PILOT ENERGY LIMITED — Management Reports 2008

Jan 20, 2008

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Form 51-102F1 Management Discussion and Analysis

For the Year Ended September 30, 2007

The following management discussion and analysis has been prepared as of January 14, 2008. The selected financial information set out below and certain comments which follow are based on and derived from the audited consolidated financial statements of Fall River Resources Ltd. (the “Company” or “Fall River”) for the year ended September 30, 2007 and should be read in conjunction with them.

Forward Looking Information

Certain statements contained in the following Management’s Discussion and Analysis constitute forward looking statements. Such forward looking statements involve a number of known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievements of the Company to be materially different from actual future results and achievements expressed or implied by such forward looking statements. Readers are cautioned not to place undue reliance on these forward looking statements, which speak only as of the date the statements were made. Readers are also advised to consider such forward looking statements while considering the risks set forth below.

General

Fall River is a Canadian company with its shares traded on the Australian Stock Exchange under the trading code of “FRV”.

Fall River is a junior oil and gas company focused on acquiring and building a portfolio of properties, enhancement of the Company and increasing shareholder value.

Fall River’s corporate strategy is risk mitigation by portfolio spread and diversity, early stage cash flow and production potential and a commitment to an expanded development program utilising that early stage cash flow. Fall River intends to participate in oil and gas interests on a joint venture / farmin basis with interests up to around 50% in Canada and the USA. Revenues are currently produced from its Sprowl gas field in Oklahoma and from West Florence Leases USA. Fall River is in the process of developing a portfolio of oil and gas prospects to further generate production and revenue flow. The Company depends largely on the issue of shares from the treasury to investors to raise the necessary funds for acquisitions and development. Such stock issues in turn depend on numerous factors, important among which are positive oil and gas prices, positive stock market conditions, a company’s track record and the experience of management.

Overall Performance

In July 2007 the Company announced that it had resolved to apply to have its shares delisted from the TSX Venture Exchange (“TSXV”). The Company has completed in excess of AUS$8.6 million in financings over the past 16 months, entirely through the Australian market. All securities issued in the past 18 months trade on the Australian Stock Exchange (“ASX”). There are currently 90,400,000 shares issued pursuant to private placements which have closed, of which approximately 74,200,000 are represented by CDI’s or CHESS Depositary Instruments, and approximately 8,300,000 are held

through the Canadian Depositary of Securities (“CDS”) and approximately 7,900,000 shares are in registered form, mostly with Australian investors.

The CDS shares are the shares that may trade through the facilities of the TSXV and represent 9.2% of the total issued and outstanding share capital. The Company has traded 226,500 shares through the TSXV and several million shares through the ASX in the past 3 months of trading on the TSXV.

In light of the small number of shares trading through the facilities of the TSXV, and the additional costs associated with being inter listed on both the TSXV and ASX, the Board of Directors believed it in the best interests of shareholders at this point to have its shares delisted from the TSXV.

Shareholders holding Canadian Share certificates or shares held in a brokerage account will be able to transfer those shares to the ASX register by completion and lodgement of a “Register Transfer Form” which is available from Computershare or from the Company’s website. ASX operates an electronic exchange and upon processing by Computershare the share will be able to be traded on ASX.

Exploration Projects

Sprowl Project Fall River Resources 20% working interest

Sprowl is a gas field comprising a section of land in Grady County in west central Oklahoma. Five wells have now been drilled into the Sprowl field, namely Sprowl 1-14, 2-14, 3-14, Nixon 1-14 and Sprowl 6-14. All wells are producing, with total production being in the order of 500,000 cubic feet per day gas, with around 7 barrels per day oil.

All gas produced is sold into the gas grid, which achieves a price based on U.S. Henry Hub spot price less pipeline costs.

Subject to U.S. gas prices and maintenance of current production levels, Sprowl revenues should over the next 12 months achieve around $156,000 (Australian) p.a.

The Operator has yet to advise the timing of the next development well (named Gruver-1), but this will presumably depend on an increase in gas pricing and a decrease in drilling/completion costs.

Baxter Shale Project

By an agreement dated November 15, 2005, the Company’s wholly owned subsidiary Spring River Resources Ltd. and Kestrel Energy Inc. agreed on the terms of a participation agreement involving (i) a farmin with respect to an initial well using the Green Canyon 27-3 well bore on the oil and gas leases itemised in the Agreement and known as the Green Canyon Prospect; (ii) an option to farmin with respect to a phase 2 well on the oil and gas leases itemised in the Agreement and known as the Green Canyon Prospect; and (iii) an option to farmin with respect to the oil and gas leases itemised in the Agreement and known as the Flaming Gorge Prospect; all the leases forming part of the Baxter Field in the county of Sweetwater, Wyoming.

