Canoro-oil & Gas

2009 Annual Report | For the year ended March 31, 2009

b u i l d i n g

t h e

f o u n d a t i o n

2

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

PROFILE

highlights

4

message to shareholders

6

operations review

12

management’s discussion & analysis

21

management’s report

34

auditors’ report

35

financial statements

36

notes to the financial statements

39

corporate information

50

ANJITA KAUR LAMBA - NOIDA

ANKURJYOTI CHUTIA - JORHAT

ANKUSH DUTTA - JORHAT

ANSHU RU

USTAGI - NOIDA

B U I L D I N G T H E F O U N D AT I O N

3

Canoro is a publicly listed independent international oil and gas exploration and production company based in Calgary, Canada and New Delhi, India with operations in the prolific Assam/Arakan basin of northeast India. Having established a core operation and infrastructure in India, the Company is well positioned for growth, both organic and through additional projects in the region. The Company has an inventory of development, exploitation and exploration opportunities within its existing asset base to drive its growth strategy. Canoro has a full complement of experienced management, technical and operations personnel, backed by a board of directors committed to the disciplined growth of the Company.

BABUL HANDIQUE - JORHAT

BHUPEN SHAMANTA - JORHAT

BIDYUT CHUTIA - JORHAT

4

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

HIGHLIGHTS

Highlights of FY2009 Results •

Average daily production increased 162% from an average of 298 barrels of oil equivalent per day (boe/d) in 2008 to 781 boe/d per day in 2009. • •

AA-ON/7 exploration drilling was unsuccessful after two wells, the PSC was relinquished and 3.5 mmboe of probable reserves were written off. •

•

Amguri reserves were increased by 1.2 mmboe proved and 1.0 mmboe proved plus probable, net of production of 0.3 mmboe.

Amguri Barail appraisal drilling was very disappointing as well A-12 came in significantly below prognosis and wet. Amguri 13B however encountered 10 meters of oil pay and 24 meters of potential gas pay yet due to operational problems the well could not be completed.

Amguri Tipam appraisal was successful yielding an excellent dry gas well at A-14 testing at stabilised rates of 2.7 mmcfd. •

•

A significant re-interpretation of Amguri field was commissioned using Pre-Stack Depth Migration (PSDM) seismic reprocessing of 3D data to develop a new model of the field. •

•

Amguri condensate recovery and gas injection project was commenced and expected to be onstream in Q1 2010.

Loss of $6.3 million ($0.06 per share) with funds from operations positive for the first time at $2.0 million ($0.02 per share).

At year end, the Company had no debt and positive working capital of $7.0 million. •

$30 million capital program spent primarily on exploration and appraisal drilling. Subsequent to year-end and 2009/10 outlook •

• •

Positive election results in India should allow the Company to move ahead on its Nagaland joint venture with ONGC. Closed limited-recourse funding of US$4.0 million for the purchase and installation of the gas compression.

2009/10 capital expenditure program of $9 million to $11 million focused primarily on gas compression plant and well workovers. •

BIJU MONI DAS - JORHAT

Outlook for average 2009/10 production of 700 boe/d to 900 boe/d with a significant impact on cash flow towards year-end as production mix moves from 30/70 oil/gas to 60/40 oil/gas on commissioning the gas re-injection facility.

BIKRAMJEET BHATTACHARYA - JORHAT

BRIAN GIENI - NOIDA

BRIEN GOGO

OI - JORHAT

B U I L D I N G T H E F O U N D AT I O N

5

Highlights of FY2009 Results Years ended 31 March (US$000s, US$ per share)

2009

2008

% Change

1,969

(1,319)

n/m

0.02

(0.01)

n/m

(6,304)

(7,088)

11%

Financial Funds generated by operations per share diluted Profit (loss) for the year

(0.06)

(0.06)

0%

29.55

33.86

(13%)

30,000

13,708

119%

Working capital

6,989

35,545

(80%)

Long-term debt

–

–

per share diluted Operating netback per barrel of oil equivalent ($/boe) Capital expenditures

Shareholders’ equity Common shares outstanding (000s)

n/m

78,138

82,091

(5%)

113,709

112,992

1%

Operating Production 244

106

130%

Natural gas production (mcf/d)

3,223

1,153

179%

Barrels of oil equivalent (boe/d)

781

298

162%

Average crude oil price Nigerian Bonny Light ($/bbl)

87.81

84.59

4%

Average realized crude oil price ($/bbl)

95.96

97.32

(2%)

2.18

2.45

(11%)

Crude oil and condensate production (bbl/d)

Commodity prices

Average natural gas price ($/mcf) Reserves Volumes (mboe) Proved

3,944

2,773

42%

Proved + probable

7,372

9,853

(25%)

11,287

16,417

(31%)

Proved + probable + possible Net present value BTAX 10% (US$000s) Proved

37,956

69,631

(45%)

Proved + probable

73,024

170,133

(57%)

Proved + probable + possible

98,647

286,351

(66%)

Proved

0.40

0.93

(57%)

Proved + probable

0.70

1.82

(62%)

Proved + probable + possible

0.93

2.85

(67%)

Net asset value (BTAX NPV10%) US$ per share

CHANG WON WEINGKEN - JORHAT

DARCY DORSCHER - JORHAT

DARREN ARCURI - CALGARY

6

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

MESSAGE TO SHAREHOLDERS

Message to Shareholders Canoro has been building its operation in northeast

Canoro incurred a record capital spending program

India since 2003. The Company began by taking over

during the year, spending $30 million primarily on

a 60% participating interest in the Amguri Produc-

exploration and appraisal drilling. Drilling results

tion Sharing Contract in Assam and working over

were poor, with only two of six wells successful.

the field. Much had to be done in order to create a

Expectations were high for Amguri-12, which

beach head in northeast India. Much had to be done

proved to be an expensive failure of both the Amguri

to realize production and revenue from our Amguri

geological model and the drilling operations itself. The

field. Now our objective is to grow the Company. We

well was significantly off prognosis and over budget.

have much to do.

A-12 was the third well to miss the target zone along

2009 – a year of mixed results

the extremely complex fault bounding the Amguri field. The drilling program was shut down and the

The 2009 Fiscal Year was a year of mixed results for

rigs released while the geological and geophysical

your company. We suffered major disappointments

group began to reassess the entire Amguri Barail

from our exploration and appraisal drilling program,

zone model. The risk level of the Company’s drilling

yet we realized a strengthening of our reserve base in

had proved unacceptably high and with indications

our core asset at Amguri and established a production

of a failed velocity model, we have embarked on an

base with positive cash flow.

extensive pre-stack depth migration (PSDM) analysis

Your Company posted a loss of $6.3 million, or

of the field. We remain convinced of the potential for

$0.06 per share. However, for the first year since its

Amguri, but are committed to having a significantly

inception, Canoro generated positive funds from

better technical understanding before embarking on

operations of $2.0 million or $0.02 per share. Oil &

another drilling program.

gas production more than doubled to average 781 barrels of oil equivalent (“boe”) per day. Production revenue during the year more than doubled to $11.1 million as a result of the increase in production, offset slightly by an 11% decrease in gas prices as the Indian rupee weakened during the year. We have made significant progress this year in establishing Canoro as an operating entity. Over the past year, we made a major investment in people and infrastructure to carry

As many international E&P companies have experienced, Canoro suffered for having secured drilling rigs in an over-heated services market of 2008. Both rigs ran into several major problems which resulted in poor execution, costly delays and failed completions. It was a difficult and expensive decision to release both rigs, however we believe that it was prudent to halt the program given our experience.

the Company to the next level of growth. At current levels of production, our cost structure is too high. As the growth in production is realized, we fully expect our metrics to be competitive. Notwithstanding, we have made significant cost reductions throughout the organization and will continue to do so.

DHRUBAJYOTI DUTTA - JORHAT

DIPAK KALITA - JORHAT

DOUG UFFEN - CALGARY

DR. GAURI KANTA

B U I L D I N G T H E F O U N D AT I O N

There was some good news in the drilling program

As many in the industry are experiencing in the wake

however. In the shallower Tipam zone at Amguri, the

of the turbulence in both commodity and capital

Company successfully completed the A-14 appraisal

markets, the investment community has yet to

well. The well tested 4.8 million standard cubic feet

recognize the intrinsic value in the Company. Canoro

(“mmscf ”) per day into an 8mm choke and a stabilised

has been hit particularly hard, with the stock currently

rate of 2.7 mmcfd into a 6mm choke at minimal

trading at approximately 20% of its net asset value.

pressure drawdown. A-14 is an important addition to

Our task is to ensure that the market price of your

the well stock at Amguri, both as a source of dry gas to

shares begin to reflect the true value of the Company.

facilitate the condensate recovery and gas reinjection project, as well as incremental natural gas sales to the

Outlook for 2009/10

local market. With the potential for greater gas de-

2009/10 will be a markedly different year for Canoro

liverability, Canoro is aggressively examining the gas

as we focus entirely on production operations as

marketing potential in the area.

opposed to exploration and appraisal drilling.

Two exploration wells on the AA-ON/7 Block proved dry. With these results, the Company withdrew from AA-ON/7, writing off 15.2 billion cubic feet (“Bcf ”) of probable gas reserves (about 3.5 mmboe). The Company also withdrew its application for an extension and effectively relinquished the block. Unique in India, a portion of AA-ON/7 extended into Nagaland, which portion is the subject of a new PSC application by Canoro and its partners. The Amguri asset continued to improve as Canoro posted a 42% increase in proved reserves for the year to 3.9 mmboe, replacing production by over five times. With the significant writeoff of AA-ON/7 reserves, by the end of FY2009 Canoro’s proved and probable

7

The key project for the year will be the construction and commissioning of the condensate recovery and gas reinjection facility at Amguri. This is important as it significantly changes the Company’s production mix from 30/70 oil/gas to 60/40 oil/gas. In so doing, we effectively double the oil & condensate production which is sold at world prices, currently around $70/bbl as opposed to gas which is currently sold on the spot market for around $12/boe. While we are expecting a small increase in production for 2009/10 to average approximately 700 boe/d to 900 boe/d, we are anticipating a significant increase in cash flow at year end due to the change in production mix. We expect to exit the year in excess of 1,000 boe/d.

reserves were down 25% to 7.4 mmboe. The AA-ON/7 writeoff did mask the improvement at Amguri where 2P reserves increased 16% by the end of the year.

HANIQUE - NOIDA

DULAL BORA - JORHAT

G.P.G. BARUAH - JORHAT

GAURAV CHANDRA SINGH - NOIDA

8

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

MESSAGE TO THE SHAREHOLDERS

Creating value through gas marketing

Building a better understanding of Amguri Amguri is a very complex field. Bounded by a significant fault, the various reservoirs have proved elusive geological targets. The Company has struggled with three wells drilled along the fault, all of which were problematic. Two wells, A-10 and A-13, missed the target initially and needed to be sidetracked into the main reservoir. A-12 having come in significantly lower than prognosis was definitive proof that the geological model of the field was seriously flawed. With well results in hand, we determined that the seismic velocity model was unable to accurately predict the various formation tops. A key issue was the velocity differences across the fault which resulted

Canoro has begun to develop significant gas production potential, which could be expanded with additional Tipam drilling. The Company has however been restricted to low priced spot market sales and large seasonal swings in demand from the neighbouring tea gardens. We have begun a major initiative to secure more lucrative markets for the Company’s gas production. There is the potential for direct marketing of gas to regional consumers as well as the possibility of developing a gas-fired power plant. Gas marketing will be a key objective for the Company going into 2009/10. New ventures and strategic partnerships

in depth errors. To develop a better model of the field

As an integral component of the Company’s strategy

and negate the velocity problems, a depth-migrated

going forward, Canoro will be actively pursuing a

seismic volume needed to be generated by way of

variety of new business initiatives aimed at acquiring

PSDM reprocessing of the Amguri 3D seismic data.

production and development assets. The expansion

The PSDM work is underway and we expect to be

and diversification of the asset base is critical to the long

completing a full reinterpretation of Amguri by the

term success of Canoro. We plan to build out of our

end of the year. On the basis of this reinterpretation,

core operations in the North East and move into other

we expect to have a clearer picture of the field and be

regions of India and beyond. The immediate objective

able to pick well locations to fully develop Amguri at

for the Company is to close its deal with ONGC on

significantly lower risk.

Changpang and the adjacent exploration blocks in Nagaland. This transaction has been considerable time in the making as it has involved gaining the support of many levels of stakeholders. During the recent general elections in India, a majority government was elected in Nagaland, which we believe will clear the way for the necessary agreements between the Nagaland government and ONGC. While there is no assurance that the transaction will be ultimately consummated, we are working ahead in earnest to bring the deal together both from a stakeholder and a financing perspective. Success with Changpang would have a material impact on the operations and value of the Company.

GAUTAM NEOG - JORHAT

GAUTAM SAIKIA - JORHAT

HEMANTA TAMULY - JORHAT

HEMNATH PHUKON

B U I L D I N G T H E F O U N D AT I O N

In addition to Changpang, we have a number of strategic initiatives aimed at gaining strong partners and a broader suite of assets. Over the course of the year, it is our objective to secure a strategic partner or acquisition and make the next step in the growth of your Company.

9

Building a Platform for Growth Over the last year Canoro has built a platform for future growth that allows us to be positioned to seize high potential opportunities that are beginning to present themselves. We have the beginnings of a significant asset base in India, high value prospects and

Building a better organization

the technical and management expertise to explore

During the course of the year, we added two new

and develop the opportunities in front of us.

directors to the board, James N. Smith and Robert S.

We appreciate the investment of our shareholders,

Wynne, both of whom have significant experience in

the continued loyalty of our employees, the ongoing

building successful E&P companies and realising the

support of the Government of India, the support of

intrinsic value for the shareholders. We have also made

the communities in which we work and the strength of

some significant changes to our management team to

our co-venturers in building a truly substantial inter-

better execute the strategy. In particular, Brian Gieni

national oil and gas production company.

has moved into the Country Manager role reflecting the need for senior executive in exerting greater control

On behalf of the board and management,

and guidance in country. Ryan Ellson has assumed the role of Vice President Finance and will assume much of the financial responsibilities of Mr. Gieni.

