2013-07-09 | Niko Reports Results for the Year Ended March 31, 2013 | GREY:NKRSF

Niko Reports Results for the Year Ended March 31, 2013

CALGARY, ALBERTA--(Marketwired - July 9, 2013) - Niko Resources Ltd. (TSX:NKO) ("Niko" or the "Company") is pleased to report its financial and operating results, including consolidated financial statements and notes thereto, as well as its managements' discussion and analysis, for the three months and year ended March 31, 2013. The operating results are effective July 8, 2013. All amounts are in U.S. dollars unless otherwise indicated and all amounts are reported using International Financial Reporting Standards unless otherwise indicated.

PRESIDENT'S MESSAGE TO THE SHAREHOLDERS

During fiscal 2013, the Company achieved significant growth in value. Substantial additions to reserves were booked related to development projects in India and in Trinidad and Tobago, contributing to a 166% increase in the Company's total proved reserves to 564 Bcfe and a 118% increase in the Company's total proved plus probable reserves to 821 Bcfe. Reflecting these significant additions, the estimated aggregate after-tax net present value of future net revenue attributable to the Company's estimated proved plus probable reserves (discounted at 10 percent and estimated using forecast prices and costs) increased by 93% to $1.3 Billion. On top of the reserve value, the Company's extensive exploration portfolio and discovered resources, including the significant MJ gas and condensate discovery in the D6 Block in India, provide substantial additional potential value for shareholders.

With a significant reserve write-down at the end of fiscal 2012 and associated production declines in the Company's main producing asset, fiscal 2013 was a very challenging year for Niko. This was coupled with the maturity of Cdn$310 million of convertible debt and a significant reduction in the availability under the Company's credit facility, all occurring in a very challenging illiquid capital market. Through it all, Niko's people launched the largest exploration program in the Company's history, achieving and exceeding many performance metrics and resulting in three potential discoveries in Indonesia. The ingenuity, planning and execution of Niko's drilling team in Indonesia consistently resulted in reduced drilling time and associated well costs, setting records for speed, cost and efficiency of deepwater drilling in Indonesia in recent times. Niko has also achieved a safety performance record second to none with no recordable injuries over the year, achieving a milestone of 8 million man-hours without a recordable incident in our operated properties in India! Development activities commenced in the producing fields in the D6 Block in India to bring on additional production, address the decline in reservoir pressure and increase water handling capacity. The Company addressed its maturing convertible debenture by issuing common shares and new unsecured convertible notes for combined gross proceeds of Cdn$273 million, and raised $113 million from the Company's program of asset sales, farm-outs and other arrangements ($70 million in fiscal 2013 and $43 million thus far in fiscal 2014), with substantial additional proceeds targeted for the remainder of fiscal 2014.

Looking forward, the long-awaited approval by the Government of India of a new pricing formula for domestic natural gas sales will double the price for gas sales from the D6 Block from its current level of $4.20/MMbtu to around $8.40/MMbtu, effective April 1, 2014. Prices are to be revised quarterly thereafter using the approved formula, with further increases expected in the future, and the impact of the increased prices will be reflected in the borrowing base of the Company's credit facility by the end of July, 2013.

The exploration program has been restarted in the D6 Block in India with the drilling of the exciting MJ-1 gas and condensate discovery, where initial evaluations of drilling results indicate significant resource potential. An initial appraisal program of up to three wells is expected to commence in the current fiscal year.

I would like to thank Niko's people and our shareholders who have supported Niko through this very difficult past year. With the continued high impact deepwater exploration program, recent discoveries and increased gas prices in India on the horizon, Niko looks forward to fiscal 2014 as a major turnaround year for the company. In the past year, the Company re-established itself as capable of achieving significant growth in value. The highlights included:

Edward S. Sampson - President and Chief Executive Officer, Niko Resources Ltd.

REVIEW OF OPERATIONS AND GUIDANCE

Sales Volumes

	Three months ended Mar 31,		Year ended Mar 31,
(MMcfe/d)	2013	2012	2013	2012
D6 Block, India	71	135	96	159
Block 9, Bangladesh	51	42	56	55
Other⁽¹⁾	4	7	6	9
Total⁽²⁾	126	184	158	223

⁽¹⁾	Other includes Hazira and Surat in India, and Canada.
⁽²⁾	Figures may not add up due to rounding.

Total sales volumes for the fourth quarter averaged 126 MMcfe/d compared to 145 MMcfe/d for the third quarter of fiscal 2013, primarily due to anticipated natural declines and reservoir management activities in the D6 Block in India.

For fiscal 2014, an additional well in the MA field and workovers for the Dhirubhai 1 and 3 and MA fields in the D6 Block in India and the Bangora field in Block 9 in Bangladesh, respectively, will provide additional volumes starting in the second quarter of the year, contributing to an annual average sales volumes forecast between 112 and 116 MMcfe/d for the year. For fiscal 2015, the Company is targeting 133 MMcfe/d, benefiting from development activities in fiscal 2014 and 2015.

Funds from Operations

	Three months ended Mar 31,		Year ended Mar 31,
(millions of U.S. dollars)	2013	2012	2013	2012
Funds from operations	30	53	132	234

Funds from operations for the fourth quarter were $30 million compared to $27 million for the third quarter of fiscal 2013.

For fiscal 2014, funds from operations are forecast to be approximately $70 to $75 million. For fiscal 2015, funds from operations are forecast to increase by $100 million or more, reflecting higher sales volume and the Company's estimate of the projected benefit of improved pricing for natural gas sales in India.

Capital Expenditures, net of Proceeds of Farm-outs and Other Arrangements

(millions of U.S. dollars)	Three months ended Mar 31, 2013		Year ended Mar 31, 2013
Capital expenditures, net of proceeds of farm-outs and other arrangements	32		206

Capital expenditures, net of proceeds of farm-outs and other arrangements, totaled $32 million for the fourth quarter. Spending in the quarter related primarily to exploration activities in Indonesia, Trinidad and Tobago, India and Brazil. The Company also received $25 million from a former partner in exchange for assuming the partner's obligation for future drilling commitments.

Exploration results for the year included potential discoveries of hydrocarbons at Lebah-1, Ajek-1 and Cikar-1 in Indonesia, and the Company is currently evaluating future plans for these three fields. Subsequent to year-end, the Company and its joint venture partners announced the significant MJ-1 gas condensate discovery in the D6 Block in India. These discoveries have the potential to increase the Company's resource base by 50% or more over the currently booked proved plus probable reserves.

For fiscal 2014, the Company's minimum level of capital expenditures, net of negotiated farm-outs and other arrangements, and workover expenditures, is forecast to total approximately $130 million. Decisions about additional capital spending during the year will be made as the year progresses, depending on the results of the Company's program of asset sales, farm-outs and other arrangements, and the Company's financing activities.

