Management s Discussion and Analysis Nine months ended September 30, 2012

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2 This ( MD&A ) of the financial and operating results of Donnybrook Energy Inc. ( Donnybrook, DEI or the Company ), should be read in conjunction with the Company s unaudited Condensed Financial Statements and related notes for the nine months ended September 30, 2012 and the audited financial statements of the Company for the year ended December 31, 2011 (the Financial Statements ) prepared in accordance with International Financial Reporting Standards or IFRS. The information contained within this MD&A is current to November 23, Q Three months ended March 31, 2012 Q Three months ended June 30, 2012 Q Three months ended September 30, 2012 Q Three months ended December 31, 2012 IDENTIFICATION Donnybrook is a Western Canadian petroleum and natural gas ( P&NG ) exploration and production company listed and posted for trading under the symbol DEI on the TSX Venture Exchange ( TSXV ). Donnybrook has offices in Calgary, Alberta, and Vancouver, British Columbia, Canada. The registered office of the Company is 1900, rd Avenue SW, Calgary, Alberta, Canada T2P 0R3. The presentation and the functional currency is the Canadian Dollar. NON-GAAP MEASURES In this document Funds flow from operations, Funds flow from operations per BOE, Net revenues, Net G&A expense, Net G&A expense per BOE, Total depletion, depreciation and amortization per BOE, Operating expense per BOE, collectively the Non-GAAP measures, are used and do not have any standardized meanings as prescribed by IFRS. They are used to assist management in measuring the Company s ability to finance capital programs and meet financial obligations. Funds flow from operations refers to cash flows from operating activities before net changes in operating working capital. Non-GAAP measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with IFRS, or other measures of financial performance calculated in accordance with IFRS. The Non-GAAP measures are unlikely to be comparable to similar measures presented by other issuers. ABBREVIATIONS bbl barrels bbls/d barrels per day mcf thousand cubic feet mcf/d thousand cubic feet per day NGL natural gas liquids BOE PRESENTATION Where amounts are expressed on a barrel of oil equivalent ( BOE ) basis, natural gas volumes have been converted to oil equivalence at six thousand cubic feet per barrel and sulphur volumes have been converted to oil equivalence at 0.6 long tons per barrel. The term BOE may be misleading, particularly if used in isolation. A BOE Page 2 of 23

3 conversion ratio of six thousand cubic feet per barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. References to oil in this discussion include crude oil and natural gas liquids ( NGLs ). NGLs include condensate, propane, butane and ethane. References to gas in this MD&A include natural gas and sulphur. OVERVIEW As at the date of this report, the Company holds 46 gross sections (11,914 ha), net sections (5,869 ha) of petroleum and natural gas rights prospective primarily for Montney liquid rich natural gas resource development in the Deep Basin area of west-central Alberta. The lands are located at Simonette (33 sections gross; 16.5 sections net), Resthaven (5 sections gross; 2.66 sections net) and Bigstone (8 sections gross; 3.75 sections net). A non-convertible gross over-riding royalty ( GORR ) varying between 1.5% and 2.0% is payable on the Company s participating share of production on a portion of the Company s land located in the Deep Basin. The Company also holds various, non-core, non-operated, minor working interests in Central Alberta. The Company s capital program has focused on land acquisition and horizontal drilling directed at the Montney formation in the Deep Basin of west-central Alberta. This high liquids content formation has provided attractive rates of return in the current natural gas price environment. The Alberta Government s five percent royalty rate on initial production from new petroleum and natural gas wells and the Alberta Natural Gas Deep Drilling Program further supports the economics of the Company s ongoing development and exploitation of unconventional tight gas reservoirs. Recent activities at Simonette, Bigstone and Resthaven are discussed below. Simonette At Simonette, Cequence Energy Ltd. ( Cequence ), as operator, drilled and completed the Company s third Simonette Montney horizontal well at W5M ( Simonette Hz 1-11 ) on a jointly held section (50% Donnybrook/50% Cequence) located in the southeast portion of the Company s 33 section (16.5 net) contiguous land block was production tested in mid-february 2012 and was tied-in and put on production in Q Total net production to Donnybrook at Simonette is currently approximately 180 BOE/d with one well shut-in awaiting a downhole pump change. Bigstone At Bigstone, Donnybrook has 8 gross (3.75 net) sections of P&NG rights located approximately 35 kilometres (22 miles) east of the eastern edge of the Company s Simonette acreage block. The Bigstone Hz W5M (50% working interest) well was drilled in December 2011 and January 2012 and was completed and production tested in February The reservoir encountered is comparable to the Montney interval that was successfully completed in the Donnybrook Hz W5M Bigstone discovery well (25% BPO; 50% APO) drilled and completed in Q The installation of surface facilities, including 3 phase separators, line heaters, tanks, measurement and monitoring equipment and construction of a 1.6 mile 8 inch pipeline to tie-in to the Delphi Energy Corp. ( Delphi ) operated gas gathering system was completed in Q The W5M site of the facilities is the same surface location used to drill the DEI Bigstone Hz and Hz wells; both of which are now being produced through the facilities. The pipeline carries condensate, natural gas and natural gas liquids from our facilities to the Delphi system tie-in point in W5M. Production from the Company s first two Bigstone wells commenced in June and July 2012 with current combined gross production estimated at 193 BOE/d (80 BOE/d net). Page 3 of 23