N - JORHAT

Douglas R. Martin

Les B. Kondratoff

Chairman of the Board

President and Chief Executive Officer

July 27, 2009

HENRY SHEN - CALGARY

JAMIRATDDIN AHMED - JORHAT

JINU MONI BORDOLOI - JORHAT

10

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

TAJIKISTAN

TURKMENISTAN

AFGHANISTAN Kabol Islamabad Amritsar

Delhi

New Delhi

PAKISTAN

NEPAL

Kathmandu

India

Thimpu

BHUTAN

BANGLADESH

TROPIC DU CANCER

Kolkata

MYANMAR (BURMA)

Mumbai

INDIAN OCEAN

Yangon GOA

Bengaluru

Chennai PUDUCHERRY

Trivandrum

INDIAN OCEAN

SRI LANKA

JITENDER RAKHRAI - NOIDA

JOHN BILSLAND - NOIDA

K.C. GUPTA

K.K BURAGOHAIN - JORHAT

KA

ATRINA VEYSEY - CALGARY

B U I L D I N G T H E F O U N D AT I O N

11

Amguri, India

KEN READ - JORHAT

KISHORE KUMAR - NOIDA

KUMUD HAZARIKA - JORHAT

12

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

OPERATIONS REVIEW

Operations Review

LES KONDRATOFF - CALGARY

M.C.ROYCHOUDHARY - JORHAT

MAHIPAL SINGH - NOIDA

MANJU GIRI

B U I L D I N G T H E F O U N D AT I O N

AMGURI – CANORO’S CORE ASSET Background On November 27, 2003, the State of Assam granted the petroleum mining lease to the owners of the Amguri Production Sharing Contract (PSC). An amendment to the Amguri PSC recognizing Canoro as a 60% owner and operator of the Amguri PSC was executed in September 2004. Canoro physically took over operations of the Amguri field in November 2004. With the transfer of operations came one producing natural gas well, Amguri 8A. During the year ended March 31, 2006, this well produced natural gas at a rate of 430 thousand standard cubic feet per day (“mcf/d”). In April 2005, Canoro began its work program for reentering the three suspended wells to re-establish production and test new potential hydrocarbon bearing zones. Work over operations were completed on the first well, Amguri 1. Canoro completed the testing of three potential hydrocarbon zones in this well and temporarily suspended the well as a potential gas producer. The well tested natural gas at rates exceeding 1 mmcf/d. In September, Canoro re-entered Amguri 5 and tested the original producing zone at gross oil rates of 588 barrels per day (“bbl/d”) of 44° API oil and 0.8 mmcf/d of natural gas. Amguri 6 was re-entered and tested next, with gross oil rates of 405 bbl/d of 56° API oil and 2.6 mmcf/d of natural gas. In light of the success of reentries at Amguri 5 and 6, Canoro re-entered Amguri 2 and did not encounter any hydrocarbons. This well has now been converted into a water disposal well. In July 2007, Canoro announced that the Amguri 10B well encountered a 32 meter thick gas-condensate reservoir at a depth of 2,882 meters to 2,914 meters in the Barail formation. This interval is also approximately 26 meters higher and 12 meters thicker than the same sands in the producing Amguri 6 well. The well tested in two intervals with the lower 13 meter interval being tested first. This interval flowed at a clean-up test rate of 375 bbl/d of 50° API condensate and 1.1 mmcf/d of natural gas through a 12/64 inch choke and tubing head pressure of 2,200 psi with less than 5% BS&W. In early August 2007, Canoro began drilling operations at the Amguri 11 appraisal location on the Amguri development block. Later that month, Canoro announced that it drilled Amguri 11 through the Barail to a depth of 3327 meters. The well discovered two new reservoirs and the main sand (totaling 65 meters of net pay), and flowed at a total of 1,190 bbl/d of condensate and 12 mmcf/d of natural gas, or 3,190 barrels of oil equivalent per day (“boe/d”). Key features of the Amguri PSC The Company’s interests in the Amguri field are governed by a production sharing contract between the Government of India (“GOI”), Canoro (60%) and its partner, Assam Company Limited (40%). The Amguri PSC contains a number of key provisions in that:

i.

it enables the Amguri partners to recover all exploration, development and production costs and expenses incurred (collectively, the “Investment”) in a field or block from the petroleum produced from that field;



ii.

it establishes formulas for sharing the petroleum produced over and above the amount required for Investment recovery (the “Profit Petroleum”). In the Amguri Field, the GOI is entitled to a 10% net profits interest in the Profit Petroleum once the Company and its partner have recovered 100% of its investment in the block from cash flows from the block. The GOI’s net profits interest increases to a maximum of 35% once 300% of the Investment has been recovered;



iii.

it grants the Amguri partners the right to market natural gas to third parties at market determined prices;



iv.

the partners are required to sell crude oil produced to the GOI at international prices;



v.

it provides a term of 25 years with provision for the GOI to grant extensions for oil and gas production for such terms as mutually agreed between the parties considering the balance of recoverable reserves;

GOSWAMI - NOIDA

MANOJ KUMAR GUPTA - NOIDA

MRIGANKA BORGOHAIN - JORHAT

13

14

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

REVIEW OF OPERATIONS



vi.

it provides that at the end of the contract life, all of the wells, facilities, and infrastructure equipment associated with a particular block or field be returned to the GOI;



vii.

a 10% royalty assumed by the natural gas purchaser, payable to the GOI on natural gas production;



viii.

a combination of royalty and cess payments of 1,455 Indian rupees (“Rs”) per metric tonne of oil (approximately $3.88 per barrel of condensate using an exchange rate of Rs 50 = US$1 as at March 31, 2009) is payable on crude oil production; and



ix.

it provides that the GOI has the right to terminate the Amguri PSC on 90 days notice upon the occurrence of certain events, including certain breaches of the Amguri PSC by the Amguri partners.

Operational review Production for the year ending 31 March 2009 averaged 781 boe/d net to Canoro representing a 162 percent increase over the prior year. Production consisted of 3.2 mmcf/d gas and 244 bbls/d of condensate production, a ratio of 69/31 gas to oil. Canoro received an average gas price of $2.45 mcf for gas and $97.32 bbl of condensate. Production originated from the Main Barail sand formation in wells A-6, A-10B, A-11 (known as the “A” pool), the Main Barail Sand in A-5 and also from the Tipam formation in the A-8A well, prior to this zone watering out and being suspended in September 2008. PVT (Pressure – Volume – Temperature) data acquired in March 2008 clearly identified the Amguri “A” pool as defined by wells A-6, A-10B and A-11, as a retrograde gas condensate reservoir. The condensate from the “A” pool measures 56-60 degree API and receives a premium price to Nigerian Bonny Light due to the high quality of condensate produced. As a result of prudent reservoir management practices, a detailed Front End Engineering Deisgn (“FEED”) study was conducted in Q1 FY2008 to discern the feasibility of installing compression for the “A” pool. The facility went through detail design and orders have been placed for compression equipment fabrication. The gas recycling scheme is projected to have a material impact on Canoro’s funds flow from operations as its production mix is projected to change from approximately 30% condensate to over 60% condensate. The recycling scheme should also mitigate the impact of seasonal demand factors as the Company will still be able to extract condensate regardless of natural gas demand in the region. During the year, the Company drilled three wells in the Amguri field with mixed results: Amguri 13 - Canoro spud Amguri 13A in early February and unfortunately the well came in 10 meters lower than anticipated based on seismic interpretation. The Company decided to sidetrack the well. Amguri 13B encountered two hydrocarbon-bearing zones in the Barail formation, based on log and drilling results. A 13-B well came in approximately 10 meters structurally higher than the original Amguri 1 discovery well. The well had approximately 10 meters of net oil pay and 24 meters of potential net gas pay in the Barail formation. The oil pay correlates to the main Barail sand in Amguri 1, while the gas pay correlates to the upper gas zone previously tested in Amguri 1. Drilling complications prevented the completion and testing of the well. Based on a full re-interpretation of the field, the Company will determine the possibility of whipstocking the well or performing a slim hole completion. Amguri 12 - the Company had high expectations for the Amguri-12 well, however, after production testing, the two main Barail intervals were unsuccessful despite log analysis indicating the presence of hydrocarbons. The well tested water in both target Barail sands. The A-12 well came in significantly lower than prognosis and appears to be in a separate compartment and not connected to the “A” pool as defined by the A-11, A-10B and A-6 producers. The disappointing results of A-12 led the Company to cease further drilling and completely re-evaluate its geologic structural model with the aid of Pre-Stack Depth Migration (“PSDM”) seismic processing.

NAREN KONWAR - JORHAT

NILKANT DHINGIA PHUKAN - JORHAT

NITUL ALI - JORHAT

NITUL KAK

B U I L D I N G T H E F O U N D AT I O N

15

AMGURI FIELD Canoro Low Pressure Gas Pipeline Canoro Low Pressure Gas Pipeline (alternative) Assam Gas Company Ltd. (AGCL) Oil Pipeline Assam Gas Company Ltd. (AGCL) Oil Pipeline (alternative) Canoro Low Pressure Gas Pipeline Existing pools Canoro Low Pressure Gas Pipeline Block boundary (alternative) Railway Assam Gas Company Ltd. (AGCL) Pipeline Rivers Oil / Waterbodies

Amguri 13B A-9

Amguri 5

A-13B

A-5

Tipam B A-2

A-8a

Amguri A Pool

A-14

A-11

Tipam A

A-3

A-13B

A-5 A-10

Tipam B

A-8a

A-2

A-12

A-10B TK-5

REC-7

Dry and abandoned

Block boundary

Abandoned O&G

HW-1

Railway

Suspended

Rivers / Waterbodies

A-1

Suspended Oil Tea Gardens

A-13

Suspended Gas Faults Gas with condensate Dry and abandoned

A-8 A-3

A-6

Assam Gas Company Ltd. Tea Gardens (AGCL) Oil Pipeline (alternative) Faults Existing pools

Amguri 13B

A-8 A-10B A-6 A-9 Amguri 5

A-1 A-13

Gas Abandoned O&G

HW-1

Suspended

Amguri A Pool

A-14

A-11

Tipam A

Suspended Oil Suspended Gas

A-10

Gas with condensate

A-12 REC-7

Gas

TK-5

Amguri 14 - the appraisal well was flow tested in the upper Tipam formation. A three-day production test yielded maximum rates of 4.8 mmscfd on an 8mm choke with a tubing head pressure of 2100 pounds per square inch (“psi”), and a stabilized final rate of 2.7 mmscfd on a 6 mm choke with a tubing head pressure of 2,180 psi. These results combined with a subsequent pressure build-up test, support the Company’s view that the A-14 well is an excellent dry gas well. This well re-establishes the Tipam formation as a viable producing zone at Amguri. This Tipam formation production enables the Company to utilize the well as a swing producer to service the local cyclical gas markets while also assisting with voidage replacement within the Main Barail gas condensate reservoir once compression is installed. The Company completed the construction of a four-inch diameter sales gas flow line in Q2 2009 to service local markets. The A-14 well is planned to be connected to the gas re-injection flow-lines for compression support to the “A” pool by early 2010. Additionally, the A-14 well assists the Company to observe prudent reservoir management practices for the “A” pool by supporting local gas markets until compression is installed beginning in Q1 2010. Development of Amguri Field The following development activities are planned for 2009/10:

Earlier in the year, the Company completed the evaluation of bids for gas re-injection and condensate extraction

facilities at Amguri. The main equipment packages have been awarded for manufacture with commissioning expected by early 2010 based on manufacturers’ current delivery dates; The Amguri-II well is planned to be recompleted as a dual producer/injector;

l

 Completion of the Pre-Stack Depth Migration Analysis of existing 3D seismic in progress and reconstruction of

l

the geological model along with 2D reinterpretation is also proposed to be taken up and completed by Q4 2009;  Construction of new oil receiving facility at Moran to receive and pump enhanced oil production to the Oil India–

l

operated pump station through a 1.2 km four-inch pipeline – this is expected to decrease the oil treatment costs of the condensate production and allow for increased netbacks;  Installation of produced water treatment and conditioning facilities to facilitate produced water disposal into the

l

Amguri-2 well using a water injection pump.

OTI - JORHAT

NITYAM THAKURIA - JORHAT

PALLAV BARUAH - JORHAT

PANKAJ TAXALI - NOIDA



16

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

REVIEW OF OPERATIONS

Canoro is focusing all efforts in 2009/10 on development projects to increase production on a low cost basis and lower operating costs. Once the interpretive results of the PSDM are known, the Company plans to embark upon another cycle of drilling activity in 2010/11 that will be reflected in an updated Plan of Development document to be submitted to industry regulators in Q4 2009.

EXPLORATION blocks AA-ONN-2003/2 (CANORO 15% WI) On the Arunachal Pradesh Block AA-ONN-2003/2, the operator has contracted a drilling rig and commenced location and road building. Canoro and its joint venture partners have a commitment under the PSC to drill seven wells. At present, however, based on current interpretation of the 3D seismic, only three drillable prospects have been identified and approved for drilling to date. It is anticipated that the operator will complete the three wells by early 2010 with estimated expenditures of $3.0 million net to Canoro’s 15% working interest. AA-ON/7 (canoro 65% wi) Unique to the oil & gas industry in India, the AA-ON/7 block boundaries are spread over the two adjoining states of Assam and Nagaland. One Petroleum Exploration License was issued for each state in 2001 and 2006 respectively. The Exploration period for the PEL issued in 2001 ended in March 2008. The Company had filed an application for extension of this period by one year to take up additional activities. During the year, the Company drilled two wells, Borkathani and Deragon II on the Assam portion of AA-ON/7. Both exploration wells failed to find commercial hydrocarbons and were plugged and abandoned. Subsequent to drilling and abandonment of the Bhorkatani and the Deragon II wells, the Company withdrew its application to the Government of India seeking an extension of the exploration phase thereby relinquishing the Assam portion of the AA-ON/7 Block. As a result of the relinquishment, probable reserves of 21.2 BCF (3.5 MMBOE) net to Company’s 65% working interest and possible reserves of 15.8 BCF (2.6 MMBOE) net have been written off by the Company. Proven reserves are unaffected by this relinquishment. With respect to the PEL issued in 2006 for the Nagaland area, the Company’s application on behalf of the partners for a new PSC has been submitted to the Government of India. AA-ONN-2004/3 & AA-ONN-2004/5 In Q4 2008, Canoro entered into a farm-in agreement with a large Indian industrial company on two blocks in Northeast India. Blocks AA-ONN-2004/3 and AA-ONN-2004/5 have a combined area totaling 1,285 km2 and are subject to GOI approvals. These blocks have a Phase I commitment that require 2D and 3D seismic programs, which is proposed to be taken up in late 2009 or early 2010 and the drilling of one exploration well on each block. The estimated capital expenditures required on these blocks for Phase I over the next three years is approximately $6.8 million net to Canoro’s 30% working interest. Procedures for the transfer of the 30% interest and operatorship to Canoro are subject to certain agreements being completed along with approvals of the Government of India. However, there is no guarantee the Government of India will approve the transaction and therefore Canoro would not have an interest in the blocks. On completion, Canoro would have a 30% participating interest and would be the operator of both blocks. Initial exploration of these blocks is anticipated to commence in 2009/10 with Phase I commitments that require 2D and 3D seismic programs, which will be deferred to later this year or early 2010, and the drilling of one exploration well on each block.

