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1 Information Technology Solutions GOLDEN GATE PETROLEUM LTD Quarterly Activities Report For the three months ended 31 December 2012 COMPANY INFORMATION Golden Gate Petroleum Ltd ABN COMPANY DIRECTORS Steve Graves Executive Chairman Chris Porter - Director Rob Oliver - Director MANAGEMENT Chris Ritchie CFO / Co Sec STOCK EXCHANGE LISTING Australian Stock Exchange ASX Code: GGP Current Shares on Issue: 2,841,930,815 Market Capitalization as at 30 January 2013 based on a share price of $0.005 AUD $14.2 million CURRENT PROJECTS Permian Project Eagle Ford Shale Bowtie West Napoleonville North Edna Acadia Goliad Production for the Quarter Total Production Highlights Reserves Study * 5.0 million BOE P1 & P2 of Reserves from Spraberry- Dean formation in Permian project leaseholds. Permian Project * SRH -5H Drilled and Completed awaiting fracture stimulation program in February * SRH 1 & SRH -2 to go on production from Cline & Wolfcamp Intervals. Bowtie West Project * Sugar Valley #1 well commenced production 12 December Napoleonville Project * Hensarling #1 well completed and ready for testing. Post drill estimated resources of 952,000 bbls of oil and 0.4BCFG. GGP has a 3.99% WI. Corporate * Cash balance as at 31 December 2012 was AU$ 1.0 million. GGP Share Oil Gas Oil Gas Well BBL MCF BBL MCF Permian Project SRH # Permian Project SRH # Permian Project SRH #3 2,095 8,426 2,095 8,426 Permian Project SRH #4 2,032 6,970 2,032 6,970 Dugas & Leblanc #3 19,473 33,610 2,921 5,041 Sugar Valley # , ,374 Total 24,008 68,789 7,097 22,811 During the quarter the Company s estimated gross share of production was 7,097 barrels of oil and 22.8 million cubic feet of gas. At current oil and gas prices net revenue to the Company is estimated at US$195,000 per month. Page 1 of 9

2 Project Location Map Reserve Study On 9 January 2013, the Company released an independent reserve report for the Permian project. The report attributes over 5.0 million barrels of oil equivalent (BOE) from P1 and P2 reserves to the Permian leasehold assets currently held in Reagan and Irion Counties, Texas. These reserves have been identified as part of the Spraberry-Dean formation in the areas where GGP holds the rights to this formation. The reserves report was prepared by MHA Petroleum Consultants, LLC (MHA), Denver, Colorado. In addition to the P1 and P2 reserves identified in the Spraberry-Dean formation, MHA also identified Contingent Resources of 10.8 million BOE from only one of three identified intervals/benches in the Wolfcamp formation with each considered by GGP to have similar potential plus one interval in the Cline formation. The reserves report included projected income data from the estimated net reserve and contingent resources. On a 10% discounted net cash flow basis, US$69.1 million was attributed to Proved (P1) and Probable (P2) reserves and US$127.1 million from Contingent Resources. The economics used NYMEX oil and gas price projections plus cost estimates confirmed to be realistic by MHA. The reserves report was based on production performance analysis within the general area of the Company s holding. In the current leasehold area, a vertical well exploitation program, using forty (40) acre spacing, was assumed for the Spraberry-Dean reservoir. The anticipated field development plan included four (4) wells drilled by the Company with existing Proved Developed reserves, twenty-seven (27) Proven Undeveloped reserves locations, and thirteen (13) Probable reserves locations. While the reserve report assumed 40 acre spacing, it also noted that some regional operators have started to develop the Spraberry-Dean formation on twenty (20) acre spacing which may add incremental reserves associated with the higher density spacing. Page 2 of 9