Estimated Reserves

	As at Mar 31,
(Bcfe)	2013	2012
Proved	564	212
Proved plus Probable	821	377

The Company increased its proved reserves by 166%, a proved reserve replacement ratio of over 700%, and increased its proved plus probable reserves by 118%, a proved plus probable reserve replacement ratio of nearly 900%.

India

For the D1 D3 and MA producing fields in the D6 Block, virtually no revisions were reflected for combined proved reserves on a gas equivalent basis, with small positive revisions reflected for combined proved plus probable reserves. A combined total of 165 Bcf of proved and 270 Bcf of proved plus probable reserves additions were booked for the R-Series and Satellite Area development projects in the D6 Block and the J-Series development project in the NEC-25 Block.

Bangladesh

Positive revisions to proved reserves of 46 Bcfe were reflected for Block 9, increasing proved reserves to 101 Bcfe even after production of 20 Bcfe.

Trinidad and Tobago

Additions to proved reserves for the Endeavour/Bounty development project in Block 5(c) were 197 Bcf (235 Bcf on a proved plus probable basis).

Estimated After-tax Net Present Value of Future Net Revenue

	As at Mar 31,
(millions of U.S. dollars)	2013	2012
Proved	761	468
Proved plus Probable	1,299	674

The estimated aggregate after-tax net present value of future net revenue attributable to the Company's estimated proved plus probable reserves (discounted at 10 percent and estimated using forecast prices and costs) increased by 93% to $1.3 Billion, reflecting the significant increases in reserves, described above.

Complete details of the Company's reserves and future net revenues attributable thereto are contained in its Annual Information Form for the year ended March 31, 2013 which is available on SEDAR at www.sedar.com.

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis (MD&A) of the financial condition, results of operations and cash flows of Niko Resources Ltd. ("Niko" or the "Company") for the year ended March 31, 2013 should be read in conjunction with the audited consolidated financial statements for the year ended March 31, 2013. This MD&A is effective July 08, 2013. Additional information relating to the Company, including the Company's Annual Information Form (AIF), is available on SEDAR at www.sedar.com.

All financial information is presented in thousands of U.S. dollars unless otherwise indicated.

The term "the quarter" is used throughout the MD&A and in all cases refers to the period from January 1, 2013 through March 31, 2013. The term "prior year's quarter" is used throughout the MD&A for comparative purposes and refers to the period from January 1, 2012 through March 31, 2012.

The fiscal year for the Company is the 12-month period ended March 31. The terms "Fiscal 2012" and "prior year" is used throughout this MD&A and in all cases refers to the period from April 1, 2011 through March 31, 2012. The terms "Fiscal 2013", "current year" and "the year" are used throughout the MD&A and in all cases refer to the period from April 1, 2012 through March 31, 2013.

Mcfe (thousand cubic feet equivalent) is a measure used throughout the MD&A. Mcfe is derived by converting oil and condensate to natural gas in the ratio of 1 bbl:6 Mcf. Mcfe may be misleading, particularly if used in isolation. A Mcfe conversion ratio of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. MMBtu (million British thermal units) is a measure used in the MD&A. It refers to the energy content of natural gas (as well as other fuels) and is used for pricing purposes. One MMBtu is equivalent to 1 Mcfe plus or minus up to 20 percent, depending on the composition and heating value of the natural gas in question.

Cautionary Statement Regarding Forward-Looking Statements and Information

Certain statements in this MD&A are "forward-looking statements" or "forward-looking information" within the meaning of applicable securities laws, herein "forward looking statements" or "forward looking information". Forward-looking information is frequently characterized by words such as "plan," "expect," "project," "intend," "believe," "anticipate," "estimate," "scheduled," "potential" or other similar words, or statements that certain events or conditions "may," "should" or "could" occur. Forward-looking information is based on the Company's expectations regarding its future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities. Such forward-looking information reflects the Company's current beliefs and assumptions and is based on information currently available to it. Forward-looking information involves significant known and unknown risks and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking information including risks associated with the impact of general economic conditions, industry conditions, governmental regulation, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and the Company's ability to access sufficient capital from internal and external sources, the risks discussed under "Risk Factors" and elsewhere in this report and in the Company's public disclosure documents, and other factors, many of which are beyond its control. Although the forward-looking information contained in this report is based upon assumptions which the Company believes to be reasonable, it cannot assure investors that actual results will be consistent with such forward-looking information. Such forward-looking information is presented as of the date of this MD&A, and the Company assumes no obligation to update or revise such information to reflect new events or circumstances, except as required by law. Because of the risks, uncertainties and assumptions inherent in forward-looking information, you should not place undue reliance on this forward-looking information. See also "Risk Factors."

Specific forward-looking information contained in this MD&A may include, among others, statements regarding:

the performance characteristics of the Company's oil, NGL and natural gas properties;
natural gas, crude oil, and condensate production levels, sales volumes and revenue;
the size of the Company's oil, NGL and natural gas reserves;
projections of market prices and costs;
supply and demand for oil, NGL and natural gas;
the Company's ability to raise capital and to continually add to reserves through acquisitions and development;
future funds from operations;
debt and liquidity levels;
future royalty rates;
treatment under governmental regulatory regimes and tax laws;
work commitments and capital expenditure programs;
the Company's future development and exploration activities and the timing of these activities;
the Company's future ability to satisfy certain contractual obligations;
future economic conditions, including future interest rates;
the impact of governmental controls, regulations and applicable royalty rates on the Company's operations;
the Company's expectations regarding the development and production potential of its properties;
the Company's expectations regarding the costs for development activities;
the resolution of various legal claims raised against the Company;
the potential for asset impairment and recoverable amounts of such assets; and
changes to accounting estimates and accounting policies.

The forward-looking statements contained in this MD&A are based on certain key expectations and assumptions made by us, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities and the availability and cost of labor and services. Although the Company believes that the expectations reflected in the forward-looking statements in this MD&A are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and natural gas industry in general, such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation, as well as the other risk factors identified under "Risk Factors" herein. Statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. You are cautioned that the foregoing list of factors and risks is not exhaustive.

The Company prepares production forecasts taking into account historical and current production, and actual and planned events that are expected to increase or decrease production and production levels indicated in its reserve reports.

The Company prepares capital spending forecasts based on internal budgets for operated properties, budgets prepared by the Company's joint venture partners, when available, for non-operated properties, field development plans and actual and planned events that are expected to affect the timing or amount of capital spending.

The Company prepares operating expense forecasts based on historical and current levels of expenses and actual and planned events that are expected to increase or decrease production and/or the associated expenses.