POOJA AERON - NOIDA

POOJA AWASTHI - NOIDA

PRAMODE CHETIA - JORHAT

PRANJIT BORAH - JO

ORHAT

B U I L D I N G T H E F O U N D AT I O N

RESERVES Sproule Associates Limited (Sproule), an independent petroleum engineering firm, has evaluated the crude oil, natural gas and natural gas liquids reserves of the Company as at March 31, 2009 and prepared a reserves report in accordance with National Instrument 51–101 “Standards of Disclosure for Oil and Gas Activities”. Sproule based its evaluation on land data, well and geological information, reservoir studies, estimates of onstream dates, contract information, operating cost data, capital budgets and future operating plans provided by the Company, information obtained from public records and Sproule’s internal non–confidential files and commodity price forecast. The Reserves Committee, with the mandate of reviewing the independent engineering report, recommended the acceptance of the Sproule reserve estimates and it has been approved by the Board of Directors for the purposes of the Annual Report. See the Company’s Annual Information Form (AIF) for additional reserve information. Reserve Reconciliation (forecast prices)

Proved

Proved + Probable

Proved +Probable +Possible

March 31, 2008 (mboe)

2,773

6,329

10,263

Net additions / revisions

1,456

1,328

1,309

Production

(285)

(285)

AMGURI GROSS RESERVES (1)

March 31, 2009 (mboe) Production replacement (%)

(285)

3,944

7,372

11,287

511

466

459

AA-ON/7 GROSS RESERVES (1) March 31, 2008 (mboe)

–

3,525

6,154

Relinquishment (2)

–

(3,525)

(6,154)

Production

–

–

–

March 31, 2009 (mboe)

–

–

–

Production replacement (%)

–

–

–

March 31, 2008

2,773

9,853

16,417

Net additions

1,456

(2,196)

(4,845)

(285)

(285)

COMPANY GROSS RESERVES (2), (3)

Production March 31, 2009 Production replacement (%)

(285) 3,944 511

7,372 (770)

11,287 (1,700)

(1) Gross reserves represent the Company’s 60% interest before deducting royalties (2) During the year the Company relinquished the Assam portion of the AA-ON/7 block (3) Includes both Amguri and AA-ON/7 reserves

PRASANTHA PHUKAN - JORHAT

PROSENNJIT PHUKAN - JORHAT

RAHUL AWASTHI - NOIDA

17

18

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

REVIEW OF OPERATIONS

AMGURI GROSS RESERVES (1), (3)









2009

Proved producing oil and NGL (mbbls)

2008

% change

391

356

10

Proved producing natural gas (mmcf)

7,582

4,692

62

Total proved producing (mboe)

1,655

1,138

Proved developed not producing oil and NGL (mbbls) Proved developed not producing natural gas (mmcf)

– 4,239

45

32

(100)

63

6,597 1,580

Total proved developed not producing (mboe)

707

42

Proved undeveloped oil and NGL (mbbls)

392

527

(26)

Proved undeveloped (mmcf)

7,146

6,401

12

Total proved undeveloped (mboe)

1,583

1,594

(1)

Total proved (mboe)

3,944

2,773

42

953

1,031

(8)

Probable oil and NGL (mbbls) Probable natural gas (mmcf)

14,848

15,148

(2)

Total probable (mboe)

3,428

3,555

(4)

Proved + probable oil and NGL (mbbls)

1,736

1,945

(11)

Proved + probable natural gas (mmcf)

33,815

26,304

29

Total proved plus probable (mboe)

7,372

6,329

16

Possible oil and NGL (mmbls)

839

1,944

(57)

18,456

11,947

54

Total possible (mboe)

3,915

3,935

(0)

Proved + probable + possible oil and NGL (mbbls)

2,575

3,888

(34)

Possible natural gas (mmcf)

Proved + probable + possible natural gas (mmcf)

52,271

38,250

37

Proved + probable + possible (mboe)

11,287

10,263

10

2009

2008

% change

AA-ON/7 GROSS RESERVES (1), (3) Proved producing oil and NGL (mbbls)

–

–

–

Proved producing natural gas (mmcf)

–

–

–

Total proved producing (mboe)

–

–

–

Proved developed not producing oil and NGL (mbbls)

–

–

–

Proved developed not producing natural gas (mmcf)

–

–

–

Total proved developed not producing (mboe)

–

–

–

Proved undeveloped oil and NGL (mbbls)

–

–

–

Proved undeveloped (mmcf)

–

–

–

Total proved undeveloped (mboe)

–

–

–

Total proved (mboe)

–

–

–

Probable oil and NGL (mbbls)

–

Probable natural gas (mmcf)

–

21,147

Total probable (mboe)

–

3,525

Proved + probable oil and NGL (mbbls)

–

Proved + probable natural gas (mmcf)

–

21,147

Total proved plus probable (mboe)

–

3,525

Possible oil and NGL (mmbls)

–

Possible natural gas (mmcf)

–

15,776

(100)

Total possible (mboe)

–

2,629

(100)

Proved + probable + possible oil and NGL (mbbls)

–

Proved + probable + possible natural gas (mmcf)

–

36,923

(100)

Proved + probable + possible (mboe)

–

6,154

(100)

RAJEEV KUMAR SINGH - NOIDA

RAJEN CHANDRA SARMAH - JORHAT

–

– (100) (100)

– (100) (100) –

–

–

RAJEN GOGOI - JORHAT

RAJE

B U I L D I N G T H E F O U N D AT I O N

COMPANY GROSS RESERVES (1), (2), (3) 2009

Proved producing oil and NGL (mbbls)

2008

% change

10

391

356

Proved producing natural gas (mmcf)

7,582

4,692

62

Total proved producing (mboe)

1,655

1,138

45

Proved developed not producing oil and NGL (mbbls) Proved developed not producing natural gas (mmcf)

– 4,239

32

(100)

63

6,597 1,580

Total proved developed not producing (mboe)

707

42

Proved undeveloped oil and NGL (mbbls)

392

527

(26)

Proved undeveloped (mmcf)

7,146

6,401

12

Total proved undeveloped (mboe)

1,583

1,594

(1)

Total proved (mboe)

3,944

2,773

42

953

1,031

(8)

14,848

36,295

(59)

Total probable (mboe)

3,428

7,080

(52)

Proved + probable oil and NGL (mbbls)

1,736

1,945

(11)

Proved + probable natural gas (mmcf)

33,815

47,451

(29)

Total proved plus probable (mboe)

7,372

9,853

(25)

Probable oil and NGL (mbbls) Probable natural gas (mmcf)

Possible oil and NGL (mmbls)

839

1,944

(57)

18,456

27,723

(33)

Total possible (mboe)

3,915

6,564

(40)

Proved + probable + possible oil and NGL (mbbls)

2,575

3,888

(34)

Proved + probable + possible natural gas (mmcf)

52,271

75,173

(30)

Proved + probable + possible (mboe)

11,287

16,417

(31)

Possible natural gas (mmcf)

Gross reserves represent the Company’s interest before deducting royalties Includes both Amguri and AAON/7 reserves (3) Columns may not add due to rounding (1) (2)

RESERVE LIFE INDEX The reserve index of Canoro has been calculated by using the average 2009 production of 781 boe/d. Accordingly, the reserve life index is 26 years on a proved plus probable basis. Reserves – March 31, 2009 Reserves Production Reserve life index (years)

Proved

Probable

Proven + Probable

3,944

3,428

7,372

285

285

285

13.8

12.0

25.8

Net present value – before tax – forecast prices (US$000) as at March 31, 2009

Proved developed producing Proved developed non–producing

0%

5%

10%

15%

31,388

27,248

23,995

21,388

5,381

3,932

2,953

2,269

Proved undeveloped

24,255

16,279

11,008

7,443

Total proved

61,024

47,459

37,956

31,100

Total probable

77,253

51,319

35,068

24,494

138,277

98,778

73,024

55,594

66,438

39,022

25,623

18,312

204,715

137,800

98,647

73,906

Total proved + probable Total possible Total proved + probable + possible

ESH MADAN - NOIDA

RAJIB BORAH - JORHAT

RAJIB KUMAR PHUKAN - JORHAT

19

20

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

REVIEW OF OPERATIONS

Net present value – AFTER tax – forecast prices (US$000) as at March 31, 2009

Proved developed producing Proved developed non–producing

0%

5%

10%

15%

31,388

26,639

22,962

20,057

5,381

3,843

2,824

2,126

Proved undeveloped

21,766

14,307

9,439

6,192

Total proved

58,535

44,789

35,225

28,375

Total probable

42,287

27,828

18,789

12,904

100,822

72,617

54,014

41,279

36,612

21,679

14,501

10,617

137,434

94,296

68,515

51,896

Total proved + probable Total possible Total proved + probable + possible

Independent Evaluator’s Commodity Pricing Assumptions Amguri Natural Gas Nigeria Bonny Light Crude Oil

Year

($/Bbl)

Proved

Proved plus Probable plus Possible

Proved plus Probable

($/mcf)

($/mcf)

Annual Cost Inflation Rate

($/mcf)

2009 (9 mos)

48.10

2.13

2.13

2.13

3.7%

2010

53.89

2.20

2.20

2.20

4.0%

2011

58.80

2.31

2.50

3.25

3.0%

2012

73.78

2.43

3.14

4.21

2.0%

2013

79.56

2.55

3.59

4.29

2.0%

2014

81.15

2.68

4.04

4.37

2.0%

2015

82.77

2.73

4.46

4.46

2.0%

2016

84.43

2.79

4.55

4.55

2.0%

2017

86.12

2.84

4.64

4.64

2.0%

2018

87.84

2.90

4.74

4.74

2.0%

2.0%

2.0%

2.0%

2.0%

2.0%

Thereafter per year NET ASSET VALUE

The net asset values of the Company as at March 31, 2009 at a discount rate of five, ten and fifteen percent before taxes are summarized below: Estimated net future revenues (1) (US$000)

5%

10%

15%

Proven

47,459

37,956

31,100

Proven + probable

98,778

73,024

55,594

137,800

98,647

73,906

6,989

6,989

6,989

Proven + probable + possible Working capital at March 31, 2009 Total asset value (2) (US$000) Proven

54,448

44,945

38,089

Proven + probable

105,767

80,013

62,583

Proven + probable + possible

144,789

105,636

80,895

Common shares outstanding

113,708,941

113,708,941

113,708,941

Proven

$ 0.48

$ 0.40

$ 0.33

Proven + probable

$ 0.93

$ 0.70

$ 0.55

Proven + probable + possible

$ 1.27

$ 0.93

$ 0.71

Basic net asset value per share (US$)

(1) before income taxes and reclamation costs (2) estimated net future revenue plus working capital at March 31, 2009

RANDEE EASTGAARD - CALGARY

RANJEET BORUAH - JORHAT

RIKHYA NATH DAS - JORHAT

RITISH P

PHUKAN - JORHAT

B U I L D I N G T H E F O U N D AT I O N

21

Management’s Discussion & Analysis

ROBERT WYNNE - CALGARY

ROBIN GOGOI - JORHAT

ROGER SAKATCH - CALGARY

22

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

MANAGEMENT’S DISCUSISON & ANALYSIS

Management’s Discussion and Analysis For the three and twelve months ended March 31, 2009

Basis of Presentation The following discussion and analysis as provided by the Management of Canoro Resources Ltd. (“Canoro” or “Company”) as of July 27, 2009 is to be read in conjunction with the accompanying audited financial statements and related notes for the years ended March 31, 2009 and 2008. The financial data presented has been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). The reporting and the functional currency is the United States dollar (US$). Effective April 1, 2008, the Company’s functional currency changed from Canadian dollars to US$ as a result of increased significance of the US$ to the Company’s cash flows. Amongst other things, this increased significance of the US$ is a result of increased capital expenditures in US$ and an increased proportion of revenues earned in US$. As both the functional and the reporting currencies of the Company are in US$, there are no translation gains and losses that will impact accumulated other comprehensive income. Monetary assets and liabilities of the Company that are denominated in currencies other than US$ are translated into its function currency at the rates of exchange in effect at the period end date. Any gains and losses are recorded in earnings. Forward-Looking Statements

Certain statements included or incorporated by reference in this MD&A constitute

forward-looking statements or forward-looking information under applicable securities legislation. Such forward-looking statements or information are for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward-looking statements or information typically contain statements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project” or similar words suggesting future outcomes or statements regarding an outlook. Forwardlooking statements or information in this MD&A include, but are not limited to, statements or information with respect to: business strategy and objectives; development plans; exploration plans; acquisition and disposition plans and the timing thereof; reserve quantities and the discounted present value of future net cash flows from such reserves; future production levels; capital expenditures; net revenue; operating and other costs; royalty rates and taxes. Forward-looking statements or information are based on a number of factors and assumptions that have been used to develop such statements and information but may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions may be identified in this MD&A, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost-efficient manner; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the countries in which the Company operates; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions that may have been used. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties that could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These risks and uncertainties that may cause actual results to differ materially from the forward-looking statements or information include, among other things: the ability of management to execute its business plan; general economic and business conditions; the risk of war or instability affecting countries or states in which the Company operates; the risks of the oil and natural gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas; market demand; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; risks and uncertainties involving geology of oil and natural gas deposits; the uncertainty of reserves estimates and reserves life; the ability of the Company to add production and reserves through acquisition, development and exploration activities; the Company’s ability to enter into or renew production sharing contracts; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to production (including decline rates), costs and expenses; fluctuations in oil and natural gas prices, foreign currency, exchange, and interest rates; risks inherent in the Company’s marketing operations, including credit risk; uncertainty in amounts and timing of royalty or cess payments; health, safety and environmental risks; risks associated with existing and potential future law suits and regulatory actions against the Company; uncertainties as to

ROY HEATH - JORHAT

RUPANKAR RAJKHOWA - JORHAT

RYAN ELLSON - CALGARY

SADANANDA GO

B U I L D I N G T H E F O U N D AT I O N

the availability and cost of financing; and financial risks affecting the value of the Company’s investments. See page 29 of the MD&A for a further discussion of specific risks and uncertainties. Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties. Additional risk factors affecting the Company and its business are contained in the Company’s Annual Information Form filed on SEDAR at www.sedar.com. Non-GAAP terms The MD&A contains the terms “funds from operations”, and “netbacks” which are not recognized measures under Canadian generally accepted accounting principles. The Company uses these measures to help evaluate its performance. Management considers netbacks an important measure as it demonstrates its profitability relative to current commodity prices. Management uses funds from operations to analyze performance and considers it a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and to repay debt. Funds from operations has been defined by the Company as net earnings adjusted for non-cash items (depletion, depreciation and accretion, stockbased compensation, unrealized (gain)/loss on foreign exchange, and unrealized investment (gain)/loss) and excludes the change in non-cash working capital related to operating activities and expenditures on asset retirement obligations and reclamation. Canoro’s determination of funds from operations may not be comparable to that reported by other companies nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. Barrel of oil equivalent Where amounts are expressed on a barrel of oil equivalent (boe) basis, natural gas volumes have been converted to barrels of oil equivalent at six thousand cubic feet to one barrel of oil equivalent (6 mcf = 1 boe). This conversion ratio is the convention used in the oil and natural gas industry and is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. The use of boe’s may be misleading, particularly if used in isolation.