3 Reserve Study (Continued) Golden Gate Petroleum Ltd Reagan and Irion Counties, Texas Assets of Interest Estimated Net Reserves, Contingent Resources and Income Data Reserves Income Data Category Net Remaining Reserves (MBOE) Discounted Net Cash 10% US$ million Proved Developed Spraberry- Dean Formation Wolfcamp Formation Proved Undeveloped 2, Total Proved 3, Probable 1, Total Proved + Probable 5, Contingent Resources 10, Reserves in this report were assigned on the basis of the Petroleum Resources Management System ( PRMS ) definitions published by the Society of Petroleum Engineers ( These definitions are generally accepted as standard in the U.S. oil and gas industry, and this report follows these guidelines for categorizing reserves. The relative uncertainty of reserves is characterized by reference to deterministic categories proved, P1 ( much more likely than not ); probable, P2 ( as likely than not ); and possible, P3 ( possible, but not likely ) or in probabilistic terms. If probabilistic methods are used, there should be at least a ninety percent (90%) probability that the quantities of proved reserves actually recovered will equal or exceed the estimate. For probable and possible reserves, the exceedance probabilities are fifty percent (50%) for probable and ten percent (10%) for possible reserves. 1P 2P 3P CONTINGENT RESOURCES 1C 2C 3C PROSPECTIVE RESOURCES Increasing Chance of Commerciality For personal use only Low Estimate Best Estimate High Estimate Permian Project Reagan and Irion Counties, Texas, Operator 100% WI Range of Uncertainty SRH-5H well On 10 December 2012, the Company announced that the SRH #5H had been drilled and completed. The SRH #5H well, Golden Gate s first horizontal well, reached a total measured depth of 11,404 feet with a total vertical depth of 7,070 feet. A horizontal section of approximately 4,700 feet was completed. Based on the Company s target range for the horizontal section being achieved and other factors including drilling rates and rig performance, it was elected to complete the well. 5½ inch casing was successfully set to bottom with a positive cement job test. The rig was released and planning for hydraulic fracturing continues with the current well data. The horizontal section is in the Upper Wolfcamp Interval which we refer to as the A Bench. The well activity versus plan was fully achieved and on schedule with actual costs running on projections. Haliburton has been scheduled to frac the SRH #5H in February 2013 after the completion of the current partially underwritten Entitlement Offer and sufficient funds are available for the planned program. Page 3 of 9

4 SRH 5H well (Continued) Demand for fracture stimulation equipment in our area remains high and impacts timing of the frac completion work. The current overall plan is to drill Wolfcamp horizontal wells over the leasehold position in 2013 in order to maintain all leases via the continuous drilling requirements. The SRH #5H well is already providing important information for next year s drilling program in addition to being put on production late in the third quarter. The Company believes there are three and possibly four intervals which could be candidates for horizontal drilling over our leasehold position. Approximately 24 horizontal well locations have been identified for each interval. 72 to 92 horizontal wells in total could be drilled over the leasehold. Based on other horizontal well estimates by major operators in the area, the SRH # 5H well could have an estimated ultimate resource potential of approximately 400,000 barrels of oil equivalent made up primarily of oil and gas liquids. SRH-1 well and SRH-2 well The Company is currently in the process of preparing to set capillaries on both the SRH #1 & #2 wells so the isolated Cline interval can be put on production and comingled with the Wolfcamp intervals which have already been frac d. The addition of chemicals to the bottom hole Cline interval is designed to avoid paraffin falling out of the oil while being produced. The current plan is to bring the two wells back on production from both the Wolfcamp and Cline intervals. Fracture stimulating the Spraberry-Dean intervals will be done at the same time as the next frac program for the planned well to be drilled in March. This will save a considerable amount of frac costs plus provide time to evaluate the effectiveness of the capillaries and make any necessary adjustments. The SRH-3 well and SRH-4 well are on production. Total current production of the producing wells is running approximately 62 BOE per day. Well Qtrly Production Cumulative Production BOE* BOE* SRH - #1-3,407.3 SRH - #2-6,202.2 SRH - #3 2, ,278.8 SRH - #4 2, ,981.1 SRH #5H - - Total 5, ,869.4 *BOE converted on a 10:1 mcf/boe ratio in order to better correspond to comparable oil revenues. Preparations are underway for the drilling of the 6 th well in the Permian project. Surveying of several sites for both vertical and horizontal wells is underway. The next well to be drilled is expected to commence drilling operations in March A decision on whether to drill a horizontal or vertical well will be determined based on the results of the #5H well s initial production and other factors involving the current permitting process and legal issues. Page 4 of 9