The Company discloses the nature and timing of expected future events based on budgets, plans, intentions and expected future events for operated properties. The nature and timing of expected future events for non-operated properties are based on budgets and other communications received from joint venture partners.

The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis when the change is material and update reserve estimates on an annual basis. See "Risk Factors" for discussion of uncertainties and risks that may cause actual events to differ from forward-looking information provided in this report. The information contained in this report, including the information provided under the heading "Risk Factors," identifies additional factors that could affect the Company's operating results and performance. The Company urges you to carefully consider those factors and the other information contained in this report.

The forward-looking statements contained in this report are made as of the date hereof and, unless so required by applicable law. The Company undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this report are expressly qualified by this cautionary statement.

Non-IFRS Measures

The selected financial information presented throughout this MD&A is prepared in accordance with IFRS, except for "funds from operations", "operating netback", "funds from operations netback", "earnings netback", "segment profit" and "working capital". These non-IFRS financial measures, which have been derived from financial statements and applied on a consistent basis, are used by management as measures of performance of the Company. These non-IFRS measures should not be viewed as substitutes for measures of financial performance presented in accordance with IFRS or as a measure of a company's profitability or liquidity. These non-IFRS measures do not have any standardized meaning prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other companies.

The Company utilizes funds from operations to assess past performance and to help determine its ability to fund future capital projects and investments. Funds from operations is calculated as cash flows from operating activities prior to the change in operating non-cash working capital, the change in long-term accounts receivable and exploration and evaluation costs expensed to the statement of comprehensive income.

The Company utilizes operating netback, funds from operations netback, earnings netback and segment profit to evaluate past performance by segment and overall.

Operating netback is calculated as oil and natural gas revenues less royalties, the government share of profit petroleum and operating expenses for a given reporting period, per thousand cubic feet equivalent (Mcfe) of production for the same period, and represents the before-tax cash margin for every Mcfe sold.

Funds from operations netback is calculated as the funds from operations per Mcfe and represents the cash margin for every Mcfe sold. Earnings netback is calculated as net income per Mcfe and represents net income for every Mcfe sold.

Segment profit is defined as oil and natural gas revenues less royalties, the government share of profit petroleum, production and operating expenses, depletion expense, exploration and evaluation expense and current and deferred income taxes related to each business segment.

The Company defines working capital as current assets less current liabilities and uses working capital as a measure of the Company's ability to fulfill obligations with current assets.

These non-IFRS measures do not have any standardized meaning prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other companies.

OVERALL PERFORMANCE

Funds from Operations

	Year ended March 31,
(thousands of U.S. dollars)	2013		2012
Oil and natural gas revenue	199,364		321,311
Production and operating expenses	(35,523	)	(38,641	)
Other income	311		6,436
General and administrative expenses	(6,931	)	(8,774	)
Finance income	1,999		4,302
Bank charges and other finance costs	(3,285	)	(5,464	)
Realized foreign exchange loss	(3,125	)	(8,271	)
EBITDAX	152,810		270,899
Interest expense	(21,806	)	(21,674	)
Current income tax recovery / (expense)	289		(5,920	)
Minimum alternate tax expense	-		(9,105	)
Funds from operations ⁽¹⁾	131,293		234,200

(1) EBITDAX and Funds from operations are non-IFRS measures as defined under "Non-IFRS measures" in this MD&A.

Oil and natural gas revenue decreased in the year, primarily due to lower sales of natural gas, crude oil and condensate from the D6 Block in India along with an adjustment to the government share of profit petroleum for the Hazira Field recorded in the current year.

Production and operating expenses have reduced in D6 mainly because of reduction in logistics cost from last year due to reduced operations. However some of this reduction is offset by increase in operating expenses of Block 9 due to the well repair and workovers during the period.

Other income in the prior year includes proceeds from farm-outs in excess of the recorded cost of the Company's interests in certain properties in Indonesia.

General and administrative expenses decreased primarily due to reduced use of outside legal services.

Bank charges and other finance costs decreased primarily due to lower costs related to financing efforts.

There were realized foreign exchange losses in the current and prior years as a result of the weakening of the Indian-Rupee against the U.S. dollar.

Interest expense increased slightly primarily due to interest on credit facility borrowing and the convertible notes in the current year, offset by lower interest on the convertible debentures.

Current income tax decreased compared to the prior year due to reductions in income for Hazira (including the adjustment to the government share of profit petroleum recorded in the current year) and Surat. In the prior year, there was an adjustment related to previous year tax provisions for Hazira.

The Company currently pays minimum alternate tax based on Indian-GAAP accounting income for the D6 block. For the current year, the D6 Block did not generate positive accounting income under Indian GAAP, resulting in no minimum alternative tax expense.

Net Income (Loss)

	Year ended March 31,
(thousands of U.S. dollars)	2013		2012
Funds from operations (non-IFRS measure)	131,293		234,200
Production and operating expenses	(1,255	)	(1,555	)
Depletion and depreciation expenses	(145,250	)	(144,595	)
Exploration and evaluation expenses	(172,811	)	(232,963	)
Asset impairments	(67,831	)	(133,415	)
Reversal of asset impairment	101,544		-
Impairment of long-term receivable	-		(22,996	)
Share-based compensation expense	(10,894	)	(21,603	)
Finance expense	(8,677	)	(7,612	)
Unrealized foreign exchange loss	(75	)	(6,095	)
Loss on short-term investments	(2,106	)	(5,823	)
Deferred income tax recovery	(40,434	)	91,607
	(216,496	)	(250,850	)
Change in accounting estimate-deferred taxes	-		(57,865	)
Share-based compensation expense-impact of option cancellation	-		(13,913	)
Net loss	(216,496	)	(322,628	)

The decrease in funds from operations is described above. Other items affecting net loss are described below.

Depletion and depreciation expense for the current year was consistent with the prior year as the impact of increased depletion rates for the D6 Block in India resulting from the revision to the reserve volumes and future costs included in the March 31, 2012 reserve report was virtually offset by the impact of lower production.

Exploration and evaluation expense for the current year includes costs associated with unsuccessful exploration wells, including wells in the Lhokseumawe Block in Indonesia and Block 2(ab) in Trinidad, and directly expensed costs of seismic and other exploration projects, payments specified in various production sharing contracts ("PSCs"), branch office costs for all exploration properties, and new venture activities.

In the current year, the Company recognized asset impairments for exploration and evaluation assets in the Lhokseumawe block in Indonesia, Block 2(ab) in Trinidad and Qara Dagh Block in Kurdistan.

The Company recognized reversal of asset impairment for the D6 Block in India.

The impairment of long term receivables in the prior year related to gas sales revenue receivables in Bangladesh.