The agreement includes provisions that:

• a) Initial Well: i) AFE for Initial Well: Spring River is to be responsible for funding an Authorization for Expenditures (AFE) for an initial well (the “Initial Well”) within 30 days of receipt of the AFE from Kestrel.

• ii) Interest Earned in Initial Well: upon drilling of the Initial Well to the contracted depth and completing the well, Spring River will earn 25% of Kestrel’s working interest and operating rights in the Baxter Leases only insofar as the Baxter Leases cover the Baxter Shale underlying certain specified land, up to Initial Well Payout (in summary, the recovery of the cost of drilling the Initial Well and any royalty interests), and 15% after Initial Well Payout.

• b) Phase 2 Well:

• i) Second Well Participation: Within 60 days of release of the rig from the Initial Well, Kestrel must send Spring River an AFE for a well for a second location on the Baxter Leases.

• ii) Option: Spring River has the option to participate in the second well (the “Phase 2 Well”) within 30 days of receipt of the AFE from Kestrel. The Phase 2 Well depth is not defined.

• iii) Failure to Participate: If Spring River elects not to participate, the Agreement terminates and it loses its rights in the Initial Well and its option to participate in the Flaming Gorge prospect.

• ii) Interest Earned in Phase 2 Well: upon drilling of the Phase 2 Well and completing the well, Spring River will earn 25% of Kestrel’s working interest and operating rights in the Baxter Leases only insofar as the Baxter Leases cover the Baxter Shale underlying certain specified land, up to Initial Well Payout (in summary, the recovery of the cost of drilling the Initial Well and any royalty interests), and 15% after Initial Well Payout.

• c) Flaming Gorge Option:

• i) Option: If Spring River participates and fulfils its obligations with respect to the Initial Well and the Phase 2 Well, Spring River has the option to acquire 15% of Kestrel’s working interest in the Flaming Gorge leases.

• ii) Initial Flaming Gorge Well Participation: Kestrel must send Spring River an AFE for a well on the Flaming Gorge Leases within 90 days of release of the rig from the Phase 2 Wel ~~l.~~

• iii) Interest Earned in Flaming Gorge Leases: upon drilling of the initial Flaming Gorge well and completing the well, Spring River will earn 25% of Kestrel’s working interest and operating rights in the Baxter Shale interval of the Flaming Gorge Leases, up to Initial Well Payout (in summary, the recovery of the cost of drilling the Initial Well and any royalty interests), and 15% after Initial Well Payout.

The AFE for the Phase 2 well was not issued within the time period specified in the Baxter Agreement but was received in September 2007. The well is to be drilled with a proposed 3000 ft lateral, in close proximity to the Pointevent well (see map) which has previously flowed gas, condensate and oil, believed to have been derived from the Baxter interval.

Following the operator issuing the AFE for the drilling of the Phase 2 Well, the Company was committed to meet its cash call by 31[st] October 2007. The Company subsequently agreed with the operator as follows:

• a. That the time period for cash call be extended to 30[th] November 2007

• b. That the Company participate in a seismic program over the Flaming Gorge leases to the extent of a 25% working interest.

• c. The Company remitted cash call funds to the operator with final remittances concluding after 30[th] November 2007

• d. The operator and the Company are to yet to resolve any issues that may arise following late payment of the cash call.

Successful Baxter Shale Test Results

Successful test results and gas flow from the Fall River’s Baxter shale have been recorded by the operator, Samson Oil & Gas (SSN), following the frac program undertaken in the Green Canyon 29-2 well. The operator's program involved the re-entry of an existing well, which was cased through the Baxter shale, perforating selected intervals and subjecting them to fracture stimulation.

The well tested a gross interval of 305 feet out of a total 3,400-foot Baxter shale interval in the well. As such, it is a limited test designed to demonstrate the potential for commercial production from the Baxter shale in the Green Canyon area. The operator is paying 100 per cent of the cost of this test

well, which although within Fall Rivers Greens Canyons lease interest, is not envisaged in the farm-in agreement.

The operator has commented as follows on the results of the well: "Initial flow rates through the casing are estimated at 100,000 cubic feet of gas per day plus 48 barrels of load water per day through a one-inch choke ... It is expected that flow rates will increase on the well as the load water is recovered, although it is still too early to estimate the flow rates ... Initial results are encouraging and indicate favourable comparisons to Questar's Baxter shale development play in the Vermillion area located 50 miles to the southeast.