5 Eagle Ford Shale Development Dimmit and LaSalle Counties, Texas, Non-Operator, 10% WI The Company is participating in a 10% working interest in a 40+ horizontal development well project in the Eagle Ford Trend. The project covers approximately 3,400 acres in the oil window of the Eagle Ford Trend. The operator & prospect promoter estimate resource potential of 15 million barrels of oil equivalent (BOE) gross (net to the Company approximately 1.5 million barrels) for the leasehold position. The leases have terms and conditions typical of the Eagle Ford. The depth of the Eagle Ford shale in this area is around 8,200 feet with a shale thickness of approximately 175 feet. There are approximately 42 potential drilling locations on 80 acre spacing. Well costs are estimated at US$7.5 million with a drilling time of three weeks after the initial two wells are used to gather important data for designing the completion program. The lateral length of the horizontal well is planned for 4,500 feet and is expected to contain 12 to 16 frac stages. Initial production rates may range from 600 BOE per day to 1,300 BOE per day. Estimated recovery per well is in a 362M BOE to 500M BOE range. The Company will be paying its proportionate share of all costs plus a two or three well promote (approximately 11.1% for a 10% working interest). The total estimated commitment to the project (paying 11.1% for a 10% working interest) including planned drilling over the next year is US$1.7 million. Cutlass West A #1 well, Dimmit and La Salle Counties, Texas, Non-Operator, 10% WI The Cutlass West A #1 well was completed on 21 June 2012 and recorded oil and gas shows through several intervals including the Eagle Ford. Critical information about the shale rock properties was gathered for the design of the frac programs. Hole cores were also taken. Fracture stimulation is planned for early 2013 followed by a pipeline connector and hook-up. Cutlass East A#1 well, Dimmit and La Salle Counties, Texas, Non-Operator, 10% WI The Cutlass East A #1 well, was drilled to a total depth of 9,203 feet on 29 July 2012 and the current plan is to test and flow back several intervals (outside the Eagle Ford) before drilling the lateral and completing the Eagle Ford. Page 5 of 9

6 Bowtie West Project Sugar Valley #1 well, Matagorda County, Texas, Non-Operator, 12% WI The Sugar Valley #1 well was drilled and completed on 7 May 2012 and commenced production on 12 December The electronic logs had indicated a gross pay interval of 32 feet full to base and is highly laminated in the lower section while being 60 feet high to the down dip well drilled in the 1970s. During the quarter the Sugar Valley #1 well produced a total 408 bbls of oil and 19,783 mcf of gas. The Company s share of production was 49 bbls of oil and 2,374 mcf of gas. Well Qtrly Production Cumulative Production BOE^ BOE^ Sugar Valley # * 286.4* * Represents the Company s 12% working interest share ^BOE converted on a 10:1 mcf/boe ratio in order to better correspond to comparable oil revenues. Partners in the Sugar Valley #1 well are: Company WI Golden Gate Petroleum Ltd 12.0% Other Partners 88.0% Napoleonville Project Dugas & Leblanc #3 well, Assumption Parish, Louisiana, Non-Operator, 15% WI During the quarter the Dugas and Leblanc #3 well produced a total 19,473 bbls of oil and 33,610 mcf of gas. The Company s share of production was 2,921 bbls of oil and 5,041 mcf of gas. Well Qtrly Production Cumulative Production BOE^ BOE^ Dugas & Leblanc #3 3,172.9* 18,210.0* * Represents the Company s 15% working interest share ^ BOE converted on a 20:1 mcf/boe ratio in order to better correspond to comparable oil revenues. Ratio is different from Texas projects due to the gas not possessing as rich of a liquid content. Partners in the D&L#3 well are: Company WI Grand Gulf Energy Ltd 40.2% Golden Gate Petroleum Ltd 15.3% Other Partners 44.5% Hensarling #1 well, Assumption Parish, Louisiana, Non-Operator 3.99% WI The Hensarling #1 well, reached a TVD of 12,445 feet in mid-december 2012 and ran electric logs over the Cris R IV and V sands, but was unable to locate commercial hydrocarbons. The operator then plugged off the bottom of the well and moved to testing the Cris R III and II sands (in that order). Recently completed electric logging operations have confirmed net pay of 31 feet of pay in the Cris R II sands and 49 feet in the Cris R III sands. The Desiree prospect covers an area of 140 acres in Assumption Parish, Louisiana and is being operated by a large US oil and gas company. The operator is the same partner that is managing the Napoleonville salt dome project. Total drilling costs are US$ 3.6 million. GGP s share of drilling costs was funded in August The primary objectives are the Cris R II and III intervals which, based on Grand Gulf Energy s post drill estimates, resources of 952,000 bbls of oil and 0.4BCFG, representing a significant discovery. The well has been completed and is ready for testing following completion of unitization. The unitization process is expected to be completed in May Partners in the Hensarling #1 well are: Company WI Grand Gulf Energy Ltd 35.6% Golden Gate Petroleum Ltd 3.99% Other Partners 60.41% Page 6 of 9