4 In February 2012, Donnybrook entered into an agreement to pool its Bigstone Montney P&NG rights held by the Company and its partners in section W5M with the Montney P&NG rights held jointly by Trilogy Energy and TAQA North in the adjacent section W5M for the purpose of drilling an extended reach horizontal well on the pooled lands. The DEI Bigstone Hz W5M commenced drilling in March 2012 from its surface location at W5M to a total measured depth of 5,336 metres with a 2,590 metre horizontal length. The well has been tied in to the Company operated Bigstone pipeline system. The well was put on stream in late November Donnybrook holds an undivided 25% working interest in the pooled lands and participated as to a 25% working interest in the drilling of the DEI Bigstone Hz W5M well. Donnybrook has informed its partners that it has surveyed multiple new drilling locations and is planning to commence drilling the DEI Bigstone Hz W5M (50% working interest) extended reach horizontal well on the west side of the Bigstone acreage block within the first six months of Resthaven At Resthaven, the W6M (70% working interest) horizontal Montney well was drilled and cased in Q and completed with a 12-stage slick-water fracture stimulation program in Q2 2011; and the frac clean-up was suspended and the well was shut-in due to the on-set of break-up. During the abbreviated frac clean-up, the well had only recovered 30% of the frac fluid. The Resthaven well has recently been production tested inline intermittently at rates of 1 mmcf/d and 60 bbls/d of condensate. The gathering system that the well is tied into is running at high line pressures which is affecting the well s ability to flow consistently into the gathering system. At Resthaven, Donnybrook has 5 gross (2.66 net) sections of P&NG rights located 8 kilometres (5 miles) west of the western edge of the Company s Simonette acreage block. DONNYCREEK ENERGY INC. RIGHT TO PURCHASE On November 4, 2011, Donnybrook spun-out certain non-core petroleum and natural gas assets (the Transferred Assets ) to Donnycreek Energy Inc. ( Donnycreek ) (TSX.V: DCK). by means of a plan of arrangement pursuant to the Business Corporations Act (Alberta) (the "Plan of Arrangement"). Cash proceeds from the spin-out were $2,188,342 in the form of a promissory note, which has been paid in full. As part of the Plan of Arrangement, Donnycreek had a right to purchase any land, wells, facilities and associated title documents and petroleum and natural gas rights within 5 miles of the Transferred Assets for 90 days following the effective date of November 4, On February 1, 2012, Donnycreek exercised its right to purchase and concluded the purchase of certain west-central Alberta area petroleum and natural gas rights from the Company for a purchase price of $2,307,097. CAPITAL EXPENDITURES The Company has funded the activities at Simonette, Bigstone, and Resthaven in part from its $12.0 million bought deal financing completed in November 2011 and the completion of its spin-out of certain non-core assets to Donnycreek. The spin-out provided Donnybrook with approximately $2.2 million of cash in November 2011 and approximately $2.3 million of cash in February With these funds, together with net cash on hand, the Company will be able to carry out the balance of its capital expenditure program. See also Capital Budget below. Donnybrook continues to monitor the financial performance of its properties in the current natural gas price environment to ensure that they remain economic. Page 4 of 23

5 SELECTED QUARTERLY INFORMATION The following selected financial data has been prepared in accordance with IFRS and should be read in conjunction with the Company s financial statements. All dollar amounts are in Canadian dollars. Fiscal Quarter Ended Net Revenue Other Income Income (Loss) THIRD QUARTER 2012 FINANCIAL AND OPERATIONAL RESULTS Production Summary Basic & Diluted Earning/(Loss) Per Share September 30, 2012 $ 742,077 $ 9,316 $ (44,685) (0.01) June 30, 2012 $ 911,709 $ 29,460 $ (293,794) (0.01) March 31, 2012 $ 374,010 $ 40,951 $ 1,972, December 31, 2011 $ 283,291 $ 31,078 $ (246,306) (0.01) September 30, 2011 $ 306,816 $ 50,378 $ (655,597) (0.01) June 30, 2011 $ 466,923 $ 26,092 $ (39,980) (0.01) March 31, 2011 $ 388,762 $ 31,214 $ 525, December 31, 2010 $ 105,788 $ 12,412 $ (598,969) (0.02) September 30, 2010 $ 69,545 $ 6,822 $ (321,564) (0.01) The following information summarizes the Company s petroleum and natural gas activities for the three and nine months ended September 30, 2012, and 2011: Total volumes Three months ended September 30, Nine months ended September 30, Natural gas (mcf) 137,429 48, , ,880 Natural gas liquid production (bbl) 1, , Crude oil (bbl) 3,718 1,102 9,371 3,565 Total production (boe) 27,722 9,522 67,920 30,671 Daily production averages Natural gas (mcf/d) 1, , Natural gas liquid (bbl/d) Crude Oil (bbl/d) Boe/d Average prices Natural gas selling price ($/mcf) $ 2.37 $ 3.89 $ 2.04 $ 4.03 Natural gas liquid selling price ($/bbl) $ $ $ $ Crude Oil selling price ($/bbl) $ $ $ $ Page 5 of 23