"Questar Corp., Kodiak Oil & Gas, and Warren Resources ... have announced significant capital expenditure plans for the Baxter shale in Vermillion area."

Fall River views this test well result as most significant and an encouraging indication and confirmation of the presence of gas in the Baxter shale within its leasehold interests.

Questar Inc., a major player in Green River Basin exploration, has had considerable success with achieving commercial production from the Baxter Shale in a 16 vertical well drilling programme that included fracture stimulation of the Baxter Shale over several intervals. Earlier this year Questar’s Trail 13-C vertical well gave an initial flow rate of 9 mmcf/d of gas, presumably having intersected an open fracture. This indicates there is potential for ‘sweet spots’ in the Baxter shale target, and Questar is now undertaking analysis of fracture patterns within the Baxter.

This year a second US independent, Kodiak Resources, joined Questar in an active drilling programme evaluating the potential of the Baxter Shale within their own leases.

Both have now drilled the initial horizontal wells into the Baxter, with a flow of just under 5 mmcf/d reported from Questar’s first horizontal well, and similar results from their second. Kodiak also encountered strong gas shows in their horizontal well, but have not yet reported on the results of testing.

The joint venture has now concluded that, as for the Barnett Shale in Texas, production will require drilling of a lateral hole and extensive fracture stimulation if commercial production is to be achieved.

West Florence - Colorado

The Company has entered into a Participation Agreement with Mountain Energy LLC as the operator in January 2007 to acquire, in accordance with a participation agreement, a 15% working interest in 12,000 acres of leasehold located in Canon City Florence, sub basin of the Denver basin. The leasehold is approximately 160 kms (100 miles) south of the City of Denver, Colorado, USA.

The Company commenced the drilling of the West Florence – 1 well in May 2007. As of 1[st] June 2007 that well was drilled to a total depth of 1,957 metres. 4 ½ inch production casing has since been run and set at a depth of 1,956 metres.

Gas shows were encountered in the Dakota Sandstone, however subsequent testing undertaken in August after casing the well yielded water with some gas. Evaluation of the remaining potential for commercial production from the Dakota section will require drilling of a well targeting the Dakota, located up-dip structurally to the east of the present location.

Production testing operations has been carried out over the Codell Sand and Lower Niobrara Fort Hays equivalent following fracture stimulation of these oil bearing zones. An Upper Niobrara Fm interval was also perforated, and flowed oil and water. This zone has not been fracture stimulated at this stage. Subsequently a pump has been installed and the Codell Sandstone has settled to a production rate of around 15 bopd together with approximately 45 barrels of water per day.

The Upper zone in the Niobrara remains to be fully evaluated and the Pierre Fm potential will need to be evaluated on a separate well due to formation damage associated with lost circulation measures involving cement plugs in this interval in the West Florence-1 well.

West Florence-1 is the first well to be drilled in the West Florence Oil and Gas Project and its associated leasehold of 12,000 acres located in the Florence sub basin of the Denver basin.

The project area is to the west of the Florence Oil Field which produced approximately 15 million barrels of oil from fractured shales of the Pierre Formation up to the 1940’s.

In keeping with the encouraging drilling results seen in the West Florence-1 well, the Company together with the West Florence Oil and Gas Project participants secured the rights to acquire up to a 70% working interest in an additional 13,000 acres (5,261 hectares) of leasehold adjacent to the currently held 12,000 acres (4,856 hectares) of 100% working interest leasehold by carrying out a farmin drilling program.

The total gross leasehold of 25,000 acres (10,117 hectares) provides the participants in the West Florence project with a significant leasehold position. Management consider this area has the potential to provide production from several oil wells located with the assistance of new seismic. Prospective Resources for the West Florence play as estimated by the Operator with respect to the 25,000 acres of leasehold held by the participants ranges between 100 BCF and 200 BCF of gas for the primary Muddy ‘J’ Sandstone and cumulatively up to 15 million barrels of oil for the three secondary targets, the Pierre, Niobrara and Codell Formations, should oil or gas be present. Fall River holds a 15% working interest. After the drilling of West Florence-1 the Dakota remains to be proved a viable play, whilst evaluation of resource volumes for the oil play awaits additional drilling..

Prospective Resources are “those quantities of oil and gas estimated at a given date to be potentially recoverable from undiscovered accumulations” It must be noted that there is no certainty that the Prospective Resources are present

Lake David

No activity occurred during the period.