7 Dugas & Leblanc #1 well Combined, insurers of the operator and the Company have paid in excess of US$19.6 million toward the blowout costs of the Dugas & Leblanc #1 well. The Company has paid its deductible to its own insurers and does not expect any further exposure. North Edna Project Walker #1 well, Jefferson David Parish, Louisiana, Non-Operator, 11.2% WI The Walker # 1 well is preparing to spud in early February The rig is on location and rigging up continues along with the delivery of surface casing. The Walker # 1 well will be drilled to a projected total depth of 9,300 feet. Crown Drilling Rig # 2 has been contracted for drilling operations. The Walker #1 well is up dip to the discovery well, Richardson # 1 well, which was drilled in September 2010 and produced 5,400 bbls of oil before production ended due to high water volumes. The new bottom hole target is up dip from the Richardson # 1 well in the Vicksburg Herpin Sand. In June 2012, the Company sold its 85% working interest in the project and received US$120,000 in cash and an 11.2% working interest in the project plus a carried interest in this initial well to casing point. The Vicksburg Herpin Sand is estimated to have a resource potential of approximately 2 million barrels of oil. Based on recent independent valuations the Company s share of project revenue is estimated to be US$6.5 million. The Vicksburg Herpin Sand is the pay objective located in the abandoned North Edna Field. Discovered in 1954, the North Edna Field produced 7.3 billion cubic feet of gas and 841,000 barrels of oil from two shallower Lower Frio sands at a depth of 7,900 and 8,600 feet. The field traps hydrocarbons from a south fault closure. During the development of the North Edna Field, the deep Herpin Sand was not drilled. Mapping of the Herpin Sand revealed an elongated barrier bar island complex that is occasionally cut by inlet channels. Research shows the main barrier island sandstone to be clean, porous and highly permeable while the channel inlets that occasionally cut through the barrier bar are filled with shaley, very fine grained laminated sands that are low permeability. Prior to the Richardson # 1 Well s successful completion in the Herpin Sand, three wells had attempted to complete in the Herpin Sand target. The first well was drilled in 1982 and experienced an uncontrolled blow out. The offset well encountered the low permeability shaley sands that are found in narrow channel inlets that sporadically cut across the main body of a barrier island. The third well drilled in late 2008 experienced a controlled blow out which ended up damaging the well bore and the well s eventual abandonment. Partners in the Walker #1 well are: Company WI Golden Gate Petroleum Ltd 11.2% Other Partners 88.8% Padre Island Project The Texas Railroad Commission Inactive Well Bonds have been returned. The Padre Island National Seashore (PINS) Bonds have not yet been returned. Page 7 of 9

