could have an adverse effect on Petrus’ operations and financial condition and the value and amount of its reserves. Prices for crude oil fluctuate in response to global supply of and demand for oil, market performance and uncertainty and a variety of other factors which are outside the control of Petrus including, but not limited, to the world economy and OPEC's ability to adjust supply to world demand, government regulation, political stability and the availability of alternative fuel sources. Natural gas prices are influenced primarily by factors within North America, including North American supply and demand, economic performance, weather conditions and availability and pricing of alternative fuel sources. Decreases in oil and natural gas prices typically result in a reduction of Petrus’ net production revenue and may change the economics of producing from some wells, which could result in a reduction in the volume of Petrus’ reserves. Any further substantial declines in the prices of crude oil or natural gas could also result in delay or cancellation of existing or future drilling, development or construction programs or the curtailment of production. All of these factors could result in a material decrease in Petrus’ net production revenue, cash flows and profitability causing a reduction in its oil and gas acquisition and development activities. In addition, bank borrowings available to Petrus will in part be determined by Petrus’ borrowing base. A sustained material decline in prices from historical average prices could further reduce such borrowing base, therefore reducing the bank credit available and could require that a portion of its bank debt be repaid. 2011 | MD&A 16 Petrus may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, Petrus will not benefit from such increases. Delay in Cash Receipts and Credit Worthiness of Counterparties In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of Petrus’ properties, and by the operator to Petrus, payments between any of such parties may also be delayed by restrictions imposed by lenders, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, blowouts or other accidents, recovery by the operator of expenses incurred in the operation of Petrus’ properties or the establishment by the operator of reserves for such expenses. In addition, the insolvency or financial impairment of any counterparty owing money to Petrus, including industry partners and marketing agents, could prevent Petrus from collecting such debts. Substantial Capital Requirements, Liquidity Petrus may have to make substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. If revenues or reserves decline, Petrus may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. Moreover, future activities may require Petrus to alter its capitalization significantly. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on its financial condition, results of operations or prospects. Exploration, Development and Production Risks Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of Petrus depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, any existing reserves the Company may have at any particular time, and the production therefrom will decline over time as such existing reserves are exploited. A future increase in the Company's reserves will depend not only on its ability to explore and develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. No assurance can be given that the Company will be able to continue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, management of Petrus may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. There is no assurance that further commercial quantities of oil and natural gas will be discovered or acquired by the Company. Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. Oil and natural gas exploration operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering and oil spills, each of which could result in substantial damage to oil and natural gas wells, producing facilities, other property and the environment or in 2011 | MD&A 17 personal injury. In accordance with industry practice, Petrus is not fully insured against all of these risks, nor are all such risks insurable. Although Petrus maintains liability insurance in an amount which it considers adequate, the nature of these risks is such that liabilities could exceed policy limits, in which event Petrus could incur significant costs that could have a materially adverse effect upon its financial condition. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations. Project Risks The Company manages a variety of projects in the conduct of its business. Project delays may delay expected revenues from operations. Significant project cost over-runs could make a project uneconomic. The Company's ability to execute projects and market oil and natural gas depends upon numerous factors beyond The Company's control, including: • • • • • • • • • • • • • the availability of processing capacity; the availability and proximity of pipeline capacity; the availability of storage capacity; the supply of and demand for oil and natural gas; the availability of alternative fuel sources; the effects of inclement weather; the availability of drilling and related equipment; unexpected cost increases; accidental events; currency fluctuations; changes in regulations; the availability and productivity of skilled labour; and the regulation of the oil and natural gas industry by various levels of government and governmental agencies. Because of these factors, Petrus could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that it produces. Reserve Replacement Petrus’ future oil and natural gas reserves and production and the cash flows to be derived therefrom are highly dependent on successfully acquiring or discovering new reserves. Without the continual addition of new reserves, any existing reserves Petrus may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in reserves will depend not only on Petrus’ ability to develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. There can be no assurance that Petrus’ future exploration and development efforts will result in the discovery and development of additional commercial accumulations of oil and natural gas. Operational Dependence Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to Petrus and may delay exploration and development activities. To the extent Petrus will not be the operator of its oil and natural gas properties, it will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or control the activities of the operators. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent. 2011 | MD&A 18 In addition, the success of Petrus will be largely dependent upon the performance of its management and key employees. Petrus does not have any key man insurance policies and, therefore, there is a risk that the death or departure of any member of management or any key employee could have a material adverse effect on the Company. Petrus’ ability to market oil and natural gas from its wells also depends upon numerous other factors beyond its control, including, among other things, the availability of natural gas processing and storage capacity, the availability of pipeline capacity, the price of oilfield services and the effects of inclement weather. Because of these factors, Petrus may be unable to market some or all of the oil and natural gas it produces or to obtain favorable prices for the oil and natural gas it produces. Reserve Estimates There are numerous uncertainties inherent in evaluating quantities of reserves and the net present value of future net revenue to be derived therefrom, including many factors beyond the control of Petrus. The reserves information contained in the GLJ Report and set forth herein, including information respecting the net present value of future net revenue from reserves, represents an estimate only. This estimate is based on number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of oil and natural gas, operating costs and royalties and other government levies that may be imposed over the producing life of the reserves. These assumptions were based on price forecasts in use at the date the GLJ Report was prepared and many of these assumptions are subject to change and are beyond the control of Petrus. Ultimately, the actual reserves attributable to Petrus’ properties will vary from the estimates contained in the GLJ Report and those variations may be material and affect the market price of the Common shares. Insurance Petrus’ involvement in the exploration for and development of oil and natural gas properties may result in the Company becoming subject to liability for pollution, blow outs, property damage, personal injury or other hazards. Although Petrus maintains insurance consistent with prudent industry practice, it is not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms. Accordingly, Petrus’ properties may be subject to liability due to hazards that cannot be insured against, or that have not been insured against due to prohibitive premium costs or for other reasons. It is also possible that changing regulatory requirements or emerging jurisprudence could render such insurance of less benefit to Petrus. The payment of any uninsured liabilities would reduce the funds available to Petrus. Competition There is strong competition relating to all aspects of the oil and natural gas industry. Petrus will actively compete for capital, skilled personnel, undeveloped land, reserve acquisitions, access to drilling