OPERATIONAL AND FINANCIAL HIGHLIGHTS In accordance with Canadian industry practice, production volumes, reserve volumes and revenues are reported on a Company interest basis, before deduction of royalties. Canoro’s results of operations were dependent on production volumes of natural gas, crude oil and natural gas liquids and the prices received for this production. Production and realized sales prices

Operational and Financial Highlights

Three months ended March 31

Twelve months ended March 31

2009

2008

% change

2009

2008

% change

2,617

1,462

79

3,223

1,153

179

Crude oil (bbl/d)

209

146

43

244

106

130

Total (boe/d)

645

390

66

781

298

162

($ thousands, except per unit amounts)

Natural gas (mcf/d)

Realized gas price ($/mcf)

1.84

2.45

(25)

2.18

2.45

(11)

Realized oil price ($/bbl)

50.64

104.47

(52)

95.76

97.32

(2)

Nigerian Bonny Light ($/bbl)

47.59

99.20

(52)

87.81

84.59

4

Realized price ($/boe)

23.87

48.36

(51)

38.92

44.13

(12)

Royalties ($/boe)

2.86

5.21

(45)

4.00

3.34

20

Operating costs ($/boe)

9.68

6.70

44

5.37

6.93

(23)

11.33

36.45

(69)

29.55

33.86

(13)

Netback ($/boe)

GOI - JORHAT

SANJANA BARUAH - JORHAT

KAMTA PRASAD - NOIDA

SANJEEV GUPTA - NOIDA

23

24

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

MANAGEMENT’S DISCUSISON & ANALYSIS

Production

Production for the three and twelve months ended March 31, 2009 averaged 645 boe/d and 781 boe/d representing a 66 percent and 162 percent increase over the comparative periods. The increase in production is due to production additions from two successful wells, A-10B and A-11, drilled in 2007 and brought onto production in March of 2008. Consequent to detail sampling and transient test data analysis conducted during the last quarter of 2007/08 on these wells, it was determined the reservoir was a retrograde condensate reservoir. Canoro initiated detailed engineering analysis including Front End Engineering Design (FEED). Engineering identified the need of gas recycling to maintain the reservoir pressure at dew point to optimize liquid recovery and practice prudent reservoir management. The engineering studies led to technical specifications of gas compressors and associated equipment for sourcing. After a competitive bid process, the main equipment packages were awarded in the third quarter with commissioning expected in early 2010 based on manufacturers’ delivery dates. The gas recycling scheme is projected to have a material impact on Canoro’s funds flow from operations as its production mix is projected to change from approximately 30% condensate to over 60% condensate. The recycling scheme should also mitigate the impact of seasonal demand factors as the Company will still be able to extract condensate regardless of natural gas demand in the region. Preparations are being made to convert the A-11 well to a dual producer/injector. Canoro plans on injecting gas into the Main Barail zone and produce from the Mid-Barail zone which tested at 2.1 mmcf/d and 280 bbl/d in 2007 through a 16/64 inch choke with tubing head pressure of 2,500 psi. Subsequent to year-end, the Company completed the tie in of A-14 with restricted production rates of 1.0 mmcf/d. A-14 gas is planned to be used for sales and additional re-injection supply. Realized sales price Natural gas

For the three and twelve months ended March 31, 2009 the Company received $1.84 and $2.18 per mcf respectively, compared to $2.45 in the comparative periods. The decrease is attributed to the weakening of the Indian rupee (Rs) against the US dollar throughout the year. The Indian rupee ranged from a high of approximately 40:1 (Rupee to US$) in April 2008 to a low of approximately 52:1 (Rupee to US$) in March 2009. The majority of natural gas production is sold at a fixed price of Rs 3,840 per 1000 m3 , however, contractually the Company must sell the first 12,000 m3/d (approximately 340 mcf/d) at Rs 2,304 per 1000 m³, (approximately $1.64 per mcf). The Company is paid in rupees and is subject to foreign exchange fluctuations on the average price received on changes between the rupee and US$. Although the Company is not directly impacted by fluctuations in global natural gas prices due to the nature its contracts, increases in global natural gas prices results in regional market pressure to increase the price received for natural gas in India. Crude oil

Crude oil prices experienced unprecedented volatility during the year. This in turn, has affected the price of the Company’s benchmark crude, Nigerian Bonny Light which has ranged from a high of $149.87 to a low of $38.26 during the year. Nigerian Bonny Light is a high grade of Nigerian crude oil with high API gravity produced in the Niger Delta basin trading near Brent, and is considered more relevant within India. The increase in the first half of the year was due to strong global demand growth primarily in China and India combined with limited supply and low inventories for oil. During the year, crude oil prices benefited from geo-political events in top producing regions including the Middle East and Africa. The precipitous fall in prices resulted from global demand destruction from the international credit crisis and fears of a global recession. As the year progressed oil demand forecasts became increasingly bearish and were continually revised downwards. For the three and twelve months the Company received $50.64 and $95.76 per bbl compared to the average Nigerian Bonny Light price of $47.59 and $87.81. The Company receives a premium to the Bonny Light due to the high quality of the condensate produced. The Company’s realized sales price for the three and twelve months ended March 31, 2009 was $23.87 and $38.92 per boe respectively, compared to $48.36 and $44.13 per boe for the same period in 2008. The change in realized price received is consistent with the change in the Nigerian Bonny Light price. Petroleum and natural gas sales Petroleum and natural gas sales for the twelve months ended March 31, 2009 were $11.1 million, up 131 percent over the $4.8 million in the prior year. The increase in revenue is attributable to a 162 percent increase in sales volumes offset by an 11 percent decrease in the realized sales price. Petroleum and natural gas sales for the three months ended March 31, 2009 were $1.4 million, down 18 percent from the comparative period in the prior year. The decrease in revenue is due to a 51 percent decrease in the realized sales price offset by a 65 percent increase in sales volumes.

SANJIB BARUAH - NOIDA

SARAT CHAND GOGOI - NOIDA

SHIRLEY TAYLOR - CALGARY

SIVA DUTTA -

- JORHAT

B U I L D I N G T H E F O U N D AT I O N

Royalties and Cess Three months ended March 31 ($000)

Total Per boe

2009

2008

Twelve months ended March 31

% change

2009

2008

166

183

(9)

1,142

363

2.86

5.22

(45)

4.00

3.34

% change

215 20

The Company pays royalties imposed by the Government of India Petroleum and Natural Gas Rules to the respective State granting the lease in which crude oil is produced. The Company is responsible for paying royalties at a rate of Rs 528 per metric tonne of crude oil produced (approximately $1.41 per bbl). In addition, the Company is responsible for paying cess at the rate of Rs 927 per metric tonne of crude oil sold (approximately $2.47 per bbl). Cess is a levy imposed by the Oil Industry Development Act on crude oil sales and is payable to the Central Government. State and Central royalties are paid in Indian Rupee’s and are subject to foreign exchange fluctuations. Royalties on natural gas are assessed at 10% of well head value of gas and are paid by the purchaser of the natural gas; therefore, the Company does not pay royalties on natural gas production. On September 20, 2007, the Company entered into an agreement with a private fund based in Jersey, Channel Islands, whereby the fund provided limited-recourse funding (“Entitlement Fund”) of $10,000,000 for appraisal and development drilling in the Company’s Amguri Field in Assam, India. The fund does not have a participating interest in the field, nor is it responsible for future capital costs. The fund only receives payments based on the Company’s 60% share of gross revenue from the Amguri Field ranging from 7% before recovery of the original $10,000,000 and 3.5% thereafter. As at March 31, 2009, the fund has recovered approximately $1.0 million. For the three months and twelve months ended March 31, 2009, total royalties and cess on production amounted to $0.2 and $1.1 million compared to $0.2 and $0.4 million in the comparative periods in the prior year. During the three and twelve months ended, the Company continued payments to the Entitlement Fund as per the agreement. Payments to the Entitlement Fund of $0.1 million and $0.8 million respectively, are included in the above royalty figures. The increase in royalties on an absolute basis is due to increased oil production and revenue entitlement payments as per the Entitlement Fund agreement. Operating expenses Three months ended March 31

Twelve months ended March 31

($000)

2009

2008

% change

2009

2008

% change

Total

562

238

136

1,531

756

103

9.68

6.70

44

5.37

6.93

(23)

Per boe

Operating expenses for the three and twelve months ended March 31, 2009 were $0.5 million ($9.68 per boe) and $1.5 million ($5.37 per boe) compared to $0.2 million ($6.70 per boe) and $0.8 million ($6.93 per boe) in the comparative periods in the prior year. The increase in operating costs on an absolute basis is due to an significant increase in production volumes. The decrease in operating expenses per boe for the twelve months ended is due to fixed costs being spread over higher production volumes and operational improvements. The increase in operating costs for the three months ended is due to non-recurring repairs and maintenance charges and an insurance adjustment related to operated wells. The Company continues to be committed to being a low cost producer in North East India. Depletion, depreciation and accretion expense Three months ended March 31 ($000)

2009

2008

Total

1,270

907

Per boe

21.87

25.56

Twelve months ended March 31

% change

2009

2008

% change

40

5,850

3,591

63

(14)

20.51

32.90

(38)

For the three and twelve months ended March 31, 2009 depletion, depreciation and accretion (“DD&A”) was $1.3 million and $5.9 million compared to $0.9 million and $3.6 million in the comparative periods in the prior year. The decrease in the DD&A rate per boe is due to the addition of proven reserves from the successful drilling at Amguri 14, increased proven reserves assigned to A-6, A-10B and A-11 due to additional well performance information obtained during the year offset by a higher capital basis. The increase in DD&A on an absolute basis is due to the increase in production.

SOUMYA SRIKANTH - NOIDA

SUMAN KUMAR - NOIDA

SURAJIT DUTTA - NOIDA

25

26

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

MANAGEMENT’S DISCUSISON & ANALYSIS

Capital expenditures The Company’s total capital expenditures during the three months and twelve months ended March 31, 2009 amounted to $3.8 million and $30.0 million compared to $5.4 million and $13.7 million for the comparative periods in the prior year. The significant increase in capital is due to higher costs of services resulting from record oil prices, additional drilling activity and significant cost overruns at Amguri 12. During the year the Company drilled six wells (3.7 net) with a 32 percent success rate based on net wells compared to three wells (2.4 net) in the prior year. The Company’s exploration and development expenditures were financed through a combination of cash on hand and funds generated from operations. The Company is in the process of re-evaluating its asset base with a concerted effort to reduce exploration risk and have a balanced portfolio of development and exploration opportunities. Work is proceeding on the Pre-Stack Depth Migration (“PSDM”) re-processing and re-interpretation of Amguri 3D seismic data with initial results expected in the second half of the calendar year. During the year, Canoro relinquished the Assam portion of the AA-ON/7 block. Canoro is currently pursuing a new PSC to be established on the Nagaland portion of the AA-ON/7 block which had an exploration license granted in August 2006. There are no guarantees the Company will be granted a new PSC.

CORPORATE Interest income During the three and twelve months ended March 31, 2009, the Company earned interest income of $0.05 and $0.2 million compared to $0.4 million and $0.9 million in the comparative periods in the prior year. The decrease in interest income is due to lower average cash balances, lower interest rates and the Company holding the cash on hand in an operating account in order to have unrestricted access to the funds. General and administrative expenses General and administrative (“G&A”) costs for the three and twelve months ended March 31, 2009 were $1.5 million and $6.9 million compared to $1.7 million and $4.9 million in the comparative periods in the prior year. Overall, G&A costs increased commensurate with increased staffing and activity levels as evidenced by Canoro spending approximately $30.0 million on exploration and development activities in the year. Specifically, G&A costs increased due to: •

increased office space in both Calgary and Delhi;

•

strengthening of the Canadian dollar, as many of the employee’s are paid in Canadian dollars;

•

increased technical and operating personnel, including four additional expatriate staff; and

•

a significant investment in developing and implementing controls and procedures to build a strong foundation to grow the Company as it moves to a development and production company.

With the decrease in activity projected for 2009/10, the Company during the fourth quarter began to reduce its personnel and made it a mandate to all employees, contractors and suppliers to reduce costs. A significant portion of the costs incurred in 2008/09 were one time set-up costs and development costs and will be non-recurring in 2009/2010. Canoro is forecasting G&A costs for 2009/10 be approximately $4.0 – $4.8 million, a reduction of approximately 41 percent to 29 percent from 2008/09 levels. Canoro believes it has assembled the necessary personnel to take the Company from an exploration company to an exploration and production company with the ability to significantly increase reserves and production. Stock based compensation expense Stock-based compensation expense is the amortization over the vesting period of the fair value of stock options granted to employees, directors and key consultants of the Company. The fair value of all options granted is estimated using the Black-Scholes option pricing model. The non-cash compensation expense for the three months and twelve months ended March 31, 2009, was $0.2 million and $1.2 million compared to $1.5 million and $2.7 million in the comparative periods in the prior year. The decrease in stock based compensation expense is primarily due to a lower average option price resulting from lower average market prices at the time of grant and a decrease in the amount of options granted during the year. Canoro believes that providing employees with stock options effectively aligns the employees’ goals with the shareholders and helps retain key employees. During the year the Company re-priced 1.6 million stock options held by employees representing approximately 15 percent of the total options outstanding. The Company did not re-price any stock options held by Officers or Directors of the Company.