Share-based compensation expense decreased in the current year, as a result of a decrease in the fair value per stock option granted as a result of lower stock price during the year as compared to the prior year and the reversal of share-based compensation expense due to forfeitures of stock options.

The Indian rupee weakened against the US dollar during the current and prior years. As a result, unrealized foreign exchange losses were recorded in the years.

The loss on short term investments is a result of mark to market valuation of these investments.

The deferred tax recovery for the current year relates mainly to the reversal of temporary differences during the tax holiday period which mainly depends on the accounting depletion rate and capital spending during the period. In the current year the amount of temporary differences reversing during the tax holiday period came down significantly resulting in deferred tax expenses which were partially offset by deferred tax recovery recognized on issuance of convertible notes in December 2012 and to a reduction in exploration and evaluation assets related to the receipt of proceeds from a farm out and from former partners in exchange for assuming the partners' obligations for future drilling commitments. For the prior year, the amounts of temporary differences reversing during the tax holiday period were significantly higher resulting in deferred tax recovery.

In the prior year, the change in accounting estimate is related to deferred income tax resulting from estimating the amount of taxable temporary differences reversing during the tax holiday period.

Capital Expenditures, net of Proceeds of Farm-outs and Other Arrangements

The following table sets forth the capital additions and exploration and evaluation costs expensed directly to income, net of proceeds of farm-outs and other arrangements, for the year ended March 31, 2013.


(thousands of U.S. dollars)	Additions to exploration and evaluation assets⁽¹⁾⁽²	⁾	Additions related to future drilling	Expensed exploration and evaluation costs⁽¹	⁾	Additions to property, plant and equipment⁽¹	⁾	Proceeds from farm outs and other arrangements		Total
Indonesia	127,818		16,025	27,825		169		(70,203	)	101,634
Trinidad	38,960		10,604	25,080		437		-		75,081
All other	1,261		-	19,586		8,672		-		29,519
Total	168,039		26,629	72,491		9,278		(70,203	)	206,234

Share-based compensation and other non-cash items are excluded.
Includes additions in the year that were subsequently written off.

Indonesia

Additions to exploration and evaluation assets for Indonesia for the current year include costs related to three wells in the Lhokseumawe block, and one well in each of the North Ganal, Kofiau, and West Papua IV blocks, along with acquisition costs of the Lhokseumawe block. The additions to future drilling in Indonesia relate to the costs of drilling inventory and other activities incurred to prepare for the current drilling campaign. These costs will be allocated when future wells are drilled. Exploration and evaluation costs expensed directly to income include costs related to seismic and other exploration projects and branch office costs. In the current year, the Company also recorded proceeds of a farm-out of $9 million and received $61 million from former partners in exchange for assuming the partners' obligations for future drilling commitments.

Trinidad and Tobago

Additions to exploration and evaluation assets for Trinidad and Tobago for the current year include costs related to two wells drilled in Block 2(ab). Exploration and evaluation costs expensed directly to income include costs related to seismic and other exploration projects, payments that are specified in various PSCs, and branch office costs.

All Other

Exploration and evaluation costs expensed directly to income included costs related to the acquisition of multi-beam data over various blocks in Brazil. Additions of property, plant and equipment in the year relate to development projects in India.

BACKGROUND ON PROPERTIES

The Company's diversified portfolio of producing, development and exploration assets is described below.

Producing Assets

The Company's principal producing natural gas and crude oil assets are in the D6 Block in India and in Block 9 in Bangladesh.

D6 Block, India

The Company entered into the PSC for the D6 Block in India in 2000 and has a 10 percent working interest, with Reliance Industries Limited ("Reliance"), the operator, holding a 60 percent interest and BP holding the remaining 30 percent interest. The D6 Block is 7,645 square kilometers lying approximately 20 kilometers offshore of the east coast of India.

Successful exploration programs in the D6 Block led to the discoveries of the Dhirubhai 1 and 3 natural gas fields in 2002 and the MA crude oil and natural gas field in 2006.

Production from the crude oil discovery in the MA field commenced in September 2008 and commercial production commenced in May 2009. Six wells are tied into a floating production storage offloading vessel ("FPSO"), which stores the crude oil until it is sold on the spot market at a price based on the Bonny Light reference price and adjusted for quality, and four of these wells are currently on production. In fiscal 2014, the joint venture plans to drill an additional gas development well and convert of one of the two suspended oil wells into a gas producing well to accelerate the production of the reservoir's gas reserves.

Field development of the Dhirubhai 1 and 3 fields included the drilling and tie-in of 18 wells, construction of an offshore platform and onshore gas plant facilities. Production from the Dhirubhai 1 and 3 natural gas discoveries commenced in April 2009 and commercial production commenced in May 2009. The natural gas produced from offshore is being received at an onshore facility at Gadimoga and is sold at the inlet to the East-West Pipeline owned by Reliance Gas Transportation Infrastructure Limited.

Production from the Dhirubhai 1 and 3 fields peaked in March 2010 and has decreased since then, primarily due to natural declines of the fields and greater than anticipated water production. Four additional wells have been drilled in the post-production phase of drilling. Based on the information obtained from three wells drilled within the main channel fairway, the Company has determined that it is not economic to tie-in any of these three wells at the present time. The fourth well was drilled outside of the main channel fairway and did not encounter economic quantities of natural gas. Nine of the original 18 wells are currently shut-in and several others are choked, primarily due to current constraints in water handling capacity. Workovers are planned to bring some of the shut-in wells back online during fiscal 2014. Increased water handling capacity and additional booster compression is expected to be installed over the next two years to address the decline in reservoir pressure.

The PSC for the D6 Block states that natural gas must be sold at arm's length prices, with "arm's length" defined as sales made freely in the open market between willing and unrelated sellers and buyers, and that the pricing formula be approved by the GOI taking into account the prevailing policy on natural gas. In May 2007, Reliance, on behalf of the joint venture partners, discovered an arm's length price for the sale of gas on a transparent basis with a term of three years and accordingly, proposed a gas price formula to the GOI. In September 2007, the GOI approved a pricing formula with some modification to the proposed formula. As a result of these modifications, the gas price is capped at $4.20/MMBtu and the formula was declared effective for a period of five years rather than the three years proposed by Reliance. The Company has signed numerous gas sales contracts with customers in the fertilizer, power, steel, city gas distribution, liquefied petroleum gas market and pipeline transportation industries, and all of these contracts expire on March 31, 2014. In June 2013, the Cabinet Committee of Economic Affairs of the GOI approved a new pricing formula for domestic gas sales in India, based on the recommendations of the Rangarajan Committee. The pricing formula is based on the average of the prices of imported LNG into India and the weighted average of gas prices in North America, Europe and Japan, as follows:

P_AV = {P_IAV + P_WAV} / 2
- P_AV= Sales price for domestic natural gas sales in India
- P_IAV = Netback price of Indian LNG term imports (excluding spot imports)
- P_WAV = Weighted average of prevailing gas prices in global markets, based on:
  - Henry Hub gas price in U.S. and total volumes consumed in North America
  - National Balancing Point gas price in U.K. and total volume consumed in Europe and Eurasia
  - Netback price of Japanese LNG imports and total volume imported by Japan

The pricing formula will be effective on April 1, 2014 for a period of five years, with the price to be revised quarterly using the approved formula. The price for each quarter will be calculated based on the 12 month trailing average price with a lag of one quarter (i.e., the price for April to June 2014 will be calculated based on the averages for the 12 months ended December 31, 2013). At the present time, the Indian LNG term imports relate primarily to the Petronet contract with RasGas of Qatar. Per the Rangarajan Committee Report, the pricing terms of this contract are as follows:

FOB = P_o x JCC_t / $15
- P_o = $1.90 / MMBTU (therefore, FOB = 12.67% x JCC_t)
- JCC_t = 12 trailing month average JCC price, subject to a floor and ceiling:
  - Floor = {(60 - N) x $20 + (N x A60)} / 60 - $4
  - Ceiling = {(60 - N) x $20 + (N x A60)} / 60 + $4
    - N = 1 for January 2009, increasing by 1 every month until December 2013 after which it remains at 60
    - A60 = 60 trailing month average price of JCC

In the future, the Indian LNG term imports are expected to include imports related to the Petronet contract with ExxonMobil for import of LNG from the Gorgon venture in Australia. Per the Rangarajan Committee Report, the terms of this contract are as follows:

FOB = 14.5% x JCC

Estimated liquefaction and transportation costs of $3.00/MMbtu for older LNG facilities (pre-2010) or $4.00/MMbtu for newer LNG facilities are to be deducted to arrive at the netback price for Indian LNG term imports.

Using the approved price formula, the price effective for April 1, 2014 is estimated at around $8.40/MMbtu, double the price of $4.20/MMbtu for current gas sales from the D6 Block. The pricing terms of the Petronet contracts are expected to result in further increases in the gas prices in future quarters, assuming current pricing levels of JCC, U.S. Henry Hub, U.K. National Balancing Point and Japan LNG imports.

The production and operating expenses for the D6 Block relate primarily to the offshore wells and facilities, the onshore gas plant facilities and the operating fee portion of the lease of the FPSO. The majority of these expenses are fixed in nature with repairs and maintenance expenditures incurred as required.

The Company calculates and remits the government share of profit petroleum to the GOI in accordance with the PSC for the D6 Block. The profit petroleum calculation considers capital, operating and other expenditures made by the joint venture. Because there are unrecovered costs to date, the GOI's share of profit petroleum has amounted to the minimum level of one percent of gross revenue. The government share of profit petroleum will increase above the minimum level once past unrecovered costs have been fully recovered. The Company has included certain costs in the profit petroleum calculations that are being contested by the GOI and has received notice from the GOI making allegations in relation to the fulfillment of certain obligations under the PSC for the D6 Block. Refer to note 30 to the consolidated financial statements for nine months ended March 31, 2013 for a complete discussion of this contingency.

The Company currently pays royalty expense of five percent of gross revenue, increasing to ten percent of gross revenue in May 2016. Royalty payments are deductible in calculating profit petroleum.

The Company pays the greater of minimum alternate tax and regular income taxes for the D6 Block. In the calculation of regular income taxes, the Company believes it is entitled to a seven-year income tax holiday commencing from the first year of commercial production and has claimed the tax holiday in the filing of tax return for fiscal 2012. Minimum alternate tax is the amount of tax payable in respect of accounting profits. Minimum alternate tax paid can be carried forward for 10 years and deducted against regular income taxes in future years.

Block 9, Bangladesh

In September 2003, the Company acquired a 60 percent working interest in the PSC for Block 9. Tullow, the operator, holds a 30 percent interest and the remaining 10 percent interest is held by BAPEX. Block 9 covers approximately 1,770 square kilometers of land in the central area of Bangladesh surrounding the capital city of Dhaka. Natural gas and condensate production for the Bangora field in Block 9 commenced in May 2006 and gas is transported from four currently producing wells to a gas plant in the block.

The Company's share of production from the Bangora field reached a sustained rate of production of 60 MMcf/d in 2009. The Company expects to add compression at the gas processing plant in the fourth quarter of Fiscal 2014 which will allow sustained production levels through 2015. The Company has signed a GPSA including a price of $2.34/MMBtu (or $2.32/Mcf), which expires at the earliest of the end of commercial production, at expiry of the PSC (March 31, 2026) and 25 years after approval of the field development plan (May 15, 2032). Petrobangla is the sole purchaser of the natural gas production from this field. The sales delivery point is at the outlet of the gas plant and thereafter is the responsibility of Petrobangla and is transported via Trunk Pipeline.

The production and operating expenses for Block 9 relate primarily to the onshore wells and facilities, including a gas plant and pipeline. The majority of these expenses are fixed in nature with repair and maintenance expenditures incurred as required.

The Company calculates and remits the government share of profit petroleum to the government of Bangladesh ("GOB") in accordance with the PSC for Block 9. The profit petroleum calculation considers capital, operating and other expenditures made by the joint venture. To date, the GOB's share of profit petroleum amounted to the minimum level of 34 percent of gross revenue based on the profit petroleum provisions of the PSC. The profit petroleum percentage of gross revenue will increase above the minimum level of 34 percent of gross revenue once past unrecovered allowable costs have been fully recovered.

Under the terms of the Block 9 PSC the Company does not make payment to the GOB with respect to income tax.

Planned Developments

The Company has undeveloped discoveries in D6 and NEC 25 blocks in India and in Block 5(c) in Trinidad and Tobago. Based on development plan submissions, increased clarity on future gas prices and positive project economics for the developments, the Company booked significant proved and probable reserves for these projects, effective March 31, 2013. The developments will provide the opportunity for significant production growth for the Company in the next four to six years.

The following is a brief description of these development plans.

Additional Areas, D6 Block, India

The Company's exploration program has identified three additional areas in the D6 Block for potential future development. In January 2013, the G2 well on the D19 discovery, one of four satellite discoveries approved for development by the GOI, was successfully drilled and the development plan for the R-Series area was submitted to the GOI for approval. The development of these areas is expected to be completed within four years after the approval of the development plans. The plans include the re-entry and completion of certain existing wells and the drilling of new wells, all connected with new flow-lines and other facilities into existing D6 Block infrastructure.