6 In addition, net overriding royalties received resulted in an average equivalent of 11 BOE per day for the three months ended September 30, 2012 (September 30, BOE per day). Average production increased in both the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 as a result of the wells put on production at Simonette and Bigstone. Simonette Hz W6 was drilled in the summer of 2011 and put into production in November 2011 and Simonette Hz W5 began production in February Bigstone Hz W5 was put into production in June 2012 and Bigstone Hz W5 was put into production in July Net revenues Three months ended Nine months ended September 30, 2012 September 30, 2011 September 30, 2012 September 30, 2011 Natural gas $ 325,204 $ 189,123 $ 690,202 $ 632,762 Natural gas liquid 42,207 22,121 98,898 67,617 Crude oil 347,848 97, , ,782 Net overriding royalty 66,247 29, , , , ,379 1,736,805 1,256,047 Royalty expenses (39,429) (31,563) (83,019) (93,546) Producing and operating expenses (434,715) (110,045) (1,032,360) (279,940) $ 307,362 $ 196,771 $ 621,426 $ 882,561 Average selling prices for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011 declined for natural gas, NGLs, and crude oil. Natural gas average selling prices decreased from $3.89/mcf in Q to $2.37/mcf in Q NGLs average selling prices decreased from $68.49/bbl in Q to $38.40/bbl in Q However, crude oil average selling prices increased from $88.74/bbl in Q to $93.56/bbl in Q and total volumes of production increased on a BOE basis in Q compared to Q as well as for the nine months ended September compared to the nine months ended September 30, 2011 resulting in increased gross revenues in 2012 compared to Net revenues for the nine months ended September 30, 2012 declined due largely to increased production costs on a per BOE basis in 2012 compared to In 2011, the primary production was the wells in the Delia-Michichi area ( W4 and W4). These wells were spun-out to Donnycreek in November In 2012, the primary producing wells were at Simonette and Bigstone. The Company s working interest in Delia-Michichi was less than its working interest at Simonette and Bigstone, as were the production costs associated with their operations. See discussion at Producing and operating expenses below. Other revenue Finance (interest income) and other income was lower at $79,727 for the nine months ended September 30, 2012 compared to $107,684 for the nine months ended September 30, 2011 as the Company had more cash on hand to invest in interest bearing financial instruments during Producing and operating expenses Three months ended Nine months ended September 30, 2012 September 30, 2011 September 30, 2012 September 30, 2011 ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) Net operating expense $ 434,715 $ $ 110,045 $ $ 1,032,360 $ $ 279,940 $ 9.13 Page 6 of 23

7 Total net operating expenses as well as net operating expense per BOE have increased significantly in Q compared to Q with the three Simonette and two Bigstone wells in production. The increase in total net operating expense for the nine months ended September 30, 2012 compared to 2011 is due to the Company having production at Simonette Hz W5M, Hz W6M, and Hz W5M as of September 20, 2012 compared to 2011, when the Company had only the Simonette Hz W5M well along with the Delia-Michichi wells which were spun-out to Donnycreek in November The Delia- Michichi wells accounted for approximately 40% of the total net operating expense for the nine months ended September 30, Also, the Bigstone Hz W5 and Bigstone Hz W5 wells began production in June and July 2012, respectively. On a per BOE basis, net operating expenses have increased as properties in the Deep Basin area of west-central Alberta have significantly higher costs associated with operations compared to the Delia-Michichi area of Alberta. General and Administrative Expense Three months ended Nine months ended September 30, 2012 September 30, 2011 September 30, 2012 September 30, 2011 ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) Gross G&A expense $ 190,259 $ 6.86 $ 257,828 $ $ 815,836 $ $ 790,264 $ Overhead recoveries $ (43,983) $ (1.59) $ (20,403) $ (2.14) $ (315,779) $ (4.65) $ (117,729) $ (3.84) Capitalized G&A $ (22,950) $ (0.83) $ (30,750) $ (3.23) $ (84,150) $ (1.24) $ (92,250) $ (3.01) Net G&A expense $ 123,326 $ 4.45 $ 206,675 $ $ 415,907 $ 6.12 $ 580,285 $ Donnybrook s net general and administrative ( G&A ) expense decreased to $415,907 for the nine months ended September 30, 2012 compared to $580,285 for the nine months ended September 30, For the nine months ended September 30, 2012, estimated production volumes (and net royalty income) averaged BOE per day which equates to net G&A expenses equivalent to $4.88 per BOE compared to the nine months ended September 30, 2011 for which estimated production volumes (and net royalty income) averaged BOE per day which equates to net G&A expenses equivalent to $18.92 per BOE. Differences in G&A expenses during Q compared to Q were as follows: Audit and accounting fees of $20,010 for Q were lower compared to $62,516 in Q In 2011, additional audit and accounting requirements related to the implementation of IFRS effective January 1, 2011 and the Plan of Arrangement with Donnycreek were necessary resulting in higher expenses in 2011 compared to Filing and listing fees of $6,786 for Q were higher compared to $2,500 for Q due to increased filing fees related to annual filing requirements and fees with provincial securities commissions in British Columbia, Alberta, Saskatchewan and Ontario. Insurance fees of $15,903 were lower in Q compared to $25,614 in Q due to changes in the timing of prepaid payments for policies and the renewal dates of coverage the Company obtained for its P&NG assets and activities. Investor relations of $9,261 were lower in Q compared to $23,043 in Q when the Company had been actively raising funds to further its acquisition and development of E&E assets and petroleum and natural gas properties. Page 7 of 23