SURENDRA SINGH - NOIDA

SWEETY TAMULY - JORHAT

TOM LOCH - CALGARY

UTPAL BORA - JORH

HAT

B U I L D I N G T H E F O U N D AT I O N

Net loss For the three and twelve months ended March 31, 2009, Canoro recorded a net loss of $2.7 million and $6.3 million compared to a net loss of $1.0 million and $7.1 million in the comparative periods in the prior year. Earnings for the three and twelve months ended were adversely affected by non-cash items such as depletion, depreciation, accretion, unrealized foreign exchange, unrealized investment loss and stock-based compensation. Liquidity and Capital Resources Share Capital

At March 31, 2009, the Company had 113,708,941 common shares outstanding (March 31, 2008 – 112,992,273). The common shares of Canoro trade on the TSX Venture Exchange under the symbol CNS. The following table summarizes outstanding share data for the three and twelve months ended March 31, 2009. Three months ended

Twelve months ended

March 31, 2009

March 31, 2009

113,708,941

113,565,580

Weighted average shares outstanding Basic

–

–

113,708,941

113,565,580

0.36

1.64

Options (1) Diluted Trading Statistics High

0.07

0.07

511,729

315,113

Low Average daily volume (1) Anti-dilutive incremental options are excluded from the weighted average diluted shares outstanding.

At July 27, 2009, the Company had 113,708,941 shares outstanding and 10,262,000 options outstanding. Capital Resources

At March 31, 2009, the Company had $7.0 million of net working capital, including cash and cash equivalents of $5.5 million and no debt. As a result of the current global financial crisis, the availability of both equity and debt has tightened significantly. Management anticipates the Company will have adequate liquidity and capital resources to fund its capital expenditures through a combination of cash flow from operations and cash on hand. In the event that debt and equity markets continue to be difficult or a there is a prolonged down turn in commodity prices, the Company would consider strategic alternatives including but not limited to a strategic merger, disposition of assets, or reduction in capital program. Failure to obtain such financing on a timely basis could cause the Company to forfeit its interest in certain properties and reduce or terminate operations. Contractual obligations, commitments and contingencies

Pursuant to current production sharing contracts (“PSC’s”) the Company is required to perform minimum exploration activities that include acquisitions and processing of seismic data and drilling of exploration wells. The Company plans to fund these costs with existing cash balances and cash flow from operations. These obligations have not been provided for in the financial statements. The Company has office lease commitments in Noida and Jorhat in India and Calgary, Canada. The following are the anticipated payments under the contracts: PSCs

Office leases

Total

2009

$ 2,746

$ 656

$ 3,402

2010

6,300

556

6,856

2011

3,394

247

3,641

2012

2,100

164

2,264

Total

$ 14,540

$ 1,623

$ 16,163

On September 20, 2007 the Company entered into an agreement with a private fund based in Jersey, Channel Islands, whereby the fund provided limited-recourse funding of $10.0 million for appraisal and development drilling in the Company’s Amguri Field in Assam, India. The funds have been expended.

UZZAL GOGOI - JORHAT

VIJAY PAL KANOJIA - NOIDA

27

28

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

MANAGEMENT’S DISCUSISON & ANALYSIS

The fund does not have a participating interest in the field, nor is it responsible for future capital costs. The fund only receives payments based on the Company’s 60 percent share of gross revenue from the Amguri Field ranging from seven percent before recovery of the original $10.0 million and 3.5 percent thereafter. The agreement provides that the Company shall have a termination option between September 20, 2010, the third anniversary of the agreement, and December 31, 2012 to buy back the fund’s entitlement for $15.0 million before recovery, or for $12.8 million after recovery of the fund’s initial $10.0 million. If this termination option is exercised by the Company, the fund will be granted, subject to TSX approval, 5.0 million warrants to acquire 5.0 million common shares of the Company, exercisable within nine months from the date of issue at an exercise price of Cdn$2.00 per common share. If the Company declines to exercise the termination option within the stated time period, the fund will retain its revenue entitlement to the Amguri field. Subsequent Events

On June 1, 2009, High Artic Energy Services L.P. (HAES) filed a statement of claim in the Court of Queen’s Bench of Alberta

against the Company for the amount of $1.3 million relating to invoices submitted to the Company. On June 30, 2009 the Company filed a defence to the HAES claim as well as a counterclaim for damages of $5 million, an Order for an accounting of the costs and expenses invoiced to the Company by HAES, pre-judgment interest and costs. On July 22, 2009 HAES filed a defence to the Company’s counterclaim. As legal proceedings have only recently been commenced, and as no examinations for discovery have yet taken place, the likelihood of success of the claim or counterclaim is not yet determinable. On July 24, 2009, Canoro announced it entered into an agreement with, a private fund (“Fund”) based in Jersey, Channel Islands, whereby the Fund will provide limited-recourse funding of US$4 million for the purchase and installation of the gas compression units as part of development operations in the Amguri Field in Assam, India. The Fund will not earn a participating interest in the field, nor will it be responsible for future capital costs. The Fund will only be entitled to receive repayments based on Canoro’s 60% share of gross revenue from the Amguri Field ranging from 8% before recovery of the original US$4 million, declining to 4% thereafter. The agreement also provides that Canoro shall have the option between July 2012 and December 31, 2012 after the Fund’s recovery of its initial investment, to buy back the Fund’s entitlement for US$5.1 million. If such option is exercised by Canoro, the Fund will be granted, subject to TSX Venture approval, warrants to subscribe for two million common shares of the Company, exercisable within six months from the date of issue at a subscription price of CDN $0.20 per share.

SUMMARY OF QUARTERLY RESULTS 2009

($ thousands, except per share amounts)

2008

Q4

Q3

Q2

Q1

Q4

Q3

Q2

Q1

Petroleum and natural gas sales

1,386

1,500

4,012

4,201

1,715

1,091

1,253

748

Cash flow from/ (used) in operating activities

1,405

(2,422)

4,406

(1,700)

(3,220)

(3,327)

276

77

Net Loss

(381)

(755)

(1,974)

(1,438)

(2,921)

(2,663)

(2,678)

(582)

Per share – basic and diluted

(0.02)

(0.02)

(0.01)

–

(0.01)

(0.02)

(0.02)

(0.03)

Capital expenditures

3,829

11,685

7,898

6,588

5,445

3,253

138

4,871

645

651

923

904

390

287

295

267

Total Assets 88,786 92,842

90,604

91,704

90,364

90,098

67,732

59,974

Total boe/day

The fluctuations in petroleum and natural gas sales over the past eight quarters is due to the volatility in oil prices and increased production volumes in fiscal 2009 over fiscal 2008. The Company has reported a loss over the past eight quarters primarily due to non-cash charges such as depletion and stock-based compensation. During the fourth quarter of 2009, the Company’s capital expenditures decreased significantly as a result of both drilling rigs being released at the end of December 2008. The decrease in production volumes over the past two quarters is due to decreased seasonal demand in the region and prudent reservoir management. Total assets have remained relatively flat since the third quarter of 2008. The large increase in total assets in the third quarter of 2008 is due to the financing that closed in December 2007.

B U I L D I N G T H E F O U N D AT I O N

Risk and uncertainties Financial Resources

The Company’s cash flow from operations may not be sufficient to fund its ongoing activities and implement its business plans. From time to time the Company may enter into transactions to acquire assets or the shares of other companies. Depending on the future exploration and development plans, the Company may require additional financing, which may not be available or, if available, may not be available on favorable terms. Failure to obtain such financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate operations. If the revenues from the Company’s reserves decrease as a result of lower oil and natural gas prices or otherwise, it will effect its ability to expend the necessary capital to replace its reserves or to maintain its production. If cash flow from operations are not sufficient to satisfy capital expenditure requirements, there can be no assurance that additional debt, equity, or asset dispositions will be available to meet these requirements or available on acceptable terms. In addition, cash flow is influenced by factors which the Company cannot control, such as commodity prices, exchange rates, interest rates and changes to existing government regulations and tax policies. Exploration and Development

The exploration and development of oil and gas deposits involve a number of uncertainties that even thorough evaluation, experience and knowledge of the industry cannot eliminate. It is impossible to guarantee that the exploration programs of the Company’s properties will generate economically recoverable reserves. The commercial viability of a new hydrocarbon pool is dependent upon a number of factors that are inherent to reserves, such as the content and the proximity of infrastructure, as well as oil and gas prices, which are subject to considerable volatility, regulatory issues such as price regulation, taxes, royalties, import and export of oil and gas and environmental protection issues. The individual impact generated by these factors cannot be predicted with any certainty, but once combined, may result in non-economic reserves. The Company remains subject to normal risks inherent to the oil and gas industry such as unusual and unexpected geological changes in the parameters and variables of the petroleum system and operations. Operating Hazards and Risks

Exploration for natural resources involves many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. Operations in which the Company has a direct or indirect interest will be subject to all the hazards and risks normally incidental to exploration, development and production of resources, any of which could result in work stoppages, damages to persons or property and possible environmental damage. Although the Company has obtained liability insurance in an amount it considers adequate, the nature of these risks is such that liabilities might exceed policy limits, the liabilities and hazards might not be insurable, or the Company might not elect to insure itself against such liabilities due to high premium costs or other reasons, in which event the Company could incur significant costs that could have a material adverse effect upon its financial condition. Reserve Estimates

Despite the fact that the Company has reviewed the estimated figures related to potential reserve evaluation and probabilities attached thereto and is of the opinion that the methods used to appraise these estimates are adequate, these figures remain estimates, even though they have been calculated or validated by independent appraisers. The reserves disclosed by the Company should not be interpreted as assurances of property life or the profitability of current or future operations given that there are numerous uncertainties inherent in the estimation of economically recoverable oil and gas reserves. Fluctuating Prices

Revenues from oil and gas sales vary accordingly to the existence of cost recovery pool balances. The Company’s revenues, if any, are expected to be in large part derived from the extraction and sale of oil and gas. The price of oil has fluctuated widely, particularly in recent years, and is affected by numerous factors beyond the Company’s control, including international economic and political trends, expectations of inflation, war, currency exchange fluctuations, interest rates, global or regional consumptive patterns, speculative activities and increased production due to new extraction developments and improved extraction and production methods. The effect of these factors on the price of oil, and therefore the economic viability of any of the Company’s exploration projects, cannot be accurately predicted.

29

30

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

MANAGEMENT’S DISCUSISON & ANALYSIS

Environmental Factors

All phases of the Company’s operations are subject to environmental regulation in India. Environmental legislation is evolving in a manner which requires stricter standards and enforcement, increased fines, and penalties for non-compliance, more stringent environmental assessments of proposed projects and a heightened degree of responsibility for companies and their officers, directors and employees. The current exploration, development and production activities of the Company require certain permits and licenses from the Directorate General Hydrocarbons and other governmental agencies and such operations are, and will be, governed by laws and regulations governing exploration, development and production, labor laws, waste disposal, land use, safety, and other matters. There can be no assurance that all licenses and permits that the Company may require to carry out exploration and development of its projects will be obtainable on reasonable terms or on a timely basis, or that such laws and regulation would not have an adverse effect on any project that the Company may undertake. Political Risk

The Company’s projects are located in Northeast India and consequently the Company is subject to certain risks, including currency fluctuations and possible political, economic civil and/or labour unrest which may result in the disruption of exploration and development activities. The states of Assam, Nagaland and Arunachal Pradesh are home to strong independence movements. Over the past several years, varying degrees of social upheaval and criminal activity has occurred in the regions related to these independence movements. While the situation is presently stable in the areas in which the Company operates and the Company believes that it has good relationships in these areas, there can be no guarantee that the Company will not be affected in the future. Additionally, the continued perception that the situation has not stabilized or improved may hinder the Company’s ability to access capital in a timely or cost effective manner. Retention of Key Employees

The Company is dependent on retaining the services of a small number of key personnel of the appropriate caliber as its business develops. The success of the Company is, and will continue to be to a significant extent, dependent on the expertise and experience of the directors and senior management and the loss of one or more could have a materially adverse effect on the Company. Exchange Rate Volatility

To the extent revenues and expenditures denominated in, or strongly linked to, the US dollar and the Indian Rupee (Rs) are not equivalent; the Company is exposed to exchange rate risk. In India, the Company is exposed to the extent that US dollar revenues for crude oil sales do not equal US dollar expenditures and that Rs revenues from natural gas sales do not equal Rs expenditures. The Company is not currently using exchange rate derivatives to manage exchange rate risk. Repatriation of earnings

Currently there are no restrictions on the repatriation from India of earnings to foreign entities. However, there can be no assurance those restrictions on repatriation of earnings from India will not be imposed in the future. Disruptions in Production

Other factors affecting the production and sale of oil and gas that could result in decreases in profitability include: (i) expiration or termination of permits or licenses, or sales price redeterminations or suspension of deliveries; (ii) future litigation; (iii) the timing and amount of insurance recoveries; (iv) work stoppages or other labor difficulties; (v) changes in the market and general economic conditions, monsoon conditions, equipment replacement or repair, fires, civil unrest or other unexpected geological conditions that can have a significant impact on operating results. Financial Risk Management

The Company is exposed to financial risks due to the nature of its business and the financial assets and liabilities it holds. The following discussion reviews material financial risks, quantifies the associated exposures, and explains how these risks, and the Company’s capital, are managed. Additional information in respect of the Company’s risks may be found in the Annual Information Form. a) Market Risk



Changes in commodity prices and foreign currency exchange rates can have an impact on the Company’s earnings and value of financial assets and liabilities.

Commodity price risk – Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. The Company is exposed to commodity price risk due to the nature of its business. Oil and natural gas prices are impacted by global supply and demand, as well as political and other forces. For the majority of natural gas production, the Company receives a fixed price of 3,840 rupees (Rs) per 1000 m3, approximately $2.73 mcf. The Company also has a contract for the life of production sharing contract to sell 12,000 m3/d (approximately 340 mcf per day) at 2,304 Rs per 1000 m³, (approximately $1.64 per mcf). The Company is paid in rupees and is subject to foreign exchange fluctuations on the average price received on changes between the rupee and US$. Although the Company is not directly impacted by fluctuations in natural gas prices due

B U I L D I N G T H E F O U N D AT I O N

to the nature of their contracts, as prices around the world increase for natural gas there is continued market pressures to increase the price received for natural gas in India which would benefit the Company. The Company receives world oil prices for its oil production and is subject to price fluctuations. The price received for crude oil is very volatile and can undergo significant changes in relatively short time periods. The highest monthly average price during the year was $137.96 in the month of July compared to lowest monthly average of price received of $44.37 in the month of December. As at March 31, 2009 the Company did not have any derivative commodity price contracts in place however, in the future, the Company may enter into such contracts in order to manage its commodity price risk. Based on actual sales volumes recorded for the year ended March 31, 2009, a US$1.00 per barrel increase (decrease) in oil prices would have increased (decreased) net earnings by $0.1 million. As the Company continues to increase production, earnings will become more impacted by commodity prices, primarily oil.