NEC-25 Block, India

The Company has a 10 percent working interest in the NEC-25 Block, with Reliance, the operator, holding a 60 percent interest and BP holding the remaining 30 percent interest. The remaining contract area comprises 9,461 square kilometres offshore adjacent to the east coast of India. Exploration and appraisal drilling has been conducted on the block and the development plan for certain discovered natural gas fields was submitted in March 2013. The development plans include the re-entry and completion of certain existing wells and the drilling of new wells, all connected via new flow-lines and other facilities into a new offshore central processing platform. The produced natural gas is expected to be transported onshore via a new pipeline.

Block 5(c), Trinidad and Tobago

The Company has a 25 percent working interest in Block 5(c) with the BG Group plc ("BG Group"), the operator, holding the remaining 75 percent working interest in this offshore development area that covers 241 square kilometres. In October 2011, the BG Group submitted a development plan to the government of Trinidad and Tobago ("GTT") for approval. Development of natural gas production from two discovered fields in the block is expected to require the drilling of new wells, construction of new flow-lines and other facilities, and expansion of an existing platform in the adjacent Block 6(b) operated by the BG Group.

Exploration Discoveries

Discovery: MJ-1, D6 Block, India

In March 2013, after a multi-year hiatus, exploration drilling recommenced in the D6 Block in India with the drilling of the MJ-1 exploration well. In May 2013, the joint venture partners announced a significant gas and condensate discovery. The MJ-1 well was drilled in a water depth of 1,024 metres - and to a total depth of 4,509 metres - to explore the prospectivity of a Mesozoic Synrift Clastic reservoir lying over 2,000 metres below the already producing reservoirs in the Dhirubhai 1 and 3 gas fields. Formation evaluation indicates a gross gas and condensate column in the well of about 155 metres in the Mesozoic reservoirs. In the drill stem test, the well flowed 30.6 MMcf/d of natural gas and 2,121 b/d of liquids though a choke of 36/64", with a flowing bottom hole pressure of 8461 psia suggesting good flow potential. Well flow rates during such tests are limited by the rig and well test equipment configuration. The discovery, named 'D-55', has been notified to the GOI and the Management Committee of the block.

Subsequent to the completion of drilling operations, a preliminary technical evaluation has been conducted that has incorporated all seismic and new well data. Principal findings demonstrate that most parameters for the MJ reservoir exceed the high end pre-drill estimates. In particular, MJ-1 has considerable thicker reservoir pay than the best case pre-drill assessment. The fully cored MJ-1 pay interval was found to be 95% sand bearing with net pay averaging 125 metres. In addition, the MJ-1 gas water contact, as confirmed by wireline log and MDT data, is at the equivalent depth of a mapped seismic flat spot and a northern structural spill point. This validates that MJ is filled fully to structural spill and accordingly aligns the MJ field nearer the maximum case pre-drill field size estimates of 65 square kilometres. In comparison, the producing MA field covers a reservoir area of 11 square kilometres.

The MJ field discovery is well positioned to take advantage of the existing D6 Block infrastructure. Conceptual planning has been initiated to maximize MJ gas and condensate recovery which has a measured compositional ratio of approximately 62 bbls/MMcf.

An initial appraisal program of up to three wells should commence within 6 to 8 months pending government approvals and equipment availability.

Potential Discoveries: Lebah-1, Ajek-1 and Cikar-1 wells, various blocks, Indonesia

The Lebah-1 well, drilled by the operator, ENI, in the North Ganal block, located offshore Kalimantan in the Makassar Strait of Indonesia, penetrated 12 feet of net pay at the top of a 41 foot gross sand Upper Miocene sand interval, a secondary target zone of the well. The joint venture partners have evaluated the potential of this zone and are finalizing plans to drill the Lebah-2 appraisal well in an area of the structure where the zone is believed to be thicker.

The Ajek-1 well, drilled in the Kofiau block, located offshore Papua province in eastern Indonesia, encountered 23 feet of pay over two target Pliocene clastic intervals, with additional thin bedded pay potential. Drilling confirmed the presence of reservoir and hydrocarbon charge, the primary pre-drill concerns in this previously undrilled sub-basin. All sands encountered were hydrocarbon filled with no water leg and C5+ gas composition indicated liquid hydrocarbons. The well has been assessed as a sub-commercial oil and gas discovery. The Company is evaluating the potential of drilling of an appraisal well or one of the other prospects on the block that it believes could contain thicker Pliocene clastic sands.

The Cikar-1 well, drilled in the West Papua IV block, located offshore Papua province in eastern Indonesia, encountered a 700 foot thick section of the targeted New Guinea Limestone primary objective and was still in the porous zone when well conditions forced suspension of drilling operations. The well encountered gas in the drilling of the deeper section and the temporary suspension of the well will allow Niko to return to the well for future deepening and testing. The Company is also evaluating the potential of drilling of an appraisal well or one of the other prospects on the block that it believes could also contain thick sections of New Guinea Limestone.

Exploration Opportunities

The Company's business strategy is to commit resources to finding, developing and producing exploration opportunities that have the potential for a "high impact"' on the Company. Exploration acreage is generally obtained by committing to acquire and process a specified amount of seismic and in most cases, drill one or more exploration wells. The Company generally uses advanced technology including high resolution multi-beam data collection and analysis, sub-sea coring and focused 3D seismic to reduce costs associated with selecting prospects to drill and increase the probability of success. The Company generally uses the information acquired to farm-out its blocks to world-class industry partners under terms where the partners fund their share of sunk costs and carry a disproportionate share of drilling costs.

The Company holds interests in contract areas covering 173,922 gross square kilometers of undeveloped land, primarily in Indonesia and Trinidad and Tobago.

Indonesia

As at March 31, 2013, the Company held interests in 22 offshore exploration blocks in Indonesia, covering 117,925 square kilometers. The Company has successfully farmed out interests in several of its blocks and is working with various parties on additional farm-outs to reduce its share of future drilling costs. The table below indicates the operator, the location of, the award date, working interest and the size of the block, as at March 31, 2013.