rigs, service rigs and other equipment, access to processing facilities and pipeline and refining capacity, and in all other aspects of its operations with a substantial number of other organizations, many of which may have greater technical and financial resources than Petrus. Some of those organizations not only explore for, develop and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a world-wide basis and as such have greater and more diverse resources on which to draw. Petrus’ ability to increase reserves and production in the future will depend not only on its ability to develop its present properties, but also on its ability to select and acquire suitable producing properties or prospects for exploratory drilling. Risks Associated with Government Regulation Regulatory Oil and natural gas operations (exploration, production, pricing, marketing, transportation and royalty rates) are subject to extensive controls and regulations imposed by various levels of government, which may be amended from 2011 | MD&A 19 time to time. Petrus’ oil and natural gas operations may also be subject to compliance with federal, provincial and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. Governments may regulate or intervene with respect to price, taxes, royalties and the exportation of oil and natural gas. Such regulations may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for natural gas and crude oil and increase the Company’s costs, any of which may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects. In order to conduct oil and gas operations, Petrus will require licenses from various governmental authorities. There can be no assurance that the Company will be able to obtain all of the licenses and permits that may be required to conduct operations that it may wish to undertake. Changes to the regulation of the oil and gas industry in jurisdictions in which Petrus operates may adversely impact Petrus’ ability to economically develop existing reserves and add new reserves. Environmental Concerns Many aspects of the oil and natural gas business present environmental risks and hazards, including the risk that Petrus may be in noncompliance with an environmental law, regulation, permit, licence, or other regulatory approval, possibly unintentionally or without knowledge. Such risks may expose Petrus to fines or penalties, third party liabilities or to the requirement to remediate, which could be material. The operational hazards associated with possible blowouts, accidents, oil spills, gas leaks, fires, or other damage to a well or a pipeline may require Petrus to incur costs and delays to undertake corrective actions, could result in environmental damage or contamination or could result in serious injury or death to employees, consultants, contractors or members of the public, creating the potential for significant liability to Petrus. Also, the occurrence of any such incident could damage Petrus’ reputation in the surrounding communities and make it more difficult for Petrus to pursue its operations in those areas. Compliance with environmental laws and regulations could materially increase Petrus’ costs. Petrus may incur substantial capital and operating costs to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, Petrus may be required to incur significant costs to comply with future federal or provincial greenhouse gas emissions reduction requirements or other regulations, if enacted. Abandonment and Reclamation Costs Petrus will be responsible for compliance with terms and conditions of environmental and regulatory approvals and all laws and regulations regarding abandonment and reclamation in respect of its properties, which abandonment and reclamation costs may be substantial. A breach of such legislation or regulations may result in the imposition of fines and penalties, including an order for cessation of operations at the site until satisfactory remedies are made. Net Asset Value Petrus’ net asset value will vary depending upon a number of factors beyond the control of Petrus’ management, including oil and natural gas prices. The market price of the common shares is also determined by a number of factors which are beyond the control of management and such market price may be greater than or less than the net asset value of Petrus. Permits and Licenses The operations of Petrus may require licenses and permits from various governmental authorities. There can be no assurance that Petrus will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development at its projects. Further, if the Company or the holder of the license or lease fails to meet the specific requirement of a license or lease, the license or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each license or lease will be met. The termination or expiration of the 2011 | MD&A 20 Company’s licenses or leases or the working interests relating to a license or lease may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects. Title to Properties Although title reviews will be done according to industry standards prior to the purchase of most oil and natural gas producing properties or the commencement of drilling wells as determined appropriate by management, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat a claim of Petrus which could result in a reduction of the revenue received by Petrus. ADVISORIES Basis of Presentation Financial data presented below have largely been derived from the Company’s audited financial statements for the period of inception to December 31, 2011, prepared in accordance with International Financial Reporting Standards (“IFRS”). Accounting policies adopted by the Company are set out in Note 3 to the audited financial statements for the period of inception to December 31, 2011. The reporting and the measurement currency is the Canadian dollar. All financial information is expressed in Canadian dollars, unless otherwise stated. Forward Looking Statements Certain information regarding Petrus set forth in this document, including management’s assessment of the Company’s future plans and operations, contains forward-looking statements WITHIN THE MEANING OF APPLICABLE SECURITIES LAW, that involve substantial known and unknown risks and uncertainties. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. Such statements represent Petrus’ internal projections, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital investment, anticipated future debt, production, revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. These statements are only predictions and actual events or results may differ materially. Although Petrus believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Petrus’ actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Petrus. In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: the size of, and future net revenues from, crude oil, NGL (natural gas liquids) and natural gas reserves; future prospects; the focus of and timing of capital expenditures; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; access to debt and equity markets; projections of market prices and costs; the performance characteristics of the Company’s crude oil, NGL and natural gas properties; crude oil, NGL and natural gas production levels and product mix; Petrus’ future operating and financial results; capital investment programs; supply and demand for crude oil, NGL and natural gas; future royalty rates; drilling, development and completion plans and the results therefrom; future land expiries; dispositions and joint venture arrangements; amount of operating, transportation and general and administrative expenses; treatment under governmental regulatory regimes and tax laws; estimated tax pool balances and anticipated IFRS elections and the impact of the conversion to IFRS. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future. These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company’s control, including the impact of general economic conditions; volatility in market prices for crude oil, NGL and natural gas; industry conditions; currency fluctuation; imprecision of reserve estimates; liabilities inherent in crude oil and natural gas operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management; 2011 | MD&A 21 changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources; completion of the financing on the timing planned and the receipt of applicable approvals; and the other risks. With respect to forward-looking statements contained in this MD&A, Petrus has made assumptions regarding: future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the impact of increasing competition; conditions in general economic and fi nancial markets; availability of drilling and related equipment and services; effects of regulation by governmental agencies; and future operating costs. Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide shareholders with a more complete perspective on Petrus’ future operations and such information may not be appropriate for other purposes. Petrus’ actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that the Company will derive therefrom. Readers are cautioned that the foregoing lists of factors are not exhaustive. These forward-looking statements are made as of the date of this MD&A and the Company disclaims any intent or obligation to update any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. BOE Presentation The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent (“BOE”) basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved measurement of results and comparisons with other industry participants. Petrus uses the 6:1 BOE measure which is the approximate energy equivalency of the two commodities at the burner tip. However, BOE’s do not represent an economic value equivalency at the wellhead and therefore may be a misleading measure if used in isolation. 