8 Legal fees of $12,083 for Q were higher compared to $6,872 in Q due to additional legal services required relating to the 2012 Annual General Meeting. Office and administration for Q of $80,806 compared to $77,627 for Q remained reasonably consistent during the current quarter. Rent for Q of $16,961 was lower compared to $21,897 for Q as in 2012 the Company maintained less office space in 2012 than in Share-Based Compensation There were no options granted in Q or during the nine months ended September 30, However, there were 4,133,500 options granted throughout Q to Q A portion of the options vested in 2011 and the remainder in The majority of the options vested in 2011 resulting in a decrease in share-based compensation in 2012 as fewer options vested. The fair value of vested share options granted and amended to directors, officers, employees and consultants is broken down as follows: Three months ended Nine months ended September 30, 2012 September 30, 2011 September 30, 2012 September 30, 2011 Directors, officers and employees $ 111,683 $ 472,210 $ 499,532 $ 765,227 Consultants 16,316 69,367 79, ,314 $ 127,999 $ 541,577 $ 578,941 $ 865,541 Depletion, depreciation and amortization Three months ended Nine months ended September 30, 2012 September 30, 2011 September 30, 2012 September 30, 2011 ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) Depletion, depreciation and amortization $ 97,764 $ 3.53 $ 102,612 $10.78 $ 280,251 $ 4.13 $ 289,997 $ 9.46 Due to an increase in the reserve base used for depletion, there was a decrease in depletion, depreciation and amortization per BOE for Q compared to Q Income Taxes Deferred income taxes arise from differences between the accounting and tax bases of the Company s assets and liabilities, which, substantially, relate to the premium recovered on flow-through shares within the meaning of the Income Tax Act (Canada) ( Flow-Through Shares). Page 8 of 23

9 As at September 30, 2012, Donnybrook has approximately $38.5 million ( $33.3 million) in tax pools available for deduction against future income as follows: Intangible resource pools: Rate % September 30, 2012 September 30, 2011 (000's) (000's) Canadian exploration expenses 100 $ 10,454 $ 8,965 Canadian development expenses 30 5, Canadian oil and gas property expenses 10 4,221 6,929 Foreign resource expenses 10 11,591 11,591 Undepreciated capital cost ,975 1,008 Capital losses Non-capital losses (expire through 2032) 100 3,426 4,478 $ 38,461 $ 33,306 At September 30, 2012, the Company has met its commitment to incur the necessary qualifying Canadian exploration expenses by December 31, 2012 in relation to its Flow-Through Shares issuances. Decommissioning Liabilities As at September 30, 2012, Donnybrook has recorded decommissioning liabilities of $471,176 compared to $362,796 at December 31, 2011, for future abandonment and reclamation of the Company s properties. The liabilities have increased as a result of fair value accretion of the existing liabilities and additional liabilities estimated on the future abandonment and reclamation of its Bigstone and Simonette area properties. Three months ended Nine months ended September 30, 2012 September 30, 2011 September 30, 2012 September 30, 2011 ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) Accretion expense $ 3,070 $ 0.11 $ 28,869 $ 3.03 $ 22,283 $ 0.33 $ 34,384 $ 1.12 LIQUIDITY AND CAPITAL RESOURCES As a petroleum and natural gas business, Donnybrook has a declining asset base and therefore, relies on ongoing development and acquisitions to replace production and add additional reserves. Future petroleum and natural gas production and reserves are highly dependent on the success of exploiting the Company s existing asset base and in acquiring additional reserves. To the extent Donnybrook is successful or unsuccessful in these activities, cash flow could be increased or reduced. Donnybrook plans to focus on growing petroleum and natural gas production from its portfolio of existing and emerging resource plays in Western Canada. Donnybrook remains highly focused on key business objectives of maintaining financial strength and optimizing capital investments attained through a disciplined approach to capital spending, a flexible investment program and financial stewardship. Natural gas prices are primarily driven by North American supply and demand, with weather being the key factor in the short term. Donnybrook believes that natural gas represents an abundant, secure, long-term supply of energy to meet North American needs. Donnybrook s results are affected by external market and risk factors, such as fluctuations in the prices of petroleum and natural gas, movements in foreign currency exchange rates and inflationary pressures on service costs. Page 9 of 23