8 Acadia Project, Midland, Louisiana, Operator, 34% WI The Company has acquired the rights to a 34% working interest after promote in this Louisiana based project with estimated reserves by the promoter of 446,000 bbls of oil and 4.1 billion cubic feet of gas. The Company will be the Operator. The new well will twin an abandoned well that produced for over 60 days before experiencing mechanical difficulties when oil and gas process were uneconomic in the 1980 s. A fixed price turnkey well and completion program for US$3.0 million has been put together to drill to 11,500 feet and test the Camerina and Marg 7 targets. One well should drain the structure. Subject to financial constraints, the Company s participation in the Acadia project is expected to commence drilling operations in mid Partners in the Acadia Project are: Company WI Golden Gate Petroleum Ltd 34% Other Partners 66% Goliad Project Goliad County, Texas, Operator, 25% WI The Company announced in August 2012 that it had acquired the rights to a 25% working interest in a project covering acres in Goliad County, Texas. The acreage is immediately up-dip and adjacent to two vertical wells drilled and completed in 2008 which tested approximately 1.5 million cubic feet of gas per day and 450 barrels per day of condensate pre-frac. Initially two wells will be drilled with the possibility of subsequent development. The Upper Wilcox and 1 st and 2 nd Mackhank will be developed. Wells will have a 10,800 feet vertical section, with a 2,500 feet horizontal leg that will be fracture stimulated in either the 1st or 2nd Mackhank interval, based on logging and testing the vertical section. The first well is expected to be drilled in the first half of 2013 at a cost of approximately US$3.5 million, including project infrastructure. Partners in the Goliad Project are: Company WI Golden Gate Petroleum Ltd 25% Other Partners 75% Corporate On 9 November 2012, the Company held its Annual General Meeting in Sydney. This meeting considered 4 resolutions in addition to adopting the Company s financial statements for the year ended 30 June The resolution concerning the adoption of the Remuneration Report was passed as an ordinary resolution but received an Against vote of in excess of 25%, which constitutes a first strike. Resolution 2 concerning the re-election of Mr. Frank Brophy as a director and Resolution 4 concerning the appointment of Grant Thornton Audit Pty Ltd were passed as an ordinary resolution. Resolution 3 concerning the approval of an additional 10% placement ability was not passed as a special resolution, as it failed to achieve the required 75% support of shareholders. On 16 November 2012, the Company announced that it was calling an Extraordinary General Meeting, to be held on 19 December 2012, in response to a s249d notice that the Company had received from a group of shareholders controlling at least 5% of the votes that may be cast a meeting of the Company. On 16 November 2012, the Company announced that it had raised AU$1,950,000 from the issue of 39,000,000 convertible notes. The issue and terms and conditions of which had been approved at an Extraordinary General Meeting held on 19 September 2012, approving the Company to issue up to 100,000,000 convertible notes to raise up to AU$5,000,000. On 20 November 2012, the Company announced that it had appointed two new additional non-executive directors, Mr. Chris Porter and Mr. Rob Oliver. In addition, the Company announced that it was calling a second Extraordinary General Meeting, to be held immediately after the first meeting to allow shareholders the opportunity to re-elect Mr. Porter and Mr. Oliver. Page 8 of 9

9 Corporate (Continued) On 30 November 2012, the Company announced that Mr. Frank Petruzzelli and Mr. Frank Brophy had resigned as non-executive directors. The results of the meetings on 19 December 2012, were that the resolutions to remove Mr. Petruzzelli and Mr. Brophy and the resolutions to appoint Mr. Kelly and Mr. Burt were all not carried on a poll. In addition, the resolutions to reelect Mr. Porter and Mr. Oliver were carried on a poll. On 7 December 2012, the Company announced that it had signed an Underwriting Agreement with Novus Capital Limited for a fully underwritten pro-rata non-renounceable 1:4 entitlement issues to eligible shareholders. The shares would be offered at an issue price of $0.005 and would raise approximately $3,231,210 before costs. Shareholders who take up their rights under the Entitlement Issue would receive 1 free attaching new option (with an exercise price of 2.0 cents, exercisable on or before 31 December 2014) for every new share purchased. On 22 December 2012, the Company announced that it had raised AU$630,000 from the issue of 12,600,000 convertible notes. The total raised through this convertible note issue was $2,580,000. In January 2013, the Company issued the 1:4 Entitlement Prospectus and Supplementary Prospectus. The Entitlement Issue was amended to a partially underwritten, due to the additional shares issued from the conversion of convertible notes subsequent from the date that the Underwriting Agreement was signed. Cash balance as at 31 December 2012 was AU$ 1.0 million. For further information contact: Chris Ritchie Chief Financial Officer Phone: investor.relations@ggpl.com.au Golden Gate is an independent oil and gas exploration and production company listed on the Australian Stock Exchange. Its focus of operations is onshore Texas and Louisiana Gulf Coast and Permian Basin regions of the USA. Competent Persons Statement: The information in this report has been reviewed and signed off by Mr. George Placke, Petroleum Engineer, with over 30 years of experience within the oil and gas sector and an extended background in Texas and the Permian Basin. The reserves figures used in this report have been compiled by the staff of MHA Petroleum Consultants, LLC, including Timothy L. Hower, BS (Petroleum Engineering), MS (Petroleum Engineering), CEO of MHA Petroleum Consultants, LLC and Julianna Sipeki, BS (Metallurgy and Materials). Mr. Hower and Ms. Sipeki are not employees of Golden Gate Petroleum Limited and consent to the inclusion in this report of these reserve figures in the form and context in which they appear. Forward Looking Statements This announcement contains forward looking statements that are subject to risk factors associated with oil and gas businesses. It is believed that the expectations reflected in these statements are reasonable but they may be affected by a variety of variables and changes in underlying assumptions which could cause actual results or trends to differ materially, including but not limited to: price fluctuations, actual demand, currency fluctuations, drilling and production results, reserve estimates, loss of market, industry competition, environmental risks, physical risks, legislative, fiscal and regulatory developments, economic and financial market conditions in various countries and regions, political risks, project delay or advancement, approvals and cost estimates. Page 9 of 9