2011 | MD&A 22 INDEPENDENT AUDITORS’ REPORT To the Shareholders of Petrus Resources Ltd.: We have audited the accompanying financial statements of Petrus Resources Ltd., which comprise the balance sheet as at December 31, 2011, and the statements of net loss and comprehensive loss, changes in shareholders’ equity and cash flows for the period from inception on December 13, 2010 to December 31, 2011, and a summary of significant accounting policies and other explanatory information. Management's responsibility for the financial statements Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error. Auditors’ responsibility Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained in our audit is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the financial statements present fairly, in all material respects, the balance sheet of Petrus Resources Ltd. as at December 31, 2011 and its financial performance and its cash flows for the period from inception on December 13, 2010 to December 31, 2011 in accordance with International Financial Reporting Standards. Calgary, Canada May 7, 2012 Chartered accountants 2011 | Annual Report 1 BALANCE SHEET (AUDITED) (Expressed in Canadian dollars) As at ASSETS Current Cash and cash equivalents Deposits and prepaid expenses Accounts receivable Non-current Exploration and evaluation assets (note 5) Property, plant and equipment (note 6) LIABILITIES Current Accounts payable and accrued liabilities Flow-through share premium liability (note 10) Non-Current Decommissioning obligation (note 9) Shareholders’ Equity Share capital (note 10) Contributed surplus Deficit See accompanying notes to the financial statements Commitments (note 21) Subsequent events (note 22) Approved by the Board of Directors, (signed) “Don T. Gray” Don T. Gray Executive Chairman December 31, 2011 7,786,788 396,657 3,635,358 11,818.803 7,232,470 40,089,044 47,321,514 59,140,317 4,328,105 979,856 5,307,961 3,652,999 8,960,960 51,018,159 32,391 (871,193) 50,179,357 59,140,317 (signed) “Patrick Arnell” Patrick Arnell Director 2011 | Annual Report 2 STATEMENT OF NET LOSS AND COMPREHENSIVE LOSS (AUDITED) (Expressed in Canadian dollars, except for share information) REVENUE Oil and natural gas revenue Royalties Oil and natural gas revenue, net of royalties Other income EXPENSES Operating (note 17) Transportation expenses General and administrative (note 18) Share-based compensation (note 11) Finance (note 9) Depletion and depreciation (note 6) NET LOSS BEFORE INCOME TAXES Deferred income tax expense (note 15) TOTAL NET LOSS AND COMPREHENSIVE LOSS Net loss per common share (note 13) Basic and diluted See accompanying notes to the financial statements Period of inception to December 31, 2011 1,976,817 444,757 1,532,060 150,923 1,682,983 1,138,867 87,302 660,640 22,674 17,960 626,733 2,554,176 (871,193) — (871,193) (0.08) 2011 | Annual Report 3 STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY (AUDITED) (Expressed in Canadian dollars) Balance at inception Net loss Issuance of common shares Premium liability of flow-through shares Share-based compensation expensed Share-based compensation capitalized Share issue costs Tax benefit of share issue costs Deferred tax benefits (note 15) Balance, December 31, 2011 See accompanying notes to the financial statements Share Capital Contributed Surplus — — 54,204,418 (1,188,386) — — (2,206,403) 584,697 (376,167) 51,018,159 — — — — 22,674 9,717 — — — 32,391 Retained Earnings (Deficit) — (871,193) — — — — — — — (871,193) Total — (871,193) 54,204,418 (1,188,386) 22,674 9,717 (2,206,403) 584,697 (376,167) 50,179,357 2011 | Annual Report 4 STATEMENT OF CASH FLOWS (AUDITED) (Expressed in Canadian dollars) Funds generated by (used in): OPERATING ACTIVITIES Net loss Adjust items not affecting cash: Share-based compensation Finance expenses Depletion and depreciation Change in operating non-cash working capital (note 16) Funds used in operations FINANCING ACTIVITIES Issuance of common shares (note 10) Share issue costs (note 10) Bridge financing issuance (notes 8 and 10) Bridge financing repayment (notes 8 and 10) Change in financing non-cash working capital (note 16) Funds generated by financing activities INVESTING ACTIVITIES Property and equipment acquisitions (note 4) Exploration and evaluation asset expenditures (note 5) Petroleum and natural gas property expenditures (note 6) Other capital expenditures (note 6) Change in investing non-cash working capital (note 16) Funds used in investing activities Increase (decrease) in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period See accompanying notes to the financial statements Period of inception to December 31, 2011 (871,193) 22,674 17,960 626,733 (203,826) (635,422) (839,248) 49,200,418 (2,206,403) 12,000,000 (6,996,000) 160,037 52,158,052 (41,979,444) (1,856,926) (252,472) (214,649) 771,475 (43,532,016) 7,786,788 — 7,786,788 NOTES TO THE FINANCIAL STATEMENTS 1. NATURE OF THE ORGANIZATION Petrus Resources Ltd. (“Petrus” or the “Company”) is a privately held entity which was incorporated under the laws of the Province of Alberta on December 13, 2010. These financial statements report the period of inception of December 13, 2010, to December 31, 2011. The principal undertaking of Petrus is the investment in energy business-related assets. The operations of the Company consist of the acquisition, development, exploration and exploitation of these assets. It conducts many of its activities jointly with others. These financial statements reflect only the Company’s share of these jointly controlled assets and its proportionate share of the relevant revenue and related costs. There is no comparable financial information for the prior periods as Petrus did not commence operations until 2011. The Company’s head office is located at 4210, 525 8th Avenue SW, Calgary, Alberta Canada. 2. BASIS OF PRESENTATION (a) Statement of Compliance These audited financial statements have been prepared by management using accounting policies consistent with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”). (b) Measurement Basis These audited financial statements were prepared on the basis of historical cost and are presented in Canadian dollars. (c) Critical Accounting Estimates and Sources of Judgment The timely preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of the financial statements are outlined below. ‐ Depletion and reserve estimates Petroleum and natural gas assets are depleted on a unit of production basis at a rate calculated by reference to proved and probable reserves determined in accordance with National Instrument 51 101 - Standards of Disclosure 101”). The calculation incorporates the estimated future cost of developing and for Oil and Gas Activities (“NI 51 extracting those reserves. Proved and probable reserves are estimated using independent reservoir engineering reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. Reserves estimates, although not reported as part of the Company’s financial statements, can have a significant effect on net income (loss), assets and liabilities as a result of their impact on depletion and depreciation, decommissioning liabilities, deferred taxes, asset impairments and business combinations. Independent reservoir engineers perform evaluations of the Company’s petroleum and natural gas reserves on an annual basis. The estimation of reserves is an inherently complex process requiring significant judgment. Estimates of economically recoverable petroleum and natural gas reserves are based upon a number of variables and assumptions such as geoscientific interpretation, production forecasts, commodity prices, costs and related future cash flows, all of which may vary considerably from actual results. These estimates are expected to be revised upward or downward over time, as additional information such as reservoir performance becomes available or as economic conditions change. ‐ 2011 | Annual Report 6 Impairment indicators and cash-generating units For purposes of impairment testing, petroleum and natural gas assets are aggregated into cash generating units (“CGU’s”), based on separately identifiable and largely independent cash inflows. The determination of the Company’s CGU’s is subject to judgment. ‐ ‐ ‐ in The recoverable amounts of CGU’s and individual assets have been determined based on the higher of the value use calculations and fair values less costs to sell. These calculations require the use of estimates and assumptions, including the discount rate, future petroleum and natural gas prices, expected production volumes and anticipated recoverable quantities of proved and probable reserves. These assumptions are subject to change as new information becomes available and changes in economic conditions take place. Changes may impact the estimated life of the field and economical reserves recoverable and may require a material adjustment to the carrying value of petroleum and natural gas assets. The Company monitors internal and external indicators of impairment relating to its tangible assets. Technical feasibility and commercial viability of exploration and evaluation assets The determination of technical feasibility and commercial viability, based on the presence of proved and probable reserves, results in the transfer of assets from exploration and evaluation assets to property, plant and equipment. As discussed above, the estimate of proved and probable reserves is inherently complex and requires significant judgment. Thus any material change to reserve estimates could affect the technical feasibility and commercial viability of the underlying assets. Decommissioning obligation At the end of the operating life of the Company’s facilities and properties and upon retirement of its petroleum and natural gas assets, decommissioning costs will be incurred by the Company. This requires judgment regarding abandonment date, future environmental and regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the removal cost and discount rates to determine the present value of these cash flows. Income taxes Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in income or loss both in the period of change, which would include any impact on cumulative provisions, and in future periods. Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a judgment as to whether or not there will be sufficient taxable income available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in income or loss in the period in which the change occurs. Additionally, future changes in tax laws in the jurisdictions in which the Company operates could limit the ability of the Company to obtain tax deductions in future periods. Measurement of share Share values, forfeiture rates and the future attainment of performance criteria. based compensation recorded pursuant to share based compensation ‐ ‐ ‐ based compensation plans are subject to estimated fair Business combinations Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of exploration and evaluation assets and petroleum and natural gas assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities 2011 | Annual Report 7 and goodwill in the purchase price allocation. Future net earnings can be affected as a result of changes in future depletion and depreciation, asset impairment or goodwill impairment. Contingencies By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently involves the exercise of significant judgment and estimates of the outcome of future events. 3. SIGNIFICANT ACCOUNTING POLICIES (a) Cash and cash equivalents The Company’s cash and cash equivalents consist of deposits held in the Company’s chequing account as well as various guaranteed investment certificates with maturities no greater than 90 days. (b) Revenue recognition Revenue from the sale of petroleum and natural gas is recognized when volumes are delivered and title passes to an external party at contractual delivery points and are recorded gross of transportation charges incurred by the Company. The costs associated with the delivery, including transportation and production-based royalty expenses, are recognized in the same period in which the related revenue is earned and recorded. Royalty income is recognized as it accrues in accordance with the terms of the respective overriding royalty agreements. Other income is recognized as it is earned which includes interest income as well as processing income. (c) Property, plant and equipment The Company’s property, plant and equipment is comprised of petroleum and natural gas assets and corporate assets. Capitalization Petroleum and natural gas assets are measured at cost less accumulated depletion and depreciation and accumulated impairment losses, if any. Petroleum and natural gas assets consists of the purchase price and costs directly attributable to bringing the asset to the location and condition necessary for its intended use. Petroleum and natural gas assets include developing and producing interests such as land acquisitions, geological and geophysical costs, facility and production equipment, other directly attributable costs and the initial estimate of the costs of dismantling and removing an asset and restoring the site on which it was located. Subsequent costs Costs incurred subsequent to the determination of technical feasibility and commercial viability are recognized as developing and producing petroleum and natural gas interests when they increase the future economic benefits embodied in the specific asset to which they relate. Such capitalized petroleum and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The cost of day-to-day servicing of an item of petroleum and natural gas assets is expensed in income or loss as incurred. Petroleum and natural gas assets are derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising from the disposal of an asset, determined as the difference between the net disposal proceeds and the carrying amount of the asset, is recognized in income or loss. Leased assets Other leases are capital leases, which are recognized on the Company’s balance sheet. Petrus records the payments made in accordance with the lease as a reduction to the obligation recorded. Depletion and depreciation The costs related to area cost centres for petroleum and natural gas properties, including related pipelines and facilities, are depleted using a unit production method based on the commercial proved and probable reserves allocated to its CGU. of ‐ ‐ 2011 | Annual Report 8 Petroleum and natural gas assets are not depleted until production commences. This depletion calculation includes actual production in the period and total estimated proved and probable reserves attributable to the assets being depleted, taking into account total capitalized costs plus estimated future development costs necessary to bring those reserves into production. Relative volumes of reserves and production (before royalties) are converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. Proved and probable reserves are estimated using independent reservoir engineering reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. Corporate assets are stated in the statement of financial position at cost less accumulated depreciation. Depreciation is calculated on a reducing balance method so as to write off the cost of these assets, less estimated residual values, over their estimated useful lives. The useful lives of the Company’s corporate assets are as follows: Corporate Asset Years Office equipment, furniture and fixtures Computer Hardware Computer Software Leasehold Improvements 5 2 1 10 The expected useful lives of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively. Impairment The carrying amounts of property, plant and equipment are grouped into CGU’s and the CGU’s are reviewed quarterly for indicators of impairment. Indicators are events or changes in circumstances that indicate that the carrying amount may not be recoverable. If indicators of impairment exist, the recoverable amount of the CGU is estimated. If the carrying amount of the CGU exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income (loss). The assessment for impairment entails comparing the carrying value of the CGU with its recoverable amount: that is, the higher of fair value, less costs to sell, and value in use. Each CGU is identified in accordance with IAS 36, Impairment of Assets. Petrus’ property, plant and equipment are grouped into CGU’s based on separately identifiable and largely independent cash inflows considering geological characteristics, shared infrastructure and exposure to market risks. Estimates of future cash flows used in the calculation of the recoverable amount are based on reserve evaluation reports prepared by independent reservoir engineers. use. Fair value, less costs to The recoverable amount is the higher of fair value, less costs to sell, and the value sell, is derived by estimating the discounted after tax future net cash flows. Discounted future net cash flows are ‐ based on forecasted commodity prices and costs over the expected economic life of the reserves and discounted using market use is assessed using the expected future cash flows discounted at a pre Impairments of property, plant and equipment are only reversed when there is significant evidence that the impairment has been reversed, but only to the extent of what the carrying amount would have been had no impairment been recognized. based rates to reflect a market participant’s view of the risks associated with the assets. Value tax rate. in in ‐ ‐ ‐ ‐ ‐ ‐ (d) Exploration & evaluation assets Capitalization All costs incurred after the rights to explore an area have been obtained, such as geological and geophysical costs, other direct costs of exploration (drilling, testing and evaluating the technical feasibility and commercial viability of 2011 | Annual Report 9 extraction) and appraisal and including any directly attributable general and administration costs and share payments, are accumulated and capitalized as exploration and evaluation assets. based ‐ Certain costs incurred prior to acquiring the legal rights to explore are charged directly to net income (loss). Amortization Exploration and evaluation costs are not amortized prior to the conclusion of appraisal activities. At the completion of appraisal activities, if technical feasibility is demonstrated and commercial reserves are discovered, then the carrying value of the relevant exploration and evaluation asset will be reclassified as a petroleum and natural gas asset into the CGU to which it relates, but only after the carrying value of the relevant exploration and evaluation asset has been assessed for impairment and, where appropriate, its carrying value adjusted. Technical feasibility and commercial viability are considered to be demonstrable when proved or probable reserves are determined to exist. If it is determined that technical feasibility and commercial viability have not been achieved in relation to the exploration and evaluation assets appraised, all other associated costs are written down to the recoverable amount in net income (loss). Expired land leases included as undeveloped land in exploration and evaluation assets are recognized in exploration and evaluation cost in net income (loss) upon expiry. Impairment If and when facts and circumstances indicate that the carrying value of an exploration and evaluation asset may exceed its recoverable amount, an impairment review is performed. For exploration and evaluation assets, when there are such indications, an impairment test is carried out by grouping the exploration and evaluation assets with property, plant and equipment CGU’s to which they belong for impairment testing. The equivalent combined carrying value of the CGU’s is compared against the recoverable amount of the CGU’s and any resulting impairment loss is written off to net income (loss). The recoverable amount is the greater of fair value, less costs to sell, or value use. in (e) Business combinations ‐ ‐ Business combinations are accounted for using the acquisition method. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured at their fair values at the acquisition date. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the acquisition date. The excess of the cost of the acquisition over the fair value of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of the acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognized immediately in net income (loss). Transaction costs associated with a business combination are expensed as incurred. (f) Decommissioning obligations The Company’s activities give rise to dismantling, decommissioning and reclamation requirements. Costs related to these abandonment activities are estimated by management in consultation with the Company’s engineers based on risk-adjusted current costs which take into consideration current technology in accordance with existing legislation and industry practices. Decommissioning obligations are measured at the present value of the best estimate of expenditures required to settle the obligations at the reporting date. When the fair value of the liability is initially measured, the estimated cost, discounted using a risk-free rate, is capitalized by increasing the carrying amount of the related petroleum and natural gas assets. The increase in the provision due to the passage of time, or accretion, is recognized as a finance expense. Increases and decreases due to revisions in the estimated future cash flows are recorded as adjustments to the carrying amount of the related petroleum and natural gas assets. Actual costs incurred upon settlement of the liability are charged against the obligation to the extent that the obligation was previously established. The carrying amount capitalized in petroleum and natural gas assets is depleted in accordance 2011 | Annual Report 10 with the Company’s depletion and depreciation policy. The Company reviews the obligation at each reporting date and revisions to the estimated timing of cash flows, discount rates and estimated costs will result in an increase or decrease to the obligations. Any difference between the actual costs incurred upon settlement of the obligation and recorded liability is recognized as an increase or reduction in income. (g) Finance expenses Finance expense may be comprised of interest expense on borrowings and accretion of the discount on decommissioning obligations. (h) Financial instruments Non-derivative financial instruments Non-derivative financial instruments comprise cash and cash equivalents, accounts receivables, accounts payable and accrued liabilities and outstanding credit facilities. Non-derivative financial instruments are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured based on their classification. The Company has made the following classifications: • Cash and cash equivalents are classified as financial assets at fair value, showing separately (i) those designated as such upon initial recognition and (ii) those classified as held for trading in accordance with IAS 39 Financial Instruments: Recognition and Measurement. • • Accounts receivable are classified as loans and receivables and are measured at amortized cost using the effective interest method. Typically, the fair value of these balances approximates their carrying value due to their short term to maturity. Accounts payable and accrued liabilities and outstanding credit facilities are classified as other liabilities and are measured at amortized cost using the effective interest method. Due to the short term nature of accounts payable and accrued liabilities, their carrying values approximate their fair values. The Company’s outstanding credit facilities bear interest at a floating rate and accordingly the fair market value approximates the carrying value. (i) Share capital Common shares are classified as equity. Incremental costs directly attributable to the issuance of common shares are recognized as a reduction in share capital, net of any tax effects. (j) Flow-through shares The resources expenditure deductions for income tax purposes related to exploratory activities funded by flow-through shares are renounced to investors in accordance with tax legislation. Upon issuance of a flow-through share, a liability is recognized representing the premium paid on flow-through common shares over regular common shares. This liability is reduced as the expenditures are incurred and tax attributes are renounced. The difference between the initial liability and the deferred tax liability created is recorded as a deferred tax expense. (k) Income taxes The Company’s income tax expense is comprised of current and deferred tax. Income tax expense is recognized through income or loss except to the extent that it relates to items recognized directly in equity, in which case the related income taxes are also recognized in equity. Current tax is the expected tax payable on taxable income for the period, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years. Deferred tax is recognized on temporary differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax basis used in the computation of taxable income. Deferred tax liabilities are generally recognized for all taxable temporary differences. Deferred tax assets are generally recognized for all deductible temporary differences to the extent that it is probable that taxable income will be available against which those deductible temporary differences can be utilized. The carrying amount of deferred tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered. 2011 | Annual Report 11 Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is expected to be settled or the asset realized, based on tax rates (and tax laws) that have been enacted or substantively enacted by the end of the reporting period. The measurement of deferred tax liabilities and assets reflects the tax consequences that would follow from the manner in which Petrus expects, at the end of the reporting period, to recover or settle the carrying amount of its assets and liabilities. (l) Joint interests Significantly all of the Company’s activities are conducted jointly with others through unincorporated joint ventures. The Company accounts for its share of the results and net assets of these Joint Ventures as jointly controlled assets. The audited financial statements include Petrus’ share of these jointly controlled assets and a proportionate share of the relevant revenue and related costs. (m) Share-based compensation The Company follows the fair value method of valuing stock option and performance warrant grants. Share based compensation expense is determined based on the estimated fair value of shares on the date of grant. Forfeitures are estimated at the grant date and are subsequently adjusted to reflect actual forfeitures. The expense is recognized over the service period, with a corresponding increase to contributed surplus. The Company capitalizes the qualifying portion of share-based compensation expense directly attributable to the exploration and development activities of exploration and evaluation assets and petroleum and natural gas assets, with a corresponding decrease to share based compensation expense. At the time the stock options or performance warrants are exercised, the issuance of common shares is recorded as an increase to shareholders’ capital and a corresponding decrease to contributed surplus. ‐ ‐ (n) Earnings per share Earnings per share are presented for basic and diluted earnings. Basic per share information is computed by dividing the net income (loss) for the period attributable to equity owners of the Company by the weighted average number of common shares outstanding during the period. The weighted average number of shares for fully diluted earnings per share information is calculated using the treasury stock method whereby it is assumed that proceeds obtained upon exercise of share warrants and stock options issued under the Company’s Stock Option Plan would be used to purchase common shares at the average market price during the period. The treasury stock method also assumes that the deemed proceeds related to unrecognized share based payments expense are used to repurchase shares at the