10 The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of its underlying assets. The Company considers its capital structure to include shareholders equity. To maintain or adjust the capital structure, the Company may, from time to time, issue shares or adjust its capital spending. There were no changes in the Company s approach to capital management during the period ended September 30, On an ongoing basis, Donnybrook will typically utilize three sources of funding to finance its capital expenditure program: internally generated cash flow from operations, debt where deemed appropriate and new equity issues, if available on favourable terms. In addition, Donnybrook may adjust its capital expenditure program depending on the commodity price outlook and competitive nature of the Canadian petroleum and natural gas industry. Liquidity risk is the risk that Donnybrook will not be able to meet its financial obligations as they fall due. Donnybrook actively manages its liquidity through daily and longer-term cash and equity management strategies. Such strategies encompass, among other factors: estimating future cash generated from operations based on reasonable production and pricing assumptions, analysis of economic risk management opportunities, and maintaining sufficient cash flows. Donnybrook generally relies on operating cash flows and access to capital markets to meet its additional financing needs, fund its capital programs and provide liquidity. While Donnybrook completed offerings on March 18, 2011 ($5,025,000) and on November 15, 2011 ($12,004,000), there can be no assurance that future 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 Donnybrook. Credit risk is the risk of financial loss to Donnybrook if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from Donnybrook s trade receivables from joint venture partners and petroleum and natural gas marketers. A substantial portion of Donnybrook s accounts receivable are with customers and joint interest partners in the petroleum and natural gas industry and are subject to normal industry credit risks. Donnybrook sells substantially all of its production to purchasers under standard industry sale and payment terms. Purchasers of Donnybrook s natural gas, crude oil and NGLs are subject to periodic internal credit review to minimize the risk of non-payment. Donnybrook has continued to closely monitor and reassess the creditworthiness of its counterparties. This has resulted in Donnybrook reducing or mitigating its exposures to certain counterparties where it is deemed warranted and permitted under contractual terms. Donnybrook may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to Donnybrook, such failures may have a material adverse effect on the Company s business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner s willingness to participate in Donnybrook s ongoing capital program, potentially delaying the program and the results of such program until Donnybrook finds a suitable alternative partner Capital Budget In 2012, Donnybrook continues to focus on its liquid rich Montney resource plays. The size and scale of its program helps provide certainty of supply for our drilling, completions, and facilities requirements. Page 10 of 23

11 Donnybrook s capital budget for of approximately $14 million includes the drilling, completion, equipping, and tie-in of wells in two of Donnybrook s core areas; Simonette and Bigstone, Alberta. The capital budget consists of completion and tie-in of one horizontal Montney well at Simonette; drill, completion and tie-in of two horizontal Montney wells at Bigstone, the tie-in of two previously completed horizontal Montney wells at Bigstone and the surface facilities and sales pipeline at Bigstone. As of the date of this report, the activities are substantially complete. Donnybrook continually monitors its capital spending program in light of the recent volatility with respect to commodity prices with the aim of ensuring the Company will be able to meet future anticipated obligations incurred from normal ongoing operations with funds flow from operations. Donnybrook has the ability to fund its capital program by utilizing cash flow, current working capital and to the extent necessary, additional equity issuances. Looking forward to 2013, Donnybrook has informed its partners that it has surveyed multiple new drilling locations and is planning to commence drilling the DEI Bigstone Hz W5M (50% working interest) extended reach horizontal well on the west side of the Bigstone acreage block within the first six months of Funds Flow from Operations and Funds Flow per BOE Three months ended Three months ended Nine months ended Nine months ended September 30, 2012 September 30, 2011 September 30, 2012 September 30, 2011 ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) Petroleum and natural gas revenue $ 781,506 $ $ 338,379 $ $ 1,736,805 $ $ 1,256,047 $ Other income $ 9,316 $ 0.34 $ 50,378 $ 5.29 $ 79,727 $ 1.17 $ 107,684 $ 3.51 Royalties $ (39,429) $ (1.42) $ (31,563) $ (3.31) $ (83,019) $ (1.22) $ (93,546) $ (3.05) Producing and operating expenses $ (434,715) $ (15.68) $ (110,045) $ (11.56) $ (1,032,360) $ (15.20) $ (279,940) $ (9.13) Exploration and evaluation expenditures $ (9,204) $ (0.33) $ (11,206) $ (1.18) $ (99,799) $ (1.47) $ (48,502) $ (1.58) General and administrative expenses $ (123,326) $ (4.45) $ (206,675) $ (21.70) $ (415,907) $ (6.12) $ (580,285) $ (18.92) Funds flow from operations $ 184,148 $ 6.64 $ 29,268 $ 3.07 $ 185,447 $ 2.73 $ 361,458 $ The increase in 2012 in funds flow from operations compared to 2011 was the result of increased production resulting in increased petroleum and natural gas revenues despite declining sales prices, as well as a decrease in general and administrative expenses. Net Income and Funds Flow from Operations Three months ended Three months ended Nine months ended Nine months ended September 30, 2012 September 30, 2011 September 30, 2012 September 30, 2011 ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) Funds flow from operations $ 184,148 $ 6.64 $ 29,268 $ 3.07 $ 185,447 $ 2.73 $ 361,458 $ Less: Share-based compensation $ (127,999) $ (4.62) $ (541,577) $ (56.88) $ (578,941) $ (8.52) $ (865,541) $ (28.22) Less: Depreciation, depletion and amortization $ (97,764) $ (3.53) $ (102,612) $ (10.78) $ (280,251) $ (4.13) $ (289,997) $ (9.46) Accretion expense $ (3,070) $ (0.11) $ (28,870) $ (3.03) $ (22,283) $ (0.33) $ (34,384) $ (1.12) Impairment losses $ - $ - $ (11,806) $ (1.24) $ - $ - $ (11,806) $ (0.38) Deferred tax recovery $ - $ - $ - $ - $ 2,330,000 $ $ 670,132 $ Net income (loss) $ (44,685) $ (1.61) $ (655,597) $ (68.85) $ 1,633,972 $ $ (170,138) $ (5.55) Working Capital The Company has working capital of $3,204,723 at September 30, 2012 compared to working capital of $8,693,711 at December 31, Working capital was greater at December 31, 2011 as the Company raised net proceeds of $5,025,000 from a private placement in Q and $12,004,000 from a private placement in Q There were no equity financings in Q1, Q2, or Q and the Company was carrying out its 2012 program. Page 11 of 23