The joint venture sees some potential for commercial gas production from the shallow reservoir of the Colony Sandstone, but progress requires resolution of the joint venture’s proposal to acquire additional acreage in the vicinity. No definitive reply has yet been received from the relevant leaseholder.

Sunken Lake

No activity occurred during the period.

East Queensdale Project Saskatchewan

In January 2007 the company entered into a Participation Agreement with Petrex Energy Ltd of Calgary, whereby it acquired an interest in a half section of land (320 acres) with oil targets in the South Queensdale area of Saskatchewan.

This prospect, known as East Queensdale, was located on the south side of the Queensdale field in southeast Saskatchewan, which has produced over 50 million barrels from the Mississippian age Alida Formation and the associated Kisby Sandstone Member.

Under the terms of the agreement the company acquired a 25% working interest before payout and a 15% working interest after payout subject to Crown royalties and 5% gross overriding royalty, the latter terminating at payout. The participation cost for such interest was 25% of the estimated costs to drill and case the test well, being CAD $112,500, (approximately Aus$130,000), but not including the costs to complete, equip and test the well.

The targets were the Mississipian age Kisby & Lodgepole Formations.

The well was drilled in November of this year to a depth of 1400 m. The Kisbey sandstone was not developed at the well location, and the Lodgepole gave no hydrocarbon shows.

However a dolomitised limestone interval within the Alida Formation yielded good oil and gas shows, and electric logs suggested up to 8 m of net pay.

After running casing and completing the well in the Alida reservoir the well flowed salty formation water, suggesting that the target horizon had previously hosted hydrocarbons, but that these had been depleted by previous production in the vicinity.

Subsequently the East Queensdale well was plugged and abandoned.

Future exploration within the East Queensdale lease will need to concentrate on a deeper Winnipegensis reef identified on seismic.

Selected Annual Information

The following table sets forth selected consolidated information of the Company at September 30 for each of the last three fiscal years prepared in accordance with Canadian Generally Accepted Accounting Principles. The selected consolidated financial information should be read in conjunction with the Audited Consolidated Financial Statements of the Company.

Canadian Dollars	2007	2006	2005
Revenues	202,016	171,060	2,256
Net earnings (loss)	(2,969,942)	(4,145,300)	(2,051,337)
Net income (loss) per share	(0.04)	(0.09)	(0.13)
Total assets	3,667,216	4,048,194	1,853,560
Long term debt	1,820,104	1,720,853	977,492
Dividends	Nil	Nil	Nil

Results of Operations

For the year ended September 30, 2007, the Company incurred a net loss of $2,969,942 compared to a net loss of $4,145,300 during the prior year. The significant differences between the two years include:

• An increase of $64,621 in natural gas and petroleum revenue as the Company had revenue from Sprowl for the entire year compared to half the year in 2006.

• A reduction of $56,374 in consulting as the Company trimmed costs to conserve cash.

• An impairment charge of $1,103,000 in 2007 compared to $2,475,200 in 2006. The impairment charge is a comparison of the book value of the asset versus estimated indicated future cash flow. The impairment charge occurs when the book value exceeds the estimated indicated future cash flow attributable to the asset.

• A write off of $231,779 was taken in 2007 compared to $382,724 in 2006. The write down is a result of property being abandoned or having been tested with no anticipated future cash flow projected from the property.

• Foreign exchange loss of $169,321 compared to a gain of $58,459 in 2006 as a result of changes in the value of the Australian dollar against the Canadian dollar and an overall increase in the strength of the Canadian dollar in 2007.

• Professional fees of $243,029 were expensed in 2007 compared to $21,184 in 2006. This is partly a result of additional accounting charges for a half yearly audit which was not done in 2006 and the accrual of the 2007 audit which was not done in 2006. In addition, legal fees were higher as the Company has to comply with both Australian and Canadian reporting requirements.

• Salaries and benefits were up $207,995 in 2007 due to 2006 salaries being only for a part year and in 2007 commencing the recording of annual leave commitments.

• $93,600 was charged in 2006 for stock based compensation compared to nil in 2007 as no options were granted during this past year.

• Travel and promotion costs were down $185,337 in 2007. Costs were higher in 2006 relating the Australian listing and prospectus financing.

Summary of Quarterly Results

The following table sets forth selected quarterly financial information for each of the last eight (8) quarters prepared in accordance with Canadian Generally Accepted Accounting Principles with the figures for each quarter on a cumulative year-to-date basis in Canadian dollars.