Foreign currency exchange rate risk – Foreign exchange rate risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates. The reporting currency of the Company is United States dollars. Substantially all of the Company’s operations are in foreign jurisdictions and as a result, the Company is exposed to foreign currency exchange rate risk on some of its activities primarily on exchange fluctuations between the rupee and the US$. Oil revenues are denominated in US$, while natural gas revenues are denominated in Indian rupees. Operating and capital expenditures are incurred in various currencies, including, US dollars, Indian rupees and Canadian dollars. The majority of capital expenditures are incurred in US$ and oil revenues are received in US$ therefore the Company’s exposure to foreign exchange is minimal. The Company may enter into derivative foreign currency contracts in order to manage foreign currency exchange rate risk, but has not done so to date. The table below shows the Company’s exposure to foreign currencies for its financial instruments: Total

Rs

CAD

US$ Equivalent

Cash and cash equivalents

5,456

5,314

142

–

Accounts receivable

10,400

9,903

485

12

Accounts payable

(9,789)

(9,430)

(174)

(185)

Balance sheet exposure

6,067

5,787

453

(173)

(1)

denotes Financial statements



US$

per FS (1)

As at March 31, 2009





The Company believes a three percent change in the US$ against these foreign currencies would be reasonably possible within the next three month reporting period. A three percent strengthening of the US$ would result in a change in earnings as follows (an equal but opposite impact to earnings would result if the US$ weakened by three percent): Rs As at March 31, 2009

Decrease in earnings

CAD

US$ Equivalent

14

(5)

b) Credit Risk



Credit risk is the risk of a financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligation and arises principally from joint venture partners and natural gas and oil marketers. The Company is exposed to credit risk in respect to its cash and cash equivalents and accounts receivables. Cash and cash equivalents are held in operating accounts with highly rated Canadian banks and therefore the Company considers these assets to have negligible credit risk. Virtually all of the Company’s accounts receivable are from counterparties in the oil and gas industry and are subject to normal industry credit risks. The Company’s production base is entirely in the Assam state in North East India. For both the Amguri and AAON/7 production sharing contracts, the Company has the same joint partner for both contracts thereby significantly concentrating the exposure to credit risk for the Company. The Company believes credit risk from its joint venture partner is mitigated by the default provisions within the production sharing contracts. The default provisions are very punitive to the party in default and can include additional working interest reverting to the operator if certain conditions are not met by the defaulting party. Revenue receivables are from both government agencies in India and large international oil and gas companies. The carrying amount of cash and cash equivalents and accounts receivable represents the Company’s maximum credit exposure.



As at March 31, 2009, the Company’s accounts receivable is aged as follows: Current (less than 90 days)

$

Past due (more than 90 days) Total

8,793 1,607

$

10,400

31

32

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

MANAGEMENT’S DISCUSISON & ANALYSIS

c) Liquidity Risk



The Company manages its risk of not meeting its financial obligations through management of its capital structure, annual budgeting of its revenues, expenditures and cash flows. On a monthly basis, internal reporting of actual results is compared to the budget in order to modify budget assumptions, if necessary, to ensure liquidity is maintained. The Company believes it has adequate cash flows and cash on hand to discharge its financial obligations. In the event that the Company’s receivables are not collected from its joint venture partner, the Company may be required to seek other alternatives of financing which may be unavailable on reasonable terms or curtail capital expenditures to satisfy outstanding obligations.

d) Capital Management



The Company defines its capital as shareholder’s equity. The Company’s objective is to maintain a strong capital position in order to execute its business plan and maximize value to shareholders. Availability of capital is critical for future success and as such, the Company strives to maintain strong relationships with the capital investment community. Methods employed to adjust the



Company’s capital structure could include any, all, or a combination of the following activities: • Repurchase shares pursuant to a normal course issuer bid;



• Issue new shares through a public offering or private placement;



• Issue equity linked or convertible debt;



• Raise fixed or floating rate debt.



The Company is not subject to any externally imposed capital requirements.

Critical accounting policies / critical accounting estimates Canoro’s financial statements have been prepared in accordance with Canadian general accepted accounting principles. Certain accounting policies require management to make decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Canoro’s management reviews their estimates frequently; however, the emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates. Canoro attempts to mitigate this risk by employing individuals with the appropriate skill set and knowledge to make reasonable estimates; developing internal reporting systems; and comparing past estimates to actual results. Petroleum and Natural Gas Reserves

All of Canoro’s petroleum and natural gas reserves are evaluated and reported on by independent petroleum engineering consultants in accordance with Canadian Securities Administrators’ National Instrument 51-101. The evaluation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, commodity prices and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change to reflect updated information. Reserve estimates can be revised upward or downward based on the results of future drilling, testing, production levels and changes in costs and commodity prices. Depletion Expense

The Company uses the full cost method of accounting for exploration and development activities whereby all costs associated with these activities are capitalized, whether successful or not. The aggregate of capitalized costs, net of certain costs related to unproved properties, and estimated future development capital is amortized using the unit-of-production method based on estimated proved reserves. Changes in estimated proved reserves or future development capital have a direct impact on depletion expense. Certain costs related to unproved properties and major development projects may be excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly to determine if proved reserves should be assigned, at which point they would be included in the depletion calculation, or for impairment, for which any write-down would be charged to depletion and depreciation expense. Full Cost Accounting Ceiling Test

The carrying value of property, plant and equipment is reviewed at least annually for impairment. Impairment occurs when the carrying value of the assets is not recoverable by the future undiscounted cash flows. The cost recovery ceiling test is based on estimates of proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Any impairment would be charged as additional depletion expense. Asset Retirement Obligations

The asset retirement obligation is estimated based on existing laws, contracts or other policies. The fair value of the obligation is based on estimated future costs for abandonments and reclamations discounted at a credit adjusted risk free rate. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings and for revisions to the estimated future cash flows. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material.

B U I L D I N G T H E F O U N D AT I O N

Income Taxes

The determination of the Company’s income and other tax assets or liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions including Canada and India. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax asset or liability may differ significantly from that estimated and recorded. Guarantees and off-balance sheet arrangements Canoro has not entered into any off-balance sheet arrangements except for certain lease agreements entered into in the normal course of operations. All leases are operating leases with lease payments charged to operating expenses or general and administrative expenses according to the nature of the lease. Recent Accounting Pronouncements The following accounting pronouncements have been issued by the Canadian Accounting Standards Board, but were not in effect at the date of the current financial statements. These pronouncements may have an impact on the Company’s future financial reporting. Goodwill and Intangible Assets

Effective April 1, 2009, the Company will be required to adopt this standard, which replaces GAAP sections 3062 and 3450 and provides guidance relating to the recognition, measurement, presentation and disclosure of goodwill and intangible assets. The Company is currently assessing the impact of this standard. Convergence of Canadian GAAP with International Financial Reporting Standards (“IFRS”)

In February of 2008, the Canadian Accounting Standards Board confirmed January 1, 2011 as the effective date for the requirement to report under International Financial Reporting Standards (“IFRS”) with comparative 2010 periods converted as well. The Company has developed a high level changeover plan to assess in detail all aspects of the changeover to IFRS, including appropriate changes to accounting policies and financial disclosures, effects on information systems and processes, changes to internal controls over financial reporting and business activities, in order to complete the transition to IFRS by April 1, 2011. The project will be managed by an in-house team of accounting professionals who have attended and will continue to attend training session’s specific to IFRS adoption. The Corporations auditors will be involved throughout the process to access whether the Corporations policies are in accordance with these new standards. Canoro will update its IFRS changeover plan to reflect new and amended accounting standards issued by the International Accounting Standards Board. As IFRS is expected to change prior to 2011, the effect on the Company’s consolidated financial statements is not reasonably determinable at this time.

2009/10 Outlook Strategy

Canoro is engaged in the acquisition, development and exploration for, and production and marketing of petroleum and natural gas in India. Presently, the Company holds two properties or Production Sharing Contracts (PSC) in the States of Assam and Arunachal Pradesh, India. The Company strives to create shareholder value through the acquisition, exploration and development of prospective oil and gas areas in India and elsewhere. The Company has achieved competitive advantages in India by focusing on relationships, experience, technology and good international oilfield practices. While the competition for attractive development properties is intense, the Company believes that this strategy is viable and offers an attractive risk-reward ratio for shareholders. The Company focuses on areas where the management has long-standing experience and above-average relationships. 2009/10 Capital Spending

The Company is forecasting capital expenditures of approximately of approximately $9.0 to $11.0 million over the next 12-18 months primarily on the gas compression project. 2009/10 Production Guidance

For fiscal 2010, the Company is forecasting average production of 700 boe/d to 900 boe/d and an exit rate of in excess of 1,000 boe/d. The exit production is not significantly higher than the average production for fiscal 2010, however, the commissioning of the compression project is projected to change the production mix of the Company from approximately 70 percent natural gas and 30 percent condensate to greater than 60 percent condensate by year end. The impact on cash flow from operations will be significant as the Company received approximately $13.07 per boe for natural gas production and $95.76 per bbl for oil during the year. SEDAR filings Additional information about Canoro is available on the Canadian Securities Administrators’ System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com and at the Company’s website at www.canoro.com.

33

34

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

NOTES TO the Consolidated Financial Statements

Management’s Report The accompanying consolidated financial statements of Canoro Resources Ltd., and all other financial and operating information contained in this report are the responsibility of management. The consolidated financial statements have been prepared in accordance with the accounting policies detailed in the notes to the consolidated financial statements and in accordance with generally accepted accounting principles in Canada. The Company’s systems of internal control have been designed and maintained to provide reasonable assurance that assets are properly safeguarded and that the financial records are sufficiently well maintained to provide relevant, timely and reliable information to management. External auditors, appointed by the shareholders, have independently examined the consolidated financial statements in accordance with generally accepted auditing standards in Canada. They have performed such tests as they have deemed necessary to enable them to express an opinion on these consolidated financial statements. An Audit Committee of the Board of Directors has reviewed these consolidated financial statements with management and the external auditors. The Board of Directors has approved the consolidated financial statements on the recommendation of the Audit Committee.

Les Kondratoff

S. Brian Gieni

President and Chief Executive Officer

Senior Vice President, Chief Financial Officer and Country Manager

July 27, 2009

B U I L D I N G T H E F O U N D AT I O N

Auditors’ Report We have audited the consolidated balance sheets of Canoro Resources Ltd., as at March 31, 2009 and 2008 and the consolidated statements of operations and deficit, comprehensive income, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express and opinion on these consolidated financial statement based on our audit. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at March 31, 2009 and 2008 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

KPMG LLP Chartered Accountants July 27, 2009

35

36

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

Consolidated Financial Statements of Canoro Resources Ltd.

For the years ended March 31, 2009 and 2008

Consolidated Balance Sheets As at March 31

2009

2008

5,456

23,993

(Thousands of United States dollars)

Assets

Current assets Cash and cash equivalents Restricted cash (Note 8) Investment Accounts receivable Inventory

–

9,741

28

80

10,400

8,323

113

401

781

767

16,778

43,305

Property, plant and equipment (Note 4)

72,008

47,059

Total Assets

88,786

90,364

9,789

7,760

859

513

Common shares (Note 7)

86,883

85,597

Contributed surplus (Note 7)

14,051

12,986

Prepaid expenses and deposits

Liabilities and Shareholders’ Equity

Current liabilities Accounts payable and accrued liabilities Asset retirement obligations (Note 5) Shareholders’ equity

Accumulated other comprehensive income Deficit Total Liabilities and Shareholders’ Equity  Future operations (Note 1) Entitlement fund (Note 6) Contingent liabilities (Note 11) Contractual obligations and commitments (Note 12) Subsequent events (Note 14)

See accompanying notes to the consolidated financial statements.

Approved by the Board:

Douglas R. Martin

Robert S. Wynne

Director

Director

8,332

8,332

(31,128)

(24,824)

78,138

82,091

88,786

90,364

B U I L D I N G T H E F O U N D AT I O N

Consolidated Statements of Operations and Deficit Years ended March 31

2009

2008

(Thousands of United States dollars)

Revenues Petroleum and natural gas sales

11,099

4,817

Royalties

(1,142)

(363)

Investment gain Interest income and other

–

26

247

870

10,204

5,350

Expenses Operating

1,531

756

General and administrative

6,929

4,917

Stock-based compensation

1,247

2,668

Foreign exchange loss Unrealized investment loss

899

123

52

383

5,850

3,591

16,508

12,438

(6,304)

(7,088)

Deficit, beginning of period

(24,824)

(17,736)

Deficit, end of period

(31,128)

(24,824)

(0.06)

(0.06)

Depletion, depreciation and accretion Net loss

Basic and diluted loss per share (Note 7)

Consolidated Statements of Comprehensive Income (Thousands of United States dollars)

Years ended March 31

Net loss

2009

(6,304)

2008

(7,088)

Other comprehensive income: Foreign exchange adjustment on change in reporting currency Comprehensive income/(loss) See accompanying notes to the consolidated financial statements.

–

12,283

(6,304)

5,195

37

38

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

Consolidated Financial Statements of Canoro Resources Ltd.

Consolidated Statements of Cash Flows Years ended March 31

2009

2008

(Thousands of United States dollars)

Operating Activities

(6,304)

Net loss

(7,088)

Non cash items Depletion, depreciation and accretion

5,850

3,591

Unrealized foreign exchange (gain)/loss

1,124

(847)

Unrealized investment loss

52

383

Gain on sale of investment

–

(26)

Stock-based compensation

1,247

Net change in non-cash working capital

(280) 1,689

2,668 (4,876) (6,195)

Financing Activities

Issuance of common shares, net of costs

689

31,684

689

31,684

Investing Activities

Additions to property, plant and equipment (net) Proceeds on sale of investments Restricted cash Change in non-cash working capital

(30,000) – 9,741 (1,556) (21,815)

Net effect of foreign exchange on cash denominated in foreign currencies Net change in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period

900

(13,708) 708 (3,365) 280 (16,085) 1,577

(18,537)

10,981

23,993

13,012

5,456

23,993

222

881

Cash flow supplemental information: Interest received See accompanying notes to the consolidated financial statements.