average market price during the period. Under the treasury stock method, stock options and share warrants have a dilutive effect only when the average market price of the common shares during the period exceeds the exercise price of the options or warrants (they money stock options and share warrants is assumed at the beginning of the year or are "in date of issuance, if later. Should the Company have a loss for the period, stock options and share warrants would be anti dilutive and therefore will have no effect on the determination of loss per share. money"). Exercise of in the the ‐ ‐ ‐ ‐ ‐ ‐ (o) New standards and interpretations not yet adopted In November 2009, the International Accounting Standards Board (IASB) published IFRS 9 – Financial Instruments, which covers the classification and measurement of financial assets as part of its project to replace IAS 39 – Financial Instruments: Recognition and Measurement. In October 2010, the requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through earnings. If this option is elected, entities are required to reverse the portion of the fair value change due to credit risk out of earnings and recognize the change in other comprehensive income. IFRS 9 is effective for the Company on January 1, 2015. Early adoption is permitted and the standard is required to be applied retrospectively. In May 2011 the IASB issued four new standards. All are effective for annual periods beginning on or after January 1, 2015. IFRS 10 – Consolidated Financial Statements replaces IAS 27 – Consolidated and Separate Financial Statements. It introduces a new principle-based definition of control, applicable to all investees to determine the scope of consolidation. The standard provides the framework for consolidated financial statements and their preparation based on the principle of control. 2011 | Annual Report 12 IFRS 11 – Joint Arrangements replaces IAS 31 – Interests in Joint Ventures. IFRS 11 divides joint arrangements into two types, each having its own accounting model. A “joint operation” continues to be accounted for using proportionate consolidation, while a “joint venture” must be accounted for using equity accounting. This differs from IAS 31, in which there was the choice to use proportionate consolidation or equity accounting for joint ventures. A “joint operation” entails joint operators having rights to the assets and obligations for the liabilities relating to the arrangement. In a “joint venture”, the joint venturers have rights to the net assets of the arrangement, typically through their investment in a separate joint venture entity. IFRS 12 – Disclosure of Interests in Other Entities is a new standard, which combines all of the disclosure requirements for subsidiaries, associates and joint arrangements, as well as unconsolidated structured entities. IFRS 13 – Fair Value Measurement is a new standard meant to clarify the definition of fair value, provide guidance on measuring fair value and improve disclosure requirements related to fair value measurement. The Company is evaluating the impact of adopting the newly issued standards. 4. ACQUISITIONS On October 31, 2011 Petrus closed an acquisition of petroleum and natural gas properties for cash consideration of $42 million, net of adjustments. The transaction was accounted for as a business combination. Petrus recorded $5.2 million in exploration and evaluation assets for the value of undeveloped land and seismic, $36.8 million in property and equipment and $3.6 million of decommissioning liabilities were recognized in relation to the acquired properties. Acquisition costs of $36 thousand were charged to general and administrative expenses on the statement of net loss and comprehensive loss. The financial statements incorporate the operations of the properties beginning November 1, 2011. During the period November 1, 2011 to December 31, 2011, the Company recorded oil and natural gas revenue of $2 million and a net loss of $230 thousand related to the acquisition. The impact of this acquisition on revenue and net loss, as if acquired at inception, would have been incremental revenue of $10.3 million and an incremental net loss of $1.1 million, respectively. 5. EXPLORATION AND EVALUATION ASSETS Balance at inception Cash additions Capitalized general & administrative Acquisitions (note 4) Change in decommissioning provision Transfers to property, plant and equipment Balance, December 31, 2011 $ — 1,970,697 58,267 5,160,551 42,955 — 7,232,470 Depletion E&E assets consist of Petrus’ undeveloped land and exploration and development projects which are pending the determination of technical feasibility. Additions represent the Company’s share of costs incurred on E&E assets during the period. Exploration and evaluation assets are not subject to depletion. Capitalization of general & administrative expenses During the year ended December 31, 2011 the Company capitalized $58 thousand (2010 – Nil) of general & administrative expenses directly attributable to exploration activities. Included in this amount is non-cash related share-based compensation of $5 thousand. 2011 | Annual Report 13 Impairment The Company analyzed indicators of impairment in relation to its exploration and evaluation assets at December 31, 2011 to ensure the carrying value does not exceed fair value. Based on the analysis, Petrus concluded that its exploration and evaluation assets were not impaired at December 31, 2011. 6. PROPERTY, PLANT AND EQUIPMENT $ Balance at inception Cash additions Capitalized general & administrative Acquisitions (note 4) Transfers from exploration and evaluation assets Change in decommissioning provision Depletion & depreciation Balance, December 31, 2011 Cost — 246,532 58,267 36,818,894 — 3,592,084 — 40,715,777 Accumulated DD&A Net book value — — — — — — (626,733) (626,733) — 246,532 58,267 36,818,894 — 3,592,084 (626,733) 40,089,044 Depletion and Depreciation Estimated future development costs of $10.2 million associated with the development of the Company’s proved plus probable undeveloped reserves were included with the costs subject to depletion. Capitalization of general & administrative expenses During the year ended December 31, 2011 the Company capitalized $58 thousand of general & administrative expenses directly attributable to development activities. Included in this amount is non-cash related share-based compensation of $5 thousand. Impairment The Company performed an impairment test at December 31, 2011 to ensure the carrying value of its petroleum and natural gas assets is recoverable and does not exceed fair value. The petroleum and natural gas prices are based on December 31, 2011 commodity price forecasts of the Company’s independent reserve evaluators. Based on the impairment test, Petrus concluded that its petroleum and natural gas assets were not impaired at December 31, 2011. 7. REVOLVING CREDIT FACILITY As at December 31, 2011, the Company had a demand revolving credit facility of $22 million with a major Canadian lender. The credit facility was obtained for general corporate purposes as well as to provide bridge financing for the Acquisition which closed October 31, 2011. The facility is available on a revolving basis for a period until June 30, 2012 and then for a further year under the term out provisions. The initial term out date may be extended for further 364 day periods at the request of Petrus, subject to approval by the lender. The credit facility provides that advances may be made by way of direct Canadian advances (at an interest rate equal to the Bank of Canada prime rate plus 0.75% per annum), U.S. dollar advances (at an interest rate equal to the U.S. Base Rate plus 0.75% per annum), or bankers’ acceptances (at a stamping fee calculated on the face amount of the banker’s acceptance at a rate equal to 175 basis points per annum). ‐ The amount of the credit facility is subject to a borrowing base test performed on a semi-annual review by the lender, based primarily on reserves and using commodity prices estimated by the lender as well as other factors. The Company has provided security by way of a first floating charge (with right to fix) over all the present and after acquired property of the Company. A decrease in the borrowing base could result in a reduction to the available credit facility. The next semi- annual review of the credit facility is to take place on June 30, 2012. At December 31, 2011, the Company has not drawn against the credit facility. 2011 | Annual Report 14 8. BRIDGE TERM LOAN The Company utilized a senior, unsecured non-revolving term loan of $12 million in order to finance the October 31, 2011 business combination. The loan was repaid entirely on November 14, 2011 using cash of $7 million and issuing shares in conjunction with the Company’s private equity placement of $5 million. At December 31, 2011, the loan has been cancelled in conjunction with its repayment. 