10 Golden Gate Petroleum Limited Appendix 5B 31 December 2012 Mining exploration entity quarterly report 31Rule 5.3 Appendix 5B Mining exploration entity quarterly report Introduced 1/7/96. Origin: Appendix 8. Amended 1/7/97, 1/7/98, 30/9/2001. Name of entity Golden Gate Petroleum Ltd ABN Quarter ended ( current quarter ) December 2012 Consolidated statement of cash flows Cash flows related to operating activities Current quarter Year to date 1.1 Receipts from product sales and related debtors 498 1, Payments for exploration and evaluation development production administration - (1,965) (242) (704) (210) (2,609) (1,323) (1,389) 1.3 Dividends received 1.4 Interest and other items of a similar nature - 1 received 1.5 Interest and other costs of finance paid (66) (142) 1.6 Income taxes paid 1.7 JV Trust Accounts Net Operating Cash Flows (2,414) (4,456) Cash flows related to investing activities 1.8 Payment for purchases of: prospects - (678) equity investments other fixed assets (10) (10) 1.9 Proceeds from sale of: Project asset equity investments other fixed assets 1.10 Loans from other entities 1.11 Refunds/(Payments) of Security Deposits Net investing cash flows Total operating and investing cash flows (2,359) (4,357) + See chapter 19 for defined terms. Appendix 5B Page 1 31/12/2003

11 Golden Gate Petroleum Limited Appendix 5B 31 December 2012 Mining exploration entity quarterly report 1.13 Total operating and investing cash flows (carried forward) (2,359) (4,357) Cash flows related to financing activities 1.14 Proceeds from issues of shares, options, etc Costs of the Issue (155) (314) 1.16 Proceeds from borrowings 2,580 2, Repayment of borrowings 1.18 Dividends paid 1.19 Other (provide details if material) Net financing cash flows 2,425 2,266 Net increase (decrease) in cash held 66 (2,091) 1.20 Cash at beginning of quarter/year to date 861 3, Exchange rate adjustments to item Cash at end of quarter Payments to directors of the entity and associates of the directors Payments to related entities of the entity and associates of the related entities Current quarter 1.23 Aggregate amount of payments to the parties included in item Aggregate amount of loans to the parties included in item Explanation necessary for an understanding of the transactions Payments include consulting fees and directors fees, office rental, travel reimbursements and provision of administration and accounting staff. Non-cash financing and investing activities 2.1 Details of financing and investing transactions which have had a material effect on consolidated assets and liabilities but did not involve cash flows 45.4 million convertible notes with a face value of $2,270,000 were converted into ordinary shares. 2.2 Details of outlays made by other entities to establish or increase their share in projects in which the reporting entity has an interest Nil + See chapter 19 for defined terms. Appendix 5B Page 2 31/12/2003