Block Name	Operator	Offshore Area	Award Date	Working Interest		Area (Square Kilometres	)
Lhokseumawe	Zaratex	Aceh	Oct. 2005	30	%	4,431
Bone Bay	Niko	Sulawesi S	Nov. 2008	100	%	4,969
South East Ganal I	Niko	Makassar Strait	Nov. 2008	100	%	3,648
Seram	Niko	Seram NE	Nov. 2008	55	%	4,991
South Matindok	Niko	Sulawesi NE	Nov. 2008	100	%	5,182
West Sageri	Niko	Makassar Strait	Nov. 2008	100	%	4,977
Cendrawasih	Niko	Papua NW	May 2009	100	%	4,991
Kofiau	Niko	Papua W	May 2009	57.5	%	5,000
Kumawa	Niko	Papua SW	May 2009	100	%	5,004
East Bula	Niko	Seram NE	Nov. 2009	55	%	6,029
Halmahera-Kofiau	Niko	Papua W	Nov. 2009	51	%	4,926
North Makassar	Niko	Makassar Strait	Nov. 2009	30	%	1,787
West Papua IV	Niko	Papua SW	Nov. 2009	49.9	%	6,389
Cendrawasih Bay II	Repsol	Papua NW	May 2010	50	%	5,073
Cendrawasih Bay III	Niko	Papua NW	May 2010	50	%	4,689
Cendrawasih Bay IV	Niko	Papua NW	May 2010	50	%	3,904
Sunda Strait I	Niko	Sunda Strait	May 2010	100	%	6,960
Obi	Niko	Papua W	Nov. 2011	51	%	8,057
North Ganal	Eni	Makassar Strait	Nov. 2011	31	%	2,432
Halmahera II	Statoil	Papua W	Dec. 2011	20	%	8,215
South East Seram	Niko	Papua SW	Dec. 2011	100	%	8,217
Aru	Niko	Papua SW	July 2012	60	%	8,054

The Company has signed various agreements that, subject to government approval, will change the working interests in several of its blocks in Indonesia.
In April 2013, the government approved the Company's relinquishment of its interest in the Lhokseumawe block.

All of the Indonesian blocks are in their initial three year exploration period, with the exception of the Lhokseumawe block. The seismic work commitments on the majority of the blocks have been fulfilled and as at March 31, 2013, the Company had remaining minimum work commitments to drill a total of ten wells. As at March 31, 2013, the Company's share of the remaining minimum work commitments as specified in the PSCs for the exploration period was $112 million to be spent at various dates through June 2015. The minimum work commitments are based on the Company's share of the estimated cost included in the PSCs and represent the amounts the host government may claim if the Company does not perform the work commitments. The actual cost of fulfilling work commitments may materially exceed the amount estimated in the PSCs. The Company has applied for or has plans to apply for extensions where drilling activity is planned. The Company is required to relinquish a portion of the exploration acreage after the first exploration period; however, the Company has received extensions in order to fulfill the well commitments on certain blocks.

Trinidad

As at March 31, 2013, the Company held interests in ten contract areas in Trinidad and Tobago, covering 9,862 square kilometers. The table below indicates the operator, the location of, the award date, the working interest and the size of the block.

Exploration Area	Operator	Location	Award Date	Working interest		Area (Square Kilometres	)
Block 2(ab) ⁽¹⁾	Niko	Offshore	July 2009	35.75	%	1,606
Guayaguayare-Shallow Horizon	Niko	Onshore/Offshore	July 2009	65	%	1,134
Guayaguayare-Deep Horizon	Niko	Onshore/Offshore	July 2009	80	%	1,190
Central Range-Shallow Horizon	Parex	Onshore	Sept. 2008	32.5	%	734
Central Range-Deep Horizon	Parex	Onshore	Sept. 2008	40	%	856
Block 4(b)	Niko	Offshore	April 2011	100	%	753
NCMA2	Niko	Offshore	April 2011	56	%	1,019
NCMA3	Niko	Offshore	April 2011	80	%	2,106
Block 5(c)⁽²⁾	BG Group	Offshore	July 2005	25	%	241
MG Block	Niko	Offshore	July 2007	70	%	223

The Company has applied to relinquish Block 2(ab).
Block 5(c) contains discoveries that are included in a field development plan submitted to the GTT for approval.

The seismic work commitments on the majority of the blocks and the drilling work commitments on Block 2(ab) have been fulfilled, and as at March 31, 2013, the Company had remaining minimum work commitments to drill a total of ten wells. As at March 31, 2013, the minimum remaining work commitments under the PSCs were $167 million, to be spent at various dates through April 2016 and represent the amounts the host government may claim if the Company does not perform the work commitments. The actual cost of fulfilling work commitments may materially exceed the amount estimated in the PSCs . The Company is working with various parties on farm-outs to reduce its share of future drilling costs.

Other Properties

India

Hazira Field

Niko is the operator of and holds a 33.33 percent interest in the Hazira Field, located about 25 kilometers southwest of the city of Surat and covering an area of 50 square kilometers on and offshore. Niko and GSPC have constructed a 36-inch gas sales pipeline to the local industrial area. The Company has constructed an offshore platform, an LBDP, a gas plant and an oil facility at the Hazira Field. The Company has one significant contract for the sale of natural gas at a price of $4.86/Mcf, expiring April 30, 2016, and the commitment for future physical deliveries under this contract exceeds the expected future production from the Hazira Field. Refer to note 30 to the consolidated financial statements for year ended March 31, 2013 for a complete discussion of this contingency.

Surat Block

The Company holds and is the operator of the 24 square kilometer Surat Block located onshore adjacent to the Hazira Field. The natural gas production from the Surat Block commenced in April 2004 and ceased in November 2012 as the cap on cumulative production in the approved field development plan was reached. The Company plans to relinquish the block.

Madagascar

In October 2008, the Company farmed into a PSC for a property located off the west coast of Madagascar covering approximately 16,845 square kilometers. The Company will earn a 75 percent participating interest in the Madagascar block and is the operator of this block. The Company has completed a multi-beam sea bed coring and 3,200 square kilometers of 3D seismic on the block. The Company has work commitments for an exploration well to be drilled prior to September 2015 and its share of the costs of the remaining commitments pursuant to the PSC is $10 million. The actual cost of fulfilling work commitments may exceed the amount estimated in the PSC. The Company is working with various parties on farm-outs to reduce its share of future drilling costs.

Pakistan

The Company holds and operates the four blocks comprising the Pakistan Blocks, located in the Arabian Sea near the city of Karachi and covering an area of 9,921 square kilometers. The Company has applied for relinquishment of all of the Pakistan Blocks.

Kurdistan

The Company held a 49% working interest in the Qara Dagh Block in Kurdistan and in November 2012, the Company and its consortium partners entered into an agreement with the Kurdistan Regional Government to surrender their collective interests in the block. Pursuant to the agreement, none of the consortium partners will have any future obligations or liabilities with regard to the original production sharing agreement, and the Company recovered a net amount of approximately $15 million in June 2013.