9. DECOMMISSIONING OBLIGATION The decommissioning liability was estimated based on the Company’s net ownership interest in all wells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The estimated future cash flows have been discounted using an average risk free rate of three percent and an inflation rate of two percent. The Company has estimated the net present value of the decommissioning obligations to be $3.7 million as at December 31, 2011 based on an undiscounted total future liability of $6.6 million. These payments are expected to be incurred over the operating lives of the assets. The following table reconciles the decommissioning liability: Balance at inception Acquisitions (note 4) Liabilities incurred Accretion expense Balance, December 31, 2011 10. SHARE CAPITAL December 31, 2011 — 3,592,084 42,955 17,960 3,652,999 Authorized The authorized share capital consists of an unlimited number of common voting shares without par value. Issued and Outstanding Common shares Balance at inception Common shares issued under private placement (1) Flow-through shares issued, net of premium (2) Common shares issued under private placement (3) Share issue costs Tax benefit of share issue costs Balance, December 31, 2011 Number of Shares Amount — 11,050,000 2,970,966 18,012,050 — — 32,033,016 — 11,050,000 5,941,932 36,024,100 (2,206,403) 208,530 51,018,159 Share Issuances (1) The Company completed its initial private equity placement on March 4, 2011 and 5,590,000 common shares were issued at a price of $1.00 per share for gross proceeds of $5,590,000. Subsequent additional closings related to the initial private equity placement ($1 per common share) occurred with an aggregate of 5,460,000 additional common shares issued at $1 per share for additional gross proceeds of $5,460,000. (2) The Company completed its second private equity placement on November 14, 2011. 2,970,966 flow-through shares were issued at a price of $2.40 per share for total gross proceeds of $7,130,318. Of the issuance price, $0.40 per share or $1,188,386 was determined to be the premium on the flow-through shares. As at December 31, 2011 the Company had spent $1,251,183 and therefore the liability outstanding at December 31, 2011 was reduced to $979,856. Petrus is committed to spending an additional $5.88 million on qualified exploration and development expenditures by December 31, 2012. Under National Instrument 45-102, the flow through shares issued November 14, 2011 are subject to a restricted hold period which expires March 15, 2012. 2011 | Annual Report 15 (3) On November 14, 2011 the Company also issued 17,338,550 common shares at a price of $2.00 per share for gross proceeds of $34,677,100. Subsequent additional closings related to this private equity placement ($2 per common share) occurred as follows: 458,500 common shares ($917,000 gross) on November 22, 2011; and 215,000 common shares ($430,000 gross) on December 31, 2011. Under National Instrument 45-102, the common shares issued November 14, 2011 are subject to a restricted hold period which expires March 15, 2012. The common shares issued in subsequent closings are subject to a restricted hold period which expires on March 23, 2011 (November 22, 2011 closing) and May 1, 2012 (December 31, 2011 closing). (4) 1,500,000 common shares ($3,000,000 gross proceeds) and 835,000 flow through shares ($2,004,000 gross proceeds) issued in conjunction with the November 14, 2011 private equity placement were issued to settle a portion of the bridge term loan as discussed in note 8. 11. SHARE BASED COMPENSATION ‐ The Company has a stock option plan (the “Plan”) in place whereby it may issue stock options and performance warrants to employees, consultants and directors of the Company. Upon exercise of the options or warrants the Company settles the obligation by issuing common shares of the Company and cash settlements are not required. The shares to be offered under the Plan consist of common shares of the Company’s authorized but unissued common shares. The aggregate number of shares issuable upon the exercise of all options granted under the Plan shall not exceed 20% of the issued and outstanding shares from time to time. If any option or warrant granted hereunder expires or terminates for any reason in accordance with the terms of the Plan without being exercised, the un-purchased shares subject thereto shall again be available for the purpose of this Plan. At December 31, 2011, 4,934,000 performance warrants were issued under the Company’s stock option plan. Performance Warrants Performance warrants are granted for a term of three years and vest based on three criteria, time (one third vest per year), market (one third vest as certain share price hurdles are achieved) and employment or service. The summary of performance warrant activity is presented below: Balance at inception Granted Exercised Forfeited or expired Balance, December 31, 2011 Exercisable, December 31, 2011 Number of warrants Weighted Average Exercise Price ($) 4,934,000 — — 4,934,000 — $2.00 — — $2.00 — The following tables summarize information about the performance warrants outstanding at December 31, 2011: Grant date December 19, 2011 Warrants Outstanding Warrants Exercisable Weighted average exercise price Weighted average remaining life (years) Number outstanding Weighted average exercise price Number exercisable 4,934,000 4,934,000 $2.00 $2.00 5 5 — — $2.00 $2.00 2011 | Annual Report 16 The fair value of each warrant granted of $0.36 per warrant is estimated on the date of grant using the Black pricing model with the following weighted average assumptions (at December 31, 2011): Fair value of warrants Risk free interest rate Expected life (years) Estimated volatility of underlying common shares (%) Estimated forfeiture rate Expected dividend yield (%) Scholes ‐ $0.36 1.36% 5 65% 20% 0% Petrus estimated the volatility of their underlying common shares by analyzing the volatility of peer group public companies with similar corporate structure, oil and gas assets and size. With respect to the market condition inherent in the warrants, Petrus estimated the probability of achieving the condition and applied the probability to each individual vesting tranche in order to fairly estimate the fair value of each warrant. The following table summarizes the Company’s share based compensation at December 31, 2011: Share Share Share ‐ ‐ Total share ‐ based compensation expensed in net loss based compensation capitalized to exploration and evaluation assets based compensation capitalized to property, plant and equipment ‐ based compensation 22,674 4,859 4,859 32,391 12. CAPITAL MANAGEMENT ‐ The Company’s general capital management policy is to maintain a sufficient capital base in order to manage its business to enable the Company to increase the value of its assets and therefore its underlying share value. The Company’s objectives when managing capital are (i) to manage financial flexibility in order to preserve the Company’s ability to meet financial obligations; (ii) maintain a capital structure that allows Petrus the ability to finance its growth using internally generated cashflow and (iii) to maintain a flexible capital structure which optimizes the cost of capital at an acceptable risk level and provides an optimal return to equity holders. In the management of capital, Petrus includes share capital and total net debt, which is made up of debt and working capital (current assets less current liabilities). Petrus manages its capital structure and makes adjustments in light of economic conditions and the risk characteristics of the underlying assets. In order to maintain or adjust the capital structure, Petrus may issue new equity, increase or decrease debt, adjust capital expenditures and acquire or dispose of assets. 13. EARNINGS PER SHARE AMOUNTS Basic earnings per share amounts are calculated by dividing net income (loss) for the period by the weighted average number of common shares outstanding during the period. The following table shows the calculation of basic and diluted earnings per share for the periods: Net income (loss) for the period Weighted average number of common shares Weighted average number of common shares – basic Dilutive effect of outstanding warrants Weighted average number of common shares – diluted Basic net income (loss) per share Diluted net income (loss) per share Period of inception to Dec. 31, 2011 $(871,193) 10,615,543 — 10,615,543 (0.08) (0.08) 2011 | Annual Report 17 At December 31, 2011, the market price of $2.00 of the Company’s shares was used to determine the dilutive effect of performance warrants. For the period ended December 31, 2011, all 4,934,000 warrants issued were anti-dilutive. At December 31, 2011 the Company had 32,033,016 common shares outstanding. 