12 The Company s sources of cash during the nine months ended September 30, 2012 were: 1) proceeds from Donnycreek s exercise of its right of purchase on certain exploration and evaluation assets in the amount of $2,307,097 in relation to the Plan of Arrangement; 2) P&NG revenues of $1,736,805; and 3) finance (interest income) and other income of $79,727. The petroleum and natural gas industry has a pre-arranged monthly clearing day for payment of revenues from all buyers of oil and natural gas. This occurs on the 25 th day following the month of sale. As a result, the Company s production revenues are collected in an orderly fashion. Donnybrook monitors its revenue counterparty credit positions to mitigate any potential credit losses. To the extent that the Company has joint venture partners in its activities, it must collect the partners share of capital expenditures and operating expense on a monthly basis. Exceptions are in the event that the partners share of a capital project is a significant amount. In this case, Donnybrook will collect such amounts from its partners in advance of expenditures taking place in accordance with standard industry operating procedures. At September 30, 2012, the Company did not have any material accounts receivable that were deemed uncollectible. Accounts payable consist of amounts payable to suppliers relating to head office and field operating and investing activities. These invoices are processed within the Company s normal payment period. Donnybrook actively manages the pace of its capital spending program by monitoring forecasted production and commodity prices and resulting cash flows. Should circumstances affect cash flow in a detrimental way, the Company is capable of reducing capital investment levels. Capital Expenditures Donnybrook s total capital expenditures for the three and nine months ended September 30, 2012 and 2011 are summarized as follows: Property and equipment September 30, 2012 September 30, 2011 September 30, 2012 September 30, 2011 Land and property acquisitions $ - $ - $ - $ - Geological and geophysical Drilling and completions 22,098 9, ,203 1,843,815 Facilities and equipment 38,554 37, , ,026 Other ,815 12,667 Exploration and evaluation assets Three months ended Nine months ended $ 60,652 $ 47,735 $ 819,879 $ 2,079,508 Land and property acquisitions $ - $ 1,220,086 $ - $ 1,131,306 Geological and geophysical 53,030 48, , ,250 Drilling and completions 622, ,668 8,637,998 7,087,869 Facilities and equipment 126, ,030 1,943, ,322 $ 802,282 $ 2,174,534 $ 10,761,162 $ 8,856,747 Total capital expenditures $ 862,934 $ 2,222,269 $ 11,581,041 $ 10,936,255 Page 12 of 23

13 Share Information The Company is authorized to issue an unlimited number of common shares without par value and an unlimited number of preferred shares. As at September 30, 2012, there were 193,836,066 common shares issued and outstanding. The Company issued 200,000 common shares during the nine months ended September 30, 2012 as a result of the exercise of 200,000 share options at $ OUTSTANDING SHARE DATA As at September 30, 2012, the Company had the following securities issued and outstanding: Number Exercise Price Expiry Date Common shares 193,836,066 n/a n/a Share options 5,550,000 $0.125 June 21, 2013 Share options 5,025,000 $0.200 August 24, 2013 Share options 2,250,000 $0.400 December 21, 2013 Share options 4,008,500 $0.500 July 27, 2014 Share options 125,000 $0.500 November 24, 2014 Fully Diluted 210,794,566 As at November 23, 2012, there are 193,836,066 common shares and 16,958,500 stock options issued and outstanding. RELATED PARTY TRANSACTIONS The following is a summary of the related party transactions that occurred throughout the nine months ended September 30, 2012 and 2011: 1. Trading transactions Management fees of $nil (September 30, $30,000) were paid or accrued to a company with a common director. Rent, office and administrative expenses of $40,040 (September 30, $44,100) were paid or accrued to a company with a common director and officer. Accounts payable and accrued liabilities as at September 30, 2012 includes $67,792 (December 31, $44,999) owing to Donnycreek Energy Inc. ( Donnycreek ) for net P&NG income for production properties in which Donnycreek has a working interest but where registered ownership has not yet transferred. Trade and other receivables as at September 30, 2012 includes $360,734 (December 31, $90,965) owing from Donnycreek for general and administrative expenses, as well as capital and operating expenses for P&NG assets in which Donnycreek has a working interest but where registered ownership has not yet transferred. All related party amounts are without significant terms or conditions. Page 13 of 23