B U I L D I N G T H E F O U N D AT I O N

Notes to Consolidated Financial Statements For the years ended March 31, 2009 and 2008 (All tabular amounts are expressed in thousands of United States dollars, except per share amounts or otherwise noted)

1.

Future OperationS These financial statements have been prepared by management on the basis of accounting principles applicable to a going concern, which assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its obligations in the normal course of operations. As at March 31, 2009, the Company had working capital of $7.0 million and had incurred a net loss of $6.3 million and generated $1.7 million of cash from operating activities for the year ended March 31, 2009. See Note 12 for details on contractual obligations and commitments of the Company. The application of the going concern concept is dependent upon the Company’s ability to generate future profitable operations. Management regularly monitors funding requirements along with the Company’s asset portfolio, operational activities, and market conditions to ensure they are appropriately balanced by either revising the Company’s financing plans, making changes to operational activities, realizing assets or raising capital as required. Such changes may possibly include the realization of assets or settling of liabilities other than in the normal course of business at amounts that may be different to those stated in the financial statements. Management believes the going concern assumption to be appropriate for these financial statements. If the going concern assumption is not appropriate, adjustments might be necessary to the carrying values of assets and liabilities, reported revenues and expenses, and the balance sheet classifications used in the consolidated financial statements.

2.

Significant accounting policies



(a) Basis of presentation:



These consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly– owned. The audited consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles. The preparation of financial statements in accordance with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period.  Actual results may differ from these estimates. Certain of the comparative amounts have been reclassified to conform to current period presentation.



(b) Petroleum and natural gas properties:





(i)

Capitalized costs







The Company follows the full cost method of accounting for its petroleum and natural gas properties. Under this method, all costs related to the exploration for, and development of, petroleum and natural gas reserves are capitalized in cost centers on a country–by–country basis. Costs include lease acquisition costs, geological and geophysical expenses, overhead directly related to exploration and development activities, and costs of drilling both productive and non–productive wells. Proceeds from the sale of properties are applied against capitalized costs, without any gain or loss being realized, unless such sale would significantly alter the rate of depletion and depreciation by 20 percent or more.





(ii)







Depletion and depreciation Depletion of petroleum and natural gas properties and depreciation of production equipment is provided using the unit–of–production method based upon estimated proven petroleum and natural gas reserves, before royalties, on a cost centre basis. The costs of significant unevaluated properties and major development projects are excluded from costs subject to depletion. For depletion and depreciation purposes, relative volumes, before royalties, of petroleum and natural gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil.





(iii) Impairment tests







In following the full cost method, an impairment loss is recognized when the carrying amount of the petroleum and natural gas properties of a cost centre is not recoverable and exceeds its fair value. The carrying amounts are assessed to be unrecoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market value of unproved properties and the cost of major development

39

40

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

NOTES TO the Consolidated Financial Statements

projects are less then the carrying amount of the cost centre. In determining the amount of impairment, the carrying amount of oil and gas properties capitalized in a cost centre is compared to the fair value of the associated proved and probable reserves and the lower of cost and market value of any unproved properties which are subject to a separate test for impairment. In determining the fair value of the proved and probable reserves, the Company uses cash flows based upon oil and gas prices as quoted in the futures market where obtainable, adjusted for quality differences, transportation, foreign exchange and other relevant factors. These cash flows are then discounted using a risk–free interest rate. If the carrying value of the oil and gas properties is in excess of its fair value (the “ceiling test”), the excess is charged against earnings as additional depletion and depreciation.



(iv) Joint activities







The Company conducts substantially all of its oil and gas exploration and production activities on a joint basis. These financial statements reflect only the Company’s proportionate interest in such activities.



(c)





Asset retirement obligations The Company recognizes the liability associated with future abandonment and site restoration costs in the financial statements at the time the liability is incurred, normally when the related asset is purchased or developed. When incurred, the liability will be measured at its fair value with a corresponding increase to property, plant and equipment and, over time, will be accreted up to the actual expected cash outlay to perform the abandonment and reclamation. This accretion to the liability will be expensed through the Company’s consolidated statement of operations. The increase to property, plant and equipment, known as the “asset retirement cost”, results in an increase to depletion expense over the life of the Company’s proven reserves.



(d) Office furniture and equipment





Depreciation of office furniture and equipment is based on estimates of useful lives and is calculated using the declining balance method at rates ranging from 20 percent to 100 percent per annum.



(e) Foreign currency translation





The Company translates foreign currency denominated monetary assets and liabilities at the exchange rate in effect at the balance sheet date and non–monetary assets and liabilities are translated at historical exchange rates. Revenues and expenses are translated at transaction date exchange rates except depletion and depreciation expenses, which is translated at the same historical exchange rates as the related assets. Exchange gains or losses are included in the determination of net income as foreign exchange loss.



(f) Revenue recognition





Revenues associated with the sale of crude oil and natural gas is recorded when title passes to the customer. Revenues from crude oil and natural gas production from properties from which the Company has an interest with other producers is recognized on the basis of the Company’s net working interest.



(g)





Inventory Inventories of petroleum products, comprising of crude oil and condensate, are valued at the lower of cost and net realizable values. Cost is determined based upon actual operating, transportation and depletion costs.



(h) Income taxes





The Company follows the asset and liability method of accounting for income taxes. Under this method, temporary differences arising from the difference between the tax basis of an asset or liability and its carrying amount on the balance sheet are used to calculate future income tax liabilities or assets. Future income tax liabilities or assets are calculated using substantively enacted tax rates anticipated to apply in the periods that the temporary differences are expected to reverse. A valuation allowance is recorded against any future income tax assets if it is more likely than not that the assets will not be realized.



(i)

Per share data





Basic per share amounts are computed by dividing net loss from operations by the weighted average number of common shares outstanding for the period. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. Under the treasury stock method, only options for which the exercise price is less than the market value impact the dilution calculations.

B U I L D I N G T H E F O U N D AT I O N



(j)





Cash and cash equivalents Cash and cash equivalents are comprised of cash, term deposits and other highly liquid investments with an original maturity of three months or less at the time of purchase.



(k) Stock–based compensation





The Company uses the fair value method for valuing stock options granted as stock–based compensation. Under the fair value method, a compensation cost is measured at fair value for stock options granted at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. Upon the exercise of the stock options, consideration paid together with the amount previously recognized as contributed surplus, is recorded as an increase to share capital.



(l)





Management estimates The preparation of the financial statements in conformity with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. The most significant estimates relate to determining the cost recoverability of the Company’s property, plant and equipment and the provisions for depletion, depreciation and accretion, which are based upon such estimates as proven reserves and future development and abandonment costs.



(m) Financial instruments





All financial instruments are recorded initially at estimated fair value on the balance sheet and classified into one of five categories: held for trading, held to maturity, available for sale, loans and receivables and other liabilities. Cash and cash equivalents, restricted cash and investments are classified as held for trading and measured at estimated fair value. Accounts receivable are classified as loans and receivables and measured at amortized cost. Accounts payable is classified as other liabilities and measured at amortized cost.





The Company may enter into derivative contracts (commodity price, interest rate or foreign currency) in order to manage risk. Derivative contracts are marked–to–market at each reporting period with the change in estimated fair value recorded as gain or loss in earnings. The Company does not utilize derivative contracts for speculative purposes, has not designated any derivative contracts as hedges, and has not recorded any assets or liabilities as a result of embedded derivatives.





The estimated fair value of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their carrying amounts due to their short terms to maturity.

3. Changes in accounting policies

(a)





Change in functional currency Effective April 1, 2008, the Company’s functional currency changed from Canadian dollars to US$ as a result of increased significance of the US$ to the Company’s cash flows. Amongst other things, the increased significance of the US$ is a result of increased capital expenditures being in US$ and an increased proportion of revenues being earned in US$. As both the functional and reporting currencies of the Company are in US$, there are no translation gains and losses that will impact accumulated other comprehensive income.





Monetary assets and liabilities of the Company that are denominated in currencies other than US$ are translated into its function currency at the rates of exchange in effect at the period end date. Any gains and losses are recorded in earnings.



(b) Upcoming accounting pronouncements





The following accounting pronouncements have been issued by the AcSB, but were not in effect at the date of the current financial statements. These pronouncements may have an impact on the Company’s future financial reporting.



Goodwill and Intangible Assets



Effective April 1, 2009, the Company will be required to adopt this standard, which replaces CICA Standards and provides guidance relating to the recognition, measurement, presentation and disclosure of goodwill and intangible assets. The Company does not expect the standard to have an impact on the financial statements.

Convergence of Canadian GAAP with International Financial Reporting Standards (“IFRS”) Effective April 1, 2011, the Company will be required to prepare its consolidated financial statements In accordance with International Financial Reporting Standards (IFRS), with appropriate comparative figures for the prior year. The Company is currently assessing the differences between Canadian GAAP and IFRS and the affect on the consolidated financial statements.

41

42

CANORO RESOURCES LTD.

NOTES TO the Consolidated Financial Statements

4.

|

2 0 0 9 A N N UA L R E P O RT

Property, plant and equipment: March 31, 2009 Accumulated Depletion and Depreciation

Cost

Net Book Value

Petroleum and natural gas properties India

$

81,955

$

12,576

$

69,379

Office furniture and equipment Canada

1,652

India $

374

1,278

1,784

433

1,351

3,436

807

2,629

85,391

$

13,383

$

72,008

March 31, 2008 Accumulated Depletion and Depreciation

Cost

Net Book Value

Petroleum and natural gas properties India

$

52,846

$

7,124

$

45,722

Office furniture and equipment Canada

787

175

612

India

896

171

725

1,683 $

54,529

346 $

7,470

1,337 $

47,059

At March 31, 2009, expenditures associated with the Company’s unproven properties totaling $5.0 million (2008 – $11.2 million) have been excluded from depletion. Estimated future development costs of $13.3 million (2008 – $15.7 million) have been included in costs subject to depletion. During the year ended March 31, 2009, direct overhead costs totaling $1.1 million (2008 – $1.2 million) were capitalized relating to the Company’s exploration and development programs in India. The Company performed a ceiling test calculation at March 31, 2009 to assess the recoverable value of the property, plant and equipment. The price of crude oil is based upon Nigerian Bonny Light as forecasted by independent reservoir consultants adjusted for quality differential. Based on these assumptions, the value of the undiscounted future net revenues from the Company’s proved reserves exceeded the carrying value of property, plant and equipment at March 31, 2009. The following table summarizes the benchmark prices used in the ceiling test calculation. Year ended March 31

Oil (US$/Barrel)

Gas (US$/mcf)

2010

48.10

2.13

2011

53.89

2.20

2012

58.80

2.31

2013

73.78

2.43

2014

79.56

2.55

Escalate thereafter

2.0% per annum

2.0% per annum

B U I L D I N G T H E F O U N D AT I O N

5. Asset retirement obligations The following table represents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas assets as at March 31, 2009:







Asset retirement obligations, beginning of year

$

Obligations incurred

513 275

Accretion expense

71

Asset retirement obligations, end of year

$

859

The Company’s asset retirement obligation results from its obligations for abandonment of well sites. The Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations is approximately $1.2 million to be incurred in the years 2025 and 2028. A credit adjusted risk free rate of 10 percent and an inflation rate of seven percent have been used to determine the fair value of the asset retirement obligation.

6.

Entitlement fund On September 20, 2007 the Company entered into an agreement with a private fund based in Jersey, Channel Islands, whereby the fund provided limited–recourse funding of $10.0 million for appraisal and development drilling in the Company’s Amguri Field in Assam, India. The funds have been expended. The fund does not have a participating interest in the field, nor is it responsible for future capital costs. The fund only receives payments based on the Company’s 60 percent share of gross revenue from the Amguri Field ranging from seven percent before recovery of the original $10.0 million and 3.5 percent thereafter. The agreement provides that the Company shall have a termination option between September 20, 2010, the third anniversary of the agreement, and December 31, 2012 to buy back the fund’s entitlement for $15.0 million before recovery, or for $12.8 million after recovery of the fund’s initial $10.0 million. If this termination option is exercised by the Company, the fund will be granted, subject to TSX approval, 5.0 million warrants to acquire 5.0 million common shares of the Company, exercisable within nine months from the date of issue at an exercise price of CDN$2.00 per common share. If the Company declines to exercise the termination option within the stated time period, the fund will retain its revenue entitlement to the Amguri field.

7.

Share capital



(a)

Authorized





Unlimited voting common shares, without nominal or par value;



Unlimited share purchase warrants; and



Unlimited non–voting preferred shares without nominal or par value.

(b)

Common shares issued



(000’s)

Number

Balance, beginning of year

112,992

Exercise of stock options Transfer from contributed surplus Balance, end of year

Amount

$

85,597

717

689

–

597

113,709

$

86,883

43

44

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

NOTES TO the Consolidated Financial Statements

(c)

Stock options



The following table sets forth a reconciliation of the stock option plan activity for the year ended March 31, 2009: Number

Weighted average exercise price (CAD)

9,942

1.47

Granted

2,775

0.36

Exercised

(717)

0.96

Forfeited

(1,548)

1.34

(125)

0.75

(000’s)

Outstanding options, beginning of year

Expired



Outstanding options, end of year

10,327

1.07

Options exercisable, end of year

7,793

1.24

During the year the Company repriced 1.6 million stock options held by employees. The Company did not reprice any stock options held by Officers or Directors of the Company.

Exercise Price (CAD)

Outstanding at March 31, 2009

Weighted Average Remaining Contractual Life

(years)

Exercisable at March 31, 2009

Weighted Average Remaining Contractual Life Exercise Price

$ 0.16 to $ 0.50

3,881

4.0

2,104

3.5

$ 0.51 to $ 1.00

1,050

1.7

1,033

1.6

$ 1.01 to $ 1.50

3,186

2.6

2,846

2.5

$ 1.51 to $ 2.00

1,525

2.4

1,125

1.8

685

0.9

685

0.9

10,327

2.9

7,793

2.4

$4.34

(d)

Contributed surplus



The following table sets forth a reconciliation of the contributed surplus balance: Balance, beginning of year

$

Grant of options expensed, net of forfeiture

12,986 1,247

Capitalized stock based compensation

415

Transfer to share capital

(597) 1,065

Balance, end of year (e)

$

14,051

Stock based compensation The Company has established a stock option plan under which it has granted options to acquire common shares to officers, directors, employees and key consultants. The plan provides for the granting of options equal to ten percent of the issued and outstanding common shares of the Company. Options issued under the plan have a term of five years and vest over a two year period starting on the date of the grant.