14. FINANCIAL INSTRUMENTS The Company’s financial instruments recognized on the financial statements consist of cash and cash equivalents, accounts receivable and accounts payable & accrued liabilities. The fair value of Petrus’ financial instruments were assessed and found to approximate their carrying amounts. Fair Value of Financial Instruments The fair value of Petrus’ financial instruments, approximate their carrying amounts due to their short terms to maturity or the indexed rate of interest on the bank debt: Financial Assets Loans and receivables: Cash and cash equivalents Accounts receivable Financial Liabilities Other Financial Liabilities: Accounts payable and accrued liabilities As at December 31, 2011 Carrying Amount Fair Value 7,786,788 3,635,358 7,786,788 3,635,358 4,328,105 4,328,105 The Company continues to monitor its trade and other receivables and its allowance for doubtful accounts. As at December 31, 2011, there have been no impairment issues. Risks associated with Financial Instruments Credit risk The Company may be exposed to certain losses in the event that counterparties to financial instruments fail to meet their obligations in accordance with agreed terms. The Company mitigates this risk by entering into transactions with highly rated major financial institutions and by routinely assessing the financial strength of its customers. At December 31, 2011, financial assets on the audited statement of financial position are comprised of cash and cash equivalents and accounts receivable. The maximum credit risk associated with these financial instruments is the total carrying value. The Company’s accounts receivable are with customers and joint venture partners in the petroleum and natural gas business and are subject to normal credit risk. Concentration of credit risk is mitigated by marketing the majority of the Company’s production to two purchasers under normal industry sale and payment terms. As is common in the petroleum and natural gas industry in western Canada, Petrus’ receivables relating to the sale of petroleum and natural gas are received on or about the 25th day of the following month. Of the $3.6 million of accounts receivable outstanding as at December 31, 2011 (all of which is less than 90 days old), $2.7 million is owed from four parties and was received in January 2012. The remaining amount of $800 thousand was related to normal operations of the Company and was received in 2012. No provision has been made for past due receivables as of December 31, 2011 as the Corporation has assessed there are no impaired receivables. Interest rate risk The Company is not currently exposed to interest rate risk as the Company did not have any amount outstanding against its credit facility. Liquidity risk Liquidity risk relates to the risk the Company will encounter difficulty in meeting obligations associated with its financial liabilities. The financial liabilities on its statement of financial position consist of accounts payable and accrued liabilities. 2011 | Annual Report 18 The Company anticipates it will continue to have adequate liquidity to fund its financial liabilities through its future cash flows. Market risk Market risk is the risk of uncertainty arising from movements of the market price of commodities and interest rates, including their impact on the future performance of the business. The market price movements that could have an adverse effect on the value of the Company’s future cash flows are primarily commodity price movements given that the Company is not drawn on its credit facility at December 31, 2011. For the period ended December 31, 2011, it is estimated that a $0.25/mcf decrease in the price of natural gas would have increased the net loss by $107 thousand. For the period ended December 31, 2011, it is estimated that a $5.00/CDN WTI/bbl decrease in the price of oil would have increased the net loss by $27 thousand. 15. DEFERRED INCOME TAXES At December 31, 2011, deferred income tax assets have not been recognized due to the uncertainty as to future realization. Management will review the carrying amount of deferred tax assets at the end of the next reporting period and determine if sufficient taxable income will be available to allow all or part of the asset to be recovered. Income (loss) before taxes Combined federal and provincial tax rate Computed “expected” tax expense (recovery) Increase/(decrease) in taxes resulting from: Permanent items Impact of flow-through shares Share issuance costs Change in rates Deferred tax benefits deemed not probable to be recovered Deferred tax expense (recovery) Effective tax rate Year ended December 31, 2011 (871,193) 26.5% (230,866) 6,619 331,563 (551,600) (6,075) 450,359 — 25.0% The Corporation had non-capital losses of approximately $2,495,207 which may be applied against future income for Canadian tax purposes. These noncapital losses expire in 2031. These losses have not been recorded in the Corporation’s records as they are deemed not probable to be recovered. The Corporation had tax allowances of approximately $5,859,400 which may be applied against future income for Canadian tax purposes. These allowances are not subject to expiry. These allowances have not been recorded in the Corporation’s records as they are deemed not probable to be recovered. 2011 | Annual Report 19 16. SUPPLEMENTAL CASH FLOW INFORMATION The following table reconciles the changes in non flows: ‐ cash working capital as disclosed in the interim statements of cash $ Source (use) in non-cash working capital: Accounts receivable Deposits and prepaid expenses Accounts payable and accrued liabilities Operating activities Financing activities Investing activities 17. OPERATING EXPENSES Period of inception to Dec. 31, 2011 (3,635,358) (396,657) 4,328,105 296,090 (635,422) 160,037 771,475 The Company’s operating expenses consist of $336 thousand of processing, gathering and compression charges and $803 thousand of other operating expenses incurred to operate the Company’s producing assets which were acquired October 31, 2011. 18. GENERAL AND ADMINISTRATIVE EXPENSES The Company’s general and administrative expenses consisted of the following expenditures: $ Salaries and benefits Subscriptions and licenses Office costs Legal, accounting and consulting Transaction costs (note 4) Capitalized general and administrative Period of inception to Dec. 31, 2011 408,485 36,589 132,578 153,429 36,376 (106,817) 660,640 19. KEY MANAGEMENT PERSONNEL The Company consider its directors and officers to be key management personnel. The following table outlines transactions with key management personnel: $ Salaries and wages Short term employee benefits Share based compensation Period of inception to Dec. 31, 2011 401,944 8,364 31,039 441,347 20. RELATED PARTY TRANSACTIONS Included in share issue costs are structuring fees of $359 thousand which relate to the Company’s initial financing. The fees were paid to a company controlled by a director of Petrus. The Company entered into a bridge financing agreement with a lender who is also a director of the Company. The bridge term loan was used to finance the Acquisition which Petrus closed October 31, 2011 prior to the November 2011 private equity placement. Prior to year end, the Company repaid the bridge loan (see note 8) and terminated the agreement. 2011 | Annual Report 20 21. COMMITMENTS AND CONTINGENCIES Provisions and Contingencies The Company’s provision for decommissioning obligations is presented in note 9. The Company is committed to incur exploration expenditures of $5.88 million on or before December 31, 2012, related to the Flow-through Share issuance completed on November 14, 2011, as indicated in note 10. Petrus may be subject to Part XII.6 tax based upon the prescribed rate, on the balance of exploration expenditures not yet incurred at the end of each month subsequent to January 31, 2012 however it is expected that the Company will satisfy the obligation during the first quarter of 2012. Petrus is the subject of litigation arising out of the termination of an officer of the Company. Damages claimed under this litigation are indeterminate however they may be material to the Company’s financial condition or results of operations. Petrus has made a provision for the estimated costs associated with this litigation based upon guidance provided by its legal counsel. The likelihood of success of the litigation is not yet known. The commitments for which the Company is responsible are as follows: Commitments (000s) Office equipment lease Capital commitments Corporate office lease Total commitments 22. SUBSEQUENT EVENTS Total < 1 year 1-3 years 4-5 years >5 years 20 10,696 3,294 14,010 5 5,296 271 5,572 10 5,400 631 6,041 5 — 661 666 — — 1,731 1,731 Financial derivative contracts Subsequent to December 31, 2011, the Company entered into the following commodity financial derivative contracts: Natural Gas Period Hedged Type Daily Volume February 1, 2012 to March 31, 2012 February 1, 2012 to December 31, 2012 April 1, 2012 to October 31, 2012 May 1, 2012 October 31, 2012 November 1, 2012 March 31, 2013 April 1, 2013 to October 31, 2013 Fixed price Costless collar Fixed price Fixed price Fixed price Costless collar 1,500 GJ 1,500 GJ 1,500 GJ 2,000 GJ 4,000 GJ 1,500 GJ Crude Oil Period Hedged Type Daily Volume Price (CAD) $2.71/GJ $2.70 - $2.95/GJ $2.77/GJ $2.25/GJ $2.25/GJ $2.50 - $3.02/GJ Price (USD) May 1, 2012 to December 31, 2012 Costless collar 75 Bbl WTI $95.00 - $106.55/Bbl Common share issuance On April 11, 2012 the Company issued 80,000 common shares at a price of $2.00 per share for gross proceeds of $160,000. The issuance was a subsequent additional closing related to the November 2011 private equity placement. Under National Instrument 45-102, the common shares issued are subject to a restricted hold period which expires August 12, 2012. 2011 | Annual Report 21 CORPORATE INFORMATION OFFICERS Kevin L. Adair, P. Eng. President and Chief Executive Officer DIRECTORS Don T. Gray Executive Chairman Calgary, Alberta SOLICITOR Burnet, Duckworth & Palmer LLP Calgary, Alberta Neil Korchinski, P. Eng. Vice President, Engineering Rick F. Braund Calgary, Alberta AUDITOR Ernst & Young LLP Chartered Accountants Calgary, Alberta Cheree Stephenson, CA Chief Financial Officer Patrick Arnell Calgary, Alberta INDEPENDENT RESERVE EVALUATOR GLJ Petroleum Consultants Calgary, Alberta Peter Verburg Corporate Secretary Peter Verburg Calgary, Alberta Kevin L. Adair Calgary, Alberta BANKERS Royal Bank of Canada Calgary, Alberta Canadian Imperial Bank of Commerce Calgary, Alberta TRANSFER AGENT Valiant Trust Company Calgary, Alberta HEAD OFFICE 4210, 525 – 8th Avenue S.W. Calgary, Alberta T2P 1G1 Phone: 403-984-9014 Fax: 403-984-2717 WEBSITE www.petrusresources.com 2011 | Annual Report 22 

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