			Net Loss
Quarter Ending	Revenue	Net Loss	per Share
September 30, 2007	202,016	2,969,942	0.04
June 30, 2007	185,848	1,227,770	0.05
March 31, 2007	132,928	950,626	0.02
December 31, 2006	77,668	606,184	0.01
September 30, 2006	171,060	4,145,300	0.09
June 30, 2006	143,618	1,524,791	0.05
March 31, 2006	36,729	793,865	0.03
December 30, 2005	13,647	641,465	0.02

NOTE : There were no discontinued operations or extraordinary items on the Company’s financial statements during the above mentioned periods.

The increase in revenue in June 2006 is a result of commencing to receive petroleum revenue from the Company’s 20% interest in the Sprowl Project. The increase in net loss in September 2006 is as a result of impairment in the Company’s carrying value of its investment in the Sprowl Project.

Liquidity and Capital Resources

The Company has financed its operations mainly through the sale of its common shares or securities convertible into common shares to investors. The Company is now receiving revenue from its Sprowl and West Florence operations however, additional financing will be required to expand production at Sprowl, continue exploration at its Baxter Shale Project, develop the West Florence operations and evaluation of its Canadian assets and future acquisitions.

The Company had working capital deficiency of $765,422 at September 30, 2007 compared to a working capital deficiency of $480,908 at September 30, 2006. The decrease in working capital was a result of exploration expenditures and general operations.

Placement Equity Raising

During the year ended September 30, 2007, the Company issued the following CDI’s on a private placement basis:

• 8,150,000 common shares for gross proceeds of CDN$740,892 (AUS$815,000). In conjunction with this private placement, the Company issued 17,441,000 warrants, each of which entitles the holder to purchase a common share at AUS$0.10 per share on or before May 9, 2009. An additional 2,000,000 warrants were issued with the same terms as other warrants to agents. The Company incurred agents’ commission of CDN$52,109 (AUS$57,050)) and this was settled through the issuance of 570,500 common shares of the Company and the issuance of 1,141,000 warrants with the same terms as the other warrants;

• 15,878,612 common shares for gross proceeds of CDN$1,010,376 (AUS$1,111,447). In conjunction with this private placement, the Company issued 15,878,612 warrants, each of

which entitles the holder to purchase a common share at AUS$0.10 per share on or before May 9, 2009. An additional 2,500,000 warrants were issued with the same terms as other warrants to agents. The Company incurred agents’ commission of CDN$71,063 (AUS$77,805)) and this was settled through the issuance of 1,111,503 common shares of the Company and the issuance of 1,111,503 warrants with the same terms as the other warrants; and

• 2,842,857 common shares for gross proceeds of CDN$180,906 (AUS$199,000). In conjunction with this private placement, the Company issued 2,842,857 warrants, each of which entitles the holder to purchase a common share at AUS$0.10 per share on or before May 9, 2009. CDN$12,724 (AUS$13,930) was paid as agents’ commission.

Capital Resources

The Company has the following capital resource commitments:

• Sprowl Gas Field in Oklahoma requires Fall River to pay 20% of the costs of all future operating and capital costs.

• Baxter prospect in Wyoming requires Fall River to pay 25% of all future operating and capital costs for the first two wells, if any, before payout and 15% after payout.

• West Florence prospect in Colorado requires Fall River to pay between 10.5% to 15% of all future operating and capital costs.

Transactions with Related Parties

Related party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. Amounts due to related parties are unsecured with no specific terms for repayment.

During the year consulting fees of $45,000 (2006 – $45,000) were recorded by the Company to one director and salaries of $648,751 (2006 - $514,350) were recorded by the Company to three directors and a party related to a director.

Interest paid or accrued on convertible debentures, previously held by directors or parties related to directors amounted to $10,794 (2006 - $10,248) during the year.

Critical Accounting Estimates

The Company follows the full cost method of accounting for natural gas and petroleum property interests whereby all costs of acquisitions, exploring for and developing natural gas and petroleum reserves are initially capitalized. Such costs include land acquisition costs, geological and geophysical expenses, and carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.

Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. Petroleum products and reserves are converted to a common unit of measure, using six thousand cubic feet of natural gas to one barrel of oil.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

Proceeds from a sale of petroleum and natural gas properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion by more than 20%. Royalties paid net of any tax credits received are netted with oil and gas sales.