12 Golden Gate Petroleum Limited Appendix 5B 31 December 2012 Mining exploration entity quarterly report Financing facilities available Amount available Amount used 3.1 Loan facilities Credit standby arrangements 0 0 Estimated cash outflows for next quarter 4.1 Exploration and evaluation 4.2 Development 4.3 Production 4.4 Administration Total 0 2, ,435 Reconciliation of cash Reconciliation of cash at the end of the quarter (as shown in the consolidated statement of cash flows) to the related items in the accounts is as follows. Current quarter Previous quarter 5.1 Cash on hand and at bank Deposits at call 5.3 Bank overdraft 5.4 Other (provide details) Total: cash at end of quarter (item 1.22) See chapter 19 for defined terms. Appendix 5B Page 3 31/12/2003

13 Golden Gate Petroleum Limited Appendix 5B 31 December 2012 Mining exploration entity quarterly report Changes in interests in mining tenements 6.1 Interests in mining tenements relinquished, reduced or lapsed Tenement reference Nature of interest (note (2)) Interest at beginning of quarter Interest at end of quarter 6.2 Interests in mining tenements acquired or increased Issued and quoted securities at end of current quarter Description includes rate of interest and any redemption or conversion rights together with prices and dates. 7.1 Preference + securities 7.2 Changes during quarter (a) Increases through issues (b) Decreases through returns of capital, buy-backs, redemptions Ordinary securities 7.4 Changes during quarter (a) Increases through issues (b) Decreases through returns of capital, buy-backs Total number Number quoted Issue price per security (see note 3) 2,801,281,570 2,801,281, ,861, ,861,826 Amount paid up per security (see note 3) + See chapter 19 for defined terms. Appendix 5B Page 4 31/12/2003

14 Golden Gate Petroleum Limited Appendix 5B 31 December 2012 Mining exploration entity quarterly report Convertible debt securities (description) Number + Class Conversion $ Maturity Face value of $0.05 but can convert at 85% of 10 day VWAP prior to maturity. 12,200,000 18,600,000 33,600,000 Series 1 Series 2 Series 3 $0.05 $0.05 $ June December September Changes during quarter (a) Increases through issues (b) Decreases through securities matured, converted 51,600,000 (6,000,000) (21,400,000) (18,000,000) Series 3 Series 1 Series 2 Series Options (description and conversion factor) Exercise price Expiry date 7.8 Issued during quarter 7.9 Exercised during quarter 7.10 Expired during quarter 7.11 Debentures (totals only) 7.12 Unsecured notes (totals only) ,076,921 Listed $ December 2014 Compliance statement 1 This statement has been prepared under accounting policies which comply with accounting standards as defined in the Corporations Act or other standards acceptable to ASX (see note 4). 2 This statement does give a true and fair view of the matters disclosed. Chris Ritchie Chief Financial Officer Date: 31 January 2013 Notes 1 The quarterly report provides a basis for informing the market how the entity s activities have been financed for the past quarter and the effect on its cash position. An entity wanting to disclose additional information is encouraged to do so, in a note or notes attached to this report. + See chapter 19 for defined terms. Appendix 5B Page 5 31/12/2003

15 Golden Gate Petroleum Limited Appendix 5B 31 December 2012 Mining exploration entity quarterly report 2 The Nature of interest (items 6.1 and 6.2) includes options in respect of interests in mining tenements acquired, exercised or lapsed during the reporting period. If the entity is involved in a joint venture agreement and there are conditions precedent which will change its percentage interest in a mining tenement, it should disclose the change of percentage interest and conditions precedent in the list required for items 6.1 and Issued and quoted securities the issue price and amount paid up is not required in items 7.1 and 7.3 for fully paid securities. 4 The definitions in, and provisions of, AASB 1022: Accounting for Extractive Industries and AASB 1026: Statement of Cash Flows apply to this report. 5 Accounting Standards ASX will accept, for example, the use of International Accounting Standards for foreign entities. If the standards used do not address a topic, the Australian standard on that topic (if any) must be complied with. + See chapter 19 for defined terms. Appendix 5B Page 6 31/12/2003