14 2. Compensation of key management and personnel The remuneration of directors and other members of key management personnel during the three and nine months ended September 30, 2012 and 2011 were as follows: Three months ended Nine months ended September 30, 2012 September 30, 2011 September 30, 2012 September 30, 2011 Salaries $ 45,900 $ 64,500 $ 248,300 $ 193,500 Share-based compensation 113, , , ,543 $ 159,043 $ 550,914 $ 751,753 $ 902,043 i. Share-based payments are the fair value of options granted to key management personnel. ii. Key management personnel were not paid post-employment benefits, termination benefits, or other longterm benefits during the three and nine months ended September 30, 2012 and CONTRACTUAL OBLIGATIONS From time to time and in the normal course of business, the Company enters into agreements to transport and market P&NG production. In addition, the Company has entered into agreements with third parties that provides employees with access to specialized computer software and information including production and reserves data, geological data, accounting systems, and land management systems. At present, the Company s only obligations with a term longer than 12 months is for rent and office services support in Vancouver and Calgary. In Vancouver, the obligation which commenced March 1, 2012 to February 28, 2014 is at a rate of $5,400 plus applicable taxes per month. In Calgary, the obligation which commenced June 1, 2012 to May 31, 2015 is for $3,221 plus applicable taxes per month. OFF-BALANCE SHEET TRANSACTIONS Donnybrook was not involved in any off-balance sheet transactions in the nine months ended September 30, 2012 and The Company has certain fixed term lease agreements, including primarily office space leases, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. The lease agreements do not provide for early termination. No asset or liability value has been assigned to these leases in the statement of financial position as of September 30, RESERVES DATA AND OTHER PETROLEUM AND NATURAL GAS INFORMATION Independently prepared reserves and assessment and evaluation of the Company s P&NG properties effective December 31, 2011 have been prepared in accordance with mandated National Instrument Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators. BUSINESS OUTLOOK Capital expenditures for 2012 and 2013 are expected to be funded from cash on hand, cash flow from operations and potentially from additional equity issuances (see Capital Budget; Liquidity and Capital Resources sections). Page 14 of 23

15 FINANCIAL REPORTING UPDATE Accounting Policy Changes The Company had no accounting policy changes during the nine months ended September 30, New Standards and Interpretations Not Yet Adopted The Company will be required to adopt certain standards and amendments issued by the IASB as described below. Accounting standards issued but not yet effective: a) Effective for annual periods beginning on or after January 1, 2013 Joint arrangements In May 2011, the IASB issued IFRS 11 Joint Arrangements ( IFRS 11 ), which supersedes IAS 31 Interests in Joint Ventures and SIC 13 Jointly Controlled Entities Non-Monetary Contributions by Venturers. IFRS 11 is effective for annual periods beginning on or after January 1, 2013, with earlier application permitted. Under IFRS 11, joint arrangements are classified as joint operations or joint ventures based on the rights and obligations of the parties to the joint arrangements. A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement ( joint operators ) have rights to the assets, and obligations for the liabilities, relating to the arrangement. A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement ( joint venturers ) have rights to the net assets of the arrangement. IFRS 11 requires that a joint operator recognize its portion of assets, liabilities, revenues and expenses of a joint arrangement, while a joint venturer recognizes its investment in a joint arrangement using the equity method. Fair value measurement In May 2011, as a result of the convergence project undertaken by the IASB with the US Financial Accounting Standards Board to develop common requirements for measuring fair value and for disclosing information about fair value measurements, the IASB issued IFRS 13 Fair Value Measurement ( IFRS 13 ). IFRS 13 is effective for annual periods beginning on or after January 1, 2013, with earlier application permitted. IFRS 13 defines fair value and sets out a single framework for measuring fair value which is applicable to all IFRSs that require or permit fair value measurements or disclosures about fair value measurements. IFRS 13 requires that when using a valuation technique to measure fair value, the use of relevant observable inputs should be maximized while unobservable inputs should be minimized. Financial statement presentation In June 2011, the IASB issued amendments to IAS 1 Presentation of Financial Statements ( IAS 1 ) that require an entity to group items presented in the statement of other comprehensive income on the basis of whether they may be reclassified to profit or loss subsequent to initial recognition. For those items presented before tax, the amendments to IAS 1 also require that the tax related to the two separate groups be presented separately. The amendments to IAS 1 are effective for annual periods beginning on or after July 1, 2012, with earlier application permitted. Page 15 of 23

16 b) Effective for annual periods beginning on or after January 1, 2015 Financial instruments The IASB intends to replace IAS 39 Financial Instruments: Recognition and Measurement ( IAS 39 ) in its entirety with IFRS 9 Financial Instruments ( IFRS 9 ) in three main phases. IFRS 9 will be the new standard for the financial reporting of financial instruments that is principles-based and less complex than IAS 39. In November 2009 and October 2010, phase 1 of IFRS 9 was issued and amended, respectively, which addressed the classification and measurement of financial assets and financial liabilities. IFRS 9 requires that all financial assets be classified as subsequently measured at amortized cost or at fair value based on the Company s business model for managing financial assets and the contractual cash flow characteristics of the financial assets. Financial liabilities are classified as subsequently measured at amortized cost except for financial liabilities classified as at fair value through profit or loss, financial guarantees and certain other exceptions. In response to delays to the completion of the remaining phases of the project, on December 16, 2011, the IASB issued amendments to IFRS 9 which deferred the mandatory effective date of IFRS 9 from January 1, 2013 to annual periods beginning on or after January 1, The amendments also provided relief from the requirement to restate comparative financial statements for the effects of applying IFRS 9. The Company has not early adopted these revised standards and is currently assessing the impact that these standards will have on the financial statements. CRITICAL ACCOUNTING ESTIMATES The reader is advised that the critical accounting estimates, policies, and practices as described herein continue to be critical in determining Donnybrook s financial results. The reader is cautioned that the preparation of financial statements in accordance with IFRS requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to estimates that differ materially from current estimates. The following discussion outlines accounting policies and practices that are critical to determining Donnybrook s financial results. Trade and other receivables Trade and other receivables are recorded at the estimated recoverable amount which involves the estimate of uncollectible accounts or amounts. Petroleum and natural gas reserves Reserves and resources are used in the units of production calculation for depreciation, depletion and amortization and the impairment analysis which affect net income. There are numerous uncertainties inherent in estimating petroleum and natural gas reserves. Estimating reserves is very complex, requiring many judgments based on geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available and as the economic environment changes. Page 16 of 23