In applying the full cost method, the Company performs a ceiling test on properties which restricts the capitalized costs less accumulated depletion from exceeding an amount equal to the sum of the undiscounted cash flows expected from the production of proved reserves and the lower of cost and market value of unproved properties, as determined by independent engineers, based on sales prices achievable under existing contracts and posted average reference prices in effect between the end of the year and the finalization of the year end audit and current costs, and after deducting estimated future general and administrative expenses, production related expenses, financing costs, future site restoration costs and income taxes.

Changes in Accounting Policy

During the year, the Company adopted a new standard, the Canadian Institute of Chartered Accountants’ (“CICA”) Handbook Section 3855, “Financial Instruments – Recognition and Measurement”. Under the new standard all financial instruments are classified as one of the following: held-to-maturity, loans and receivables, held-for-trading or available-for-sale. Financial assets and liabilities held-for-trading are measured at fair value with gains and losses recognized in net income. Financial assets held-to-maturity, loans and receivables, and financial liabilities other than those held-for-trading, are measured at amortized cost. Available-for-sale instruments are measured at fair value with unrealized gains and losses recognized in other comprehensive income. The standard also permits designation of any financial instrument as held-for-trading upon initial recognition.

Also adopted by the Company during the year was CICA Handbook Section 1530, “Comprehensive Income”. As a result of adopting these standards, a new category, Accumulated Other Comprehensive Income, is added to shareholders’ equity on the consolidated balance sheets. Major components for this category include: unrealized gains and losses on financial assets classified as available-for-sale, unrealized foreign currency translation amounts, net of hedging, arising from selfsustaining foreign operations, and changes in fair value of the effective portion of cash flow hedging amounts.

The adoption of the provisions of these new standards resulted in no retrospective adjustment to the Company’s consolidated financial statements.

Financial Instruments and Other Instruments

The Company has not entered into any specialized financial agreements to minimize its investment risk, currency risk or commodity risk. As of the date hereof, the Company’s investment in oil and gas properties has full exposure to commodity risk, both upside and downside. As the oil and gas price moves so to does the underlying value of the Company’s oil and gas projects.

The Company’s property interests in the United States make it subject to foreign currency fluctuations which may adversely affect the Company’s financial position and results.

Outstanding Share Data

The authorized share capital consists of an unlimited number of common shares. As of September 30, 2007, an aggregate of 90,536,522 common shares were issued and outstanding.

The Company has the following warrants outstanding as of September 30, 2007:

Number of shares Price per share Expiry Date 4,974,149 CDN$0.20 October 19, 2007 12,743,301 AUS$0.25 November 30, 2007

331,760 CDN$0.25 April 24, 2008 41,773,972 AUS$0.10 May 9, 2009

• These warrants expired unexercised.

The following summarizes information about the stock options outstanding as of September 30, 2007:

		Weighted average
	Number of options	remaining contractual	Number of options
Exerciseprice	outstanding	life(years)	exercisable
$0.18	2,690,000	2.58	2,690,000
$0.20	150,000	0.12	150,000*
$0.18	2,840,000	2.45	2,840,000

• These stock options expired unexercised.

Investor Relations

Directors and officers of the Company all participate in a limited investor relations program. The Company has no arrangements for external promotional activities. Costs allocated to investor relations are comprised of promotional expenses incurred by directors and officers of the Company.

Disclosure Controls and Procedures

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is accumulated and communicated to the management as appropriate to allow timely decisions regarding required disclosure. The Company’s CEO and CFO have concluded, based on their evaluation as of the end of the year, that the disclosure controls and procedures are effective to provide reasonable assurance that material information related to the Company is made known to them by others. It should be noted that while the Company’s CEO and CFO believe that the disclosure controls and procedures provide a reasonable level of assurance and that they are effective, they do not expect that the disclosure controls and 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.

Internal Controls over Financial Reporting

The CEO and CFO of the Company are responsible for designing internal controls over financial reporting or causing them to be designed under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. The Company has assessed the design of the internal control over financial reporting and during this process the Company identified a certain weakness in internal controls over financial reporting which is as follows:

• Due to the limited number of staff, it is not feasible to achieve complete segregation of incompatible duties

The weakness in the Company’s internal controls over financial reporting result in a more than remote likelihood that a material misstatement would not be prevented or detected. Management and the Board of Directors work to mitigate the risk of a material misstatement in financial reporting; however, there can be no assurance that this risk can be reduced to less than a remote likelihood of a material misstatement.

Additional information on the Company can be found on SEDAR at www.sedar.com. and at the Company’s website at www.fallriverresources.com.