The weighted–average fair value of stock options issued during the year ended March 31, 2009 was $0.32 per option. (March 31, 2008 – $1.11) using the Black–Scholes option–pricing model with the following assumptions:

Years ended March 31

Weighted average fair value of awards Expected volatility (range) Risk free rate of return Expected option life (range) Forfeiture rate

2009

2008

$0.32

$1.11

103% to 108%

88% to 106%

1.71% to 2.88%

2.85% to 4.55%

5 years

5 years

7%

14%

B U I L D I N G T H E F O U N D AT I O N

f)

Loss per share



Net loss per share is computed using the following weighted average common shares:

2009

Years ended March 31

Basic Diluted

(1)

2008

113,566

98,801

113,566

98,801



Anti–dilutive incremental options are excluded from the weighted average diluted shares outstanding.



(1)

8.

Restricted cash



From time to time, the Company is required to post guarantees with the Government of India and letters of credit to its suppliers of goods and services. As at March 31, 2009, none of the Company’s cash was restricted.

9.

Future income taxes The provision for income taxes differs from the result, which would have been obtained by applying the combined federal and provincial income tax rates to the Company’s loss before income taxes. This difference results from the following items:

Combined federal and provincial income tax rate

2009

2008

29.25%

31.47%

(1,844)

Expected tax recovery:

(2,231)

Increase (decrease) resulting from: 366

Stock–based compensation

–

Non taxable loss on sale

44

474

Other

(177)

–

Expiration of non–capital losses

177

1,283

–

Reduction in future income tax rate

314

1,160

Net increase in valuation allowance

(593)

Foreign exchange



840

187

–

–

2009

2008

2,866

2,356

The components comprising the future income taxes are as follows: Tax assets: Non–capital loss carry forwards Investments Unrealized foreign exchange Share issue costs

Asset retirement obligations Less: valuation allowance



56 –

636

996

(11)

Inventory Property, plant and equipment

Future income tax asset

37 (367)





$

(30)

1,960

2,387

181

130

5,302

5,895

(5,302)

(5,895)

–

$

–

At March 31, 2009, the Company had approximately $14.2 million (2008 – $9.5 million) of losses available to reduce future taxable income in Canada, expiring in the years 2009 to 2026.

45

46

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

NOTES TO the Consolidated Financial Statements

10.

Geographic segmentation



The Company has a corporate office in Canada and operations in India. Set out below is segmented information on a geographic basis. Canada

For the year ended March 31, 2009

Petroleum and natural gas sales

$

–

Interest income and other

India

$

11,099

222

Net loss

Consolidated

$

25

11,099 247

4,651

1,653

6,304

865

29,135

30,000

Capital expenditures As at March 31, 2009 Total assets

$

$

83,401

Canada

For the year ended March 31, 2008

Petroleum and natural gas sales

5,385

$

–

Interest income and other Net loss

$

India

$

4,817

88,786

Consolidated

$

4,817

843

27

870

4,755

2,333

7,088

591

13,117

13,708

Capital expenditures As at March 31, 2008 Total assets

$

35,402

$

54,696

$

90,098

11. Contingent liabilities

The Company is subject to legal proceedings and actions arising in the normal course of business. Management believes that any liabilities, which might arise pertaining to such matters, would not be expected to have a material effect on the Company’s consolidated financial position.

12. Contractual obligations and commitments

Pursuant to current production sharing contracts (“PSC’s”) the Company is required to perform minimum exploration activities that include acquisitions and processing of seismic data and drilling of exploration wells. The Company plans to fund these costs with existing cash balances and cash flow from operations. These obligations have not been provided for in the financial statements.



The Company has office lease commitments in Noida and Jorhat in India and Calgary, Canada.



The following are the anticipated payments under the contracts: PSC’s

2009

$

$

656

Total

$

3,402

2010

6,300

556

6,856

2011

3,394

247

3,641

2012 Total

2,746

Office leases

2,100 $

14,540

164 $

The Company has an obligation to pay a revenue entitlement as described in Note 6.

1,623

2,264 $

16,163

B U I L D I N G T H E F O U N D AT I O N

13.

Financial Risk Management



The Company is exposed to financial risks due to the nature of its business and the financial assets and liabilities it holds. The following discussion reviews material financial risks, quantifies the associated exposures, and explains how these risks, and the Company’s capital, are managed.



Additional information in respect of the Company’s risks may be found in the Annual Information Form.

a)

Market Risk



Changes in commodity prices and foreign currency exchange rates can have an impact on the Company’s earnings and value of financial assets and liabilities.



Commodity price risk – Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. The Company is exposed to commodity price risk due to the nature of its business. Oil and natural gas prices are impacted by global supply and demand, as well as political and other forces. For the majority of natural gas production, the Company receives a fixed price of 3,840 rupees (Rs) per 1000 m3, approximately $2.73 per thousand cubic feet (mcf). The Company also has a contract for the life of production sharing contract to sell 12,000 m3/d (approximately 340 mcf per day) at 2,304 Rs per 1000 m³ (approximately $1.64 per mcf). The Company is paid in rupees and is subject to foreign exchange fluctuations on the average price received on changes between the rupee and US$. Although the Company is not directly impacted by fluctuations in natural gas prices due to the nature of their contracts, as prices around the world increase for natural gas there is continued market pressures to increase the price received for natural gas in India which would benefit the Company. The Company receives world oil prices for its oil production and is subject to price fluctuations. The price received for crude oil is very volatile and can undergo significant changes in relatively short time periods. The highest monthly average price during the year was $137.96 in the month of July compared to lowest monthly average of price received of $44.37 in the month of December. As at March 31, 2009 the Company did not have any derivative commodity price contracts in place however, in the future, the Company may enter into such contracts in order to manage its commodity price risk.



Based on actual sales volumes recorded for the year ended March 31, 2009, a US$1.00 per barrel increase (decrease) in oil prices would have increased (decreased) net earnings by $0.1 million. As the Company continues to increase production, earnings will become more impacted by commodity prices, primarily oil.



Foreign currency exchange rate risk – Foreign exchange rate risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates. The reporting currency of the Company is United States dollars. Substantially all of the Company’s operations are in foreign jurisdictions and as a result, the Company is exposed to foreign currency exchange rate risk on some of its activities primarily on exchange fluctuations between the rupee and the US$. Oil revenues are denominated in US$, while natural gas revenues are denominated in Indian rupees. Operating and capital expenditures are incurred in various currencies, including, US dollars, Indian rupees and Canadian dollars. The majority of capital expenditures are incurred in US$ and oil revenues are received in US$ therefore the Company’s exposure to foreign exchange is reduced.



The Company may enter into derivative foreign currency contracts in order to manage foreign currency exchange rate risk, but has not done so to date.



The table below shows the Company’s exposure to foreign currencies for its financial instruments: Total

US$

per FS (1)

As at March 31, 2009

Cash and cash equivalents

Rs

CAD

US$ Equivalent

US$ Equivalent

5,456

5,314

142

–

Accounts receivable

10,400

9,903

485

12

Accounts payable

(9,789)

(9,430)

(174)

(185)

6,067

5,787

453

(173)

Balance sheet exposure (1)

denotes Financial statements





47

48

CANORO RESOURCES LTD.

NOTES TO the Consolidated Financial Statements



|

2 0 0 9 A N N UA L R E P O RT

The Company believes a three percent change in the US$ against these foreign currencies would be reasonably possible within the next three month reporting period. A three percent strengthening of the US$ would result in a change in earnings as follows (an equal but opposite impact to earnings would result if the US$ weakened by three percent): Rs

Decrease in earnings

CAD

US$ Equivalent

As at March 31, 2009

14

(5)

b)

Credit Risk



Credit risk is the risk of a financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligation and arises principally from joint venture partners and natural gas and oil marketers. The Company is exposed to credit risk in respect to its cash and cash equivalents and accounts receivable.



Cash and cash equivalents are held in operating accounts with highly rated Canadian banks and therefore the Company considers these assets to have negligible credit risk.



Virtually all of the Company’s accounts receivable are from counterparties in the oil and gas industry and are subject to normal industry credit risks. The Company’s production base is entirely in the Assam state in North East India. For both the Amguri and AAON/7 production sharing contracts, the Company has the same joint partner for both contracts significantly concentrating the exposure to credit risk for the Company. The Company believes credit risk from its joint venture partner is mitigated by the default provisions within the production sharing contracts. The default provisions are very punitive to the party in default and can include additional working interest reverting to the operator if certain conditions are not met by the defaulting party. Revenue receivables are from both government agencies in India and large international oil and gas companies.



The carrying amount of cash and cash equivalents and accounts receivable represents the Company’s maximum credit exposure.



As at March 31, 2009, the Company’s accounts receivable is aged as follows: Current (less than 90 days) Past due (more than 90 days) Total

$8,793 1,607 $10,400

c)

Liquidity Risk



The Company manages its risk of not meeting its financial obligations through management of its capital structure, annual budgeting of its revenues, expenditures and cash flows. On a monthly basis, internal reporting of actual results is compared to the budget in order to modify budget assumptions, if necessary, to ensure liquidity is maintained.



The Company believes it has adequate cash flows and cash on hand to discharge its financial obligations. In the event that the Company’s receivables are not collected from its joint venture partner, the Company may be required to seek other alternatives of financing which may be unavailable on reasonable terms or curtail capital expenditures to satisfy outstanding obligations.

d)

Capital Management



The Company defines its capital as shareholder’s equity. The Company’s objective is to maintain a strong capital position in order to execute its business plan and maximize value to shareholders. Availability of capital is critical for future success and as such, the Company strives to maintain strong relationships with the capital investment community. Methods employed to adjust the Company’s capital structure could include any, all, or a combination of the following activities:





•

repurchase shares pursuant to a normal course issuer bid;

•

issue new shares through a public offering or private placement;

•

issue equity linked or convertible debt;

•

raise fixed or floating rate debt.

The Company is not subject to any externally imposed capital requirements.

B U I L D I N G T H E F O U N D AT I O N

14.

Subsequent Events



On June 1, 2009, High Artic Energy Services L.P. (HAES) filed a statement of claim in the Court of Queen’s Bench of Alberta against the Company for the amount of $1.3 million relating to invoices submitted to the Company. On June 30, 2009 the Company filed a defence to the HAES claim as well as a counterclaim for damages of $5 million, an Order for an accounting of the costs and expenses invoiced to the Company by HAES, pre-judgment interest and costs. On July 22, 2009 HAES filed a defence to the Company’s counterclaim. As legal proceedings have only recently been commenced, and as no examinations for discovery have yet taken place, the likelihood of success of the claim or counterclaim is not yet determinable.



On July 24, 2009, Canoro announced it entered into an agreement with, a private fund (“Fund”) based in Jersey, Channel Islands, whereby the Fund will provide limited-recourse funding of US$4 million for the purchase and installation of the gas compression units as part of development operations in the Amguri Field in Assam, India. The Fund will not earn a participating interest in the field, nor will it be responsible for future capital costs. The Fund will only be entitled to receive repayments based on Canoro’s 60% share of gross revenue from the Amguri Field ranging from 8% before recovery of the original US$4 million, declining to 4% thereafter.



The agreement also provides that Canoro shall have the option between July 2012 and December 31, 2012 after the Fund’s recovery of its initial investment, to buy back the Fund’s entitlement for US$5.1 million. If such option is exercised by Canoro, the Fund will be granted, subject to TSX Venture approval, warrants to subscribe for two million common shares of the Company, exercisable within six months from the date of issue at a subscription price of CDN $0.20 per share.

49

50

CANORO RESOURCES LTD.

|

2 0 0 9 A N N UA L R E P O RT

CORPORATE INFORMATION

Corporate Information Board of Directors Douglas R. Martin Board Chair; Chair, Audit Committee; Member, Compensation Committee Calgary, Alberta, Canada D. Nolan Blades Chair, Reserves Committee

Calgary, Alberta, Canada

John Boyd Member, Audit Committee; Member, Reserves Committee

Calgary, Alberta, Canada

Jeff Clarke Member, Corporate Governance Committee

Allen, Texas, USA

Harley Winger Chair, Corporate Governance Committee

Calgary, Alberta, Canada

Les B. Kondratoff Member, Compensation Committee

Bragg Creek, Alberta, Canada

James N. Smith Member, Reserves Committee; Member, Corporate Governance Committee

Reading, England, United Kingdom

Robert S. Wynne Member, Audit Committee; Chair, Compensation Committee

Calgary, Alberta, Canada

B U I L D I N G T H E F O U N D AT I O N

EXECUTIVE OFFICERS Les B. Kondratoff, BSc, MBA, President and Chief Executive Officer S. Brian Gieni, BComm, CMA, Senior Vice President, Chief Financial Officer and Country Manager Robert S. Wynne, BSc, MBA, Managing Director and Chief Operating Officer Doug Uffen, BSc, P.Geoph, Vice President – Geoscience Ryan Ellson, CA, Vice President Finance

CANORO’S OFFICE LOCATIONS

auditors

Canada

KPMG LLP

700, 717 7th Avenue SW

Calgary, Alberta, Canada

Calgary, Alberta, Canada T2P 0Z3 Tel: +1 (403) 543-5747

INVESTOR RELATIONS CONTACT

Fax: +1 (403) 543-5740

Robert Wynne

www.canoro.com

Tel: +1 (403) 592-6295 Fax: +1 (403) 543-5740

India 2nd Floor, GHCL Building B-38, Sector-1

[email protected]

ABBREVIATIONS bbl/d

barrels of oil per day

bcf

billion cubic feet

boe

barrel of oil equivalent

boe/d

barrel of oil equivalent per day

STOCK EXCHANGE LISTING

mbbl

thousand barrels

TSX Venture Exchange

mboe

thousand barrels of oil equivalent

Symbol: CNS

mcf

thousand cubic feet

mcf/d

thousand cubic feet per day

REGISTRAR AND TRANSFER AGENT

mmbbl

million barrels

Computershare Trust Company of Canada

mmboe

million barrels of oil equivalent

Calgary, Alberta, Canada

mmcf

million cubic feet

Noida 201301, India Tel: +91-120-4270210 / 4270211 Fax: +91-120-4270220

mmcf/d

million cubic feet per day

INDEPENDENT ENGINEERS

PSC

Production sharing contract

Sproule Associates Limited



Calgary, Alberta, Canada

51

www.canoro.com