17 Depreciation and depletion Depletion of petroleum and natural gas properties is provided using the unit-of-production method based on production volumes before royalties in relation to total estimated proved reserves as determined annually by independent engineers and internal reserve evaluations on a quarterly basis. Natural gas reserves and production are converted at the energy equivalent of approximately six thousand cubic feet to one barrel of oil. The costs of acquiring and evaluating unproved properties are excluded from depletion calculations. Recoverability of asset carrying values The Company assesses its petroleum and natural gas properties, including exploration and evaluation assets, for possible impairment if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable, at least annually. The assessment of any impairment of property and equipment is dependent upon estimates of recoverable amount that take into account factors such as reserves, economic and market conditions, timing of cash flows, the useful lives of assets and their related salvage values. Donnybrook s assets are aggregated into CGUs, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows, geography, production profile and infrastructure of its assets. By their nature, these estimates and assumptions are subject to measurement uncertainty and may impact the carrying value of the Company s assets in future periods. Decommissioning liabilities Provisions for decommissioning liabilities associated with the Company s drilling operations are based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean up technology. Share-based compensation The fair value of share options granted is measured using the Black-Scholes option pricing model. Measurement inputs include share price on measurement date, exercise price of the option, expected volatility, expected life of the options, expected dividends and the risk-free rate. The Company estimates volatility based on historical share price excluding specific time frames in which volatility was affected by specific transactions that are not considered to be indicative of the Company s expected share price volatility. The expected life of the options is based on historical experience and general option holder behavior. Dividends were not taken into the consideration as the Company does not expect to pay dividends. Management also makes an estimate of the number of options that will forfeit and the rate is adjusted to reflect the actual number of options that actually vest. Income taxes Related assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly affect the amount of the deferred income tax asset or liability calculated at a point in time. These differences could materially impact earnings. Page 17 of 23

18 Other estimates The accrual method of accounting requires management to incorporate certain estimates including estimates of revenues, royalties, capital, drilling credits, and operating costs as at a specific reporting date, but for which actual revenues and costs have not yet been received. In addition, estimates are made on capital projects which are in progress or recently completed where actual costs have not been received by the reporting date. The Company obtains the estimates from the individuals with the most knowledge of the activity and from all project documentation received. The estimates are reviewed for reasonableness and compared to past performance to assess the reliability of the estimates. Past estimates are compared to actual results in order to make informed decisions on future estimates. BUSINESS RISKS Donnybrook s exploration and production activities are concentrated in the Western Canadian Sedimentary Basin, where activity is highly competitive and includes a variety of different sized companies ranging from smaller junior producers, intermediate and senior producers, to the much larger integrated petroleum companies. The Company s principal activity of petroleum and natural gas exploration and development is considered to be inherently risky. Donnybrook is subject to a number of risks which are also common to other organizations involved in the petroleum and gas industry. Such risks include finding and developing petroleum and natural gas reserves of economic costs, estimating amounts of recoverable reserves, production of petroleum and gas in commercial quantities, marketability of petroleum and gas produced, fluctuations in commodity prices, financial and liquidity risks and environmental and safety risks. Some of the most significant risks being: 1. Substantial expenditures are required to explore for P&NG reserves and there is no assurance that the Company will discover economic reserves; 2. The junior resource market, where the Company raises funds, is extremely volatile and there is no guarantee that the Company will be able to raise funds as it requires them; 3. Although the Company has taken steps to verify title to the P&NG properties it has an interest in or is earning into, there is no guarantee that the property will not be subject to title disputes or undetected defects; 4. The Company is subject to the laws and regulations relating to environmental matters, including provisions relating to reclamation, discharge of hazardous material and other matters. The Company s exploration and development activities including those conducted by partners and/or operators are in compliance with applicable environmental protection legislation. The Company is not aware of any existing environmental problems related to its properties that may cause material liability to the Company; 5. Under applicable regulatory requirements, the Company will be required to identify and disclose any proved petroleum and natural gas reserves, estimated quantities of crude oil, natural gas and natural gas liquids. This geological and engineering data demonstrates with reasonable certainty the estimated quantities of crude oil, natural gas and natural gas liquids, which will be recoverable in future years from known reservoirs under existing economic and operating conditions. However, the process of estimating petroleum and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir, and as a result, such estimates are inherently imprecise. Actual future production, petroleum and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable petroleum Page 18 of 23