SEGMENT PROFIT

INDIA

	Year ended March 31,
(thousands of U.S. dollars)	2013		2012
Natural gas revenue	144,070		236,363
Oil and condensate revenue ⁽¹⁾	38,372		68,149
Royalties	(9,255	)	(15,456	)
Government share of profit petroleum	(9,552	)	(6,414	)
Production and operating expenses	(26,042	)	(31,795	)
Depletion and depreciation expenses	(131,480	)	(130,514	)
Asset impairment	101,544		(133,578	)
Exploration and evaluation expenses	(1,300	)	(12,233	)
Current income tax recovery / (expense)	298		(6,926	)
Minimum alternate tax expense	-		(9,107	)
Deferred income tax recovery / (expense)	(82,579	)	59,376
Change in accounting estimate - deferred taxes	-		(57,865	)
Segment profit / (loss)⁽²⁾	24,076		(40,000	)
Daily natural gas sales (Mcf/d)	96,089		157,719
Daily oil and condensate sales (bbls/d) ⁽¹⁾	1,024		1,706
Operating costs ($/Mcfe)	0.70		0.52
Depletion rate ($/Mcfe)	3.47		2.09

(1)	Production that is in inventory has not been included in the revenue or cost amounts indicated.
(2)	Segment profit / (loss) is a non-IFRS measure as calculated above.

Segment profit from India includes the results from the Dhirubhai 1 and 3 natural gas fields and the MA crude oil and natural gas field in the D6 Block, the Hazira crude oil and natural gas field and the Surat gas field.

The Company's oil and gas revenues for the year-to-date decreased from the prior year's periods, primarily due to natural production declines and reservoir management activities in the D6 Block. Production from the Surat block ceased in November 2012 as the cap on cumulative production in the approved field development plan was reached.

The decrease in royalties is a result of the decreased revenues described above. Royalties applicable to production from the D6 Block are five percent for the first seven years of commercial production and gas royalties applicable to the Hazira Field and Surat Block are currently 10 percent of the sales price.

Pursuant to the terms of the Indian PSCs, the Government of India is entitled to a sliding scale share in the profits once the Company has recovered its investment. Profits are defined as revenue less royalties, operating expenses and capital expenditures. An additional $6 million of the government share of profit petroleum for the Hazira Field was recognized and reduced crude oil and natural gas revenue in the period. The adjustment, related to crude oil and natural gas revenues earned in prior years, was the result of a court ruling finding that the 36-inch natural gas pipeline that Niko and GSPC constructed to connect the Hazira Field to the local industrial area was not eligible for cost recovery.

For the D6 Block, the Company is able to use up to 90 percent of revenue to recover costs. The Government of India was entitled to 10 percent of the profits not used to recover costs during the year. The government share of profit petroleum will continue at this level until the Company has recovered its costs. The Government of India was entitled to 25 percent and 20 percent of the profits from the Hazira Field and the Surat Block, respectively.

Operating costs at the D6 Block decreased mainly because of significant reduction in logistics costs due to reduced movement of material and inventory as compared to the prior year.

In the current year, as a result of increased reserves volumes assigned to the D6 Block in the March 31, 2013 reserve report, the Company recognized a $102 million reversal of the asset impairment recorded in the prior year related to the D6 Block in India. In the prior year, as a result of reduced reserves volumes assigned to the D6 Block in the March 31, 2012 reserve report, the Company had recognized a $133 million impairment related to the Company's producing assets in the D6 Block.

There was a current income tax recovery in the current year, primarily as a result of the adjustment to the government share of profit petroleum described above, which is deductible for tax purposes.

The deferred tax expense for the current year relates mainly to the reversal of temporary differences during the tax holiday period which mainly depends on the accounting depletion rate and capital spending during the period. In the current year the amount of temporary differences reversing during the tax holiday period came down significantly resulting in deferred tax expenses. For the prior year, the amounts of temporary differences reversing during the tax holiday period were significantly higher resulting in deferred tax recovery.

In the prior year, the change in accounting estimate is related to deferred income taxes as a result of estimating the amount of taxable temporary differences reversing during the tax holiday period.

Contingencies

The Company has contingencies related to natural gas sales contracts for the Hazira Field, the profit petroleum calculations for the Hazira Field and the D6 Block, and income taxes for the Hazira Field and the Surat Block. Refer to note 30 to the consolidated financial statements for year ended March 31, 2013 for a complete discussion of these contingencies.

BANGLADESH

	Year ended March 31,
(thousands of U.S. dollars)	2013		2012
Natural gas revenue	46,444		49,714
Condensate revenue	6,891		8,141
Government share of profit petroleum	(18,049	)	(19,589	)
Production and operating expenses	(10,278	)	(7,377	)
Depletion and depreciation expenses	(12,441	)	(13,055	)
Exploration and evaluation expenses	(361	)	(933	)
Impairment of long-term receivable	-		(22,996	)
Segment profit / (loss)⁽¹⁾	12,206		(6,095	)
Daily natural gas sales (Mcf/d)	54,936		58,962
Daily condensate sales (bbls/d)	175		191
Operating costs ($/Mcfe)	0.47		0.29
Depletion rate ($/Mcfe)	0.61		0.59

Segment profit is a non-IFRS measure as calculated above.

The Company's oil and gas revenues for the year decreased from the prior year, primarily due to the curtailment of production from one of the four wells in the Bangora field due to operational issues. Repairs to this well should be completed by the end of the second quarter and production restored to previous levels in the third quarter.

Pursuant to the terms of the PSC for Block 9, the Government of Bangladesh was entitled to 61 percent of profit gas in the current and prior years, which equates to 34 percent of revenues while the Company is recovering historical capital costs. Overall, the government share of profit petroleum decreased due to decreased revenues from Block 9.

Production and operating expense increased due to the well repair and commencement of facilities expansion work during the period.

The impairment of long term receivables in the prior year related to a receivable for natural gas sales to the Bangladesh Oil, Gas and Mineral Corporation (Petrobangla) from the Feni field in Bangladesh. The Company has filed for arbitration to settle this receivable. Due to the uncertainty with respect to the timing of resolution of this claim and various claims against the Company (as described below), a provision has recorded against the full amount of the receivable.

Contingencies

The Company has contingencies related to various claims filed against it with respect to the Feni property in Bangladesh as at March 31, 2013. Refer to note 30 to the consolidated financial statements for the year ended March 31, 2013 for a complete discussion of these contingencies.

Indonesia, Trinidad and Tobago, Kurdistan and Brazil

(thousands of U.S. dollars)	Exploration and evaluation expenses				Asset impairment			Income tax recovery		Depreciation and other				Segment Profit
	Year ended March 31,
	2013		2012		2013		2012	2013	2012	2013		2012		2013		2012
Indonesia	(92,206	)	(61,717	)	(16,281	)	-	34,671	9,319	116		6,256		(73,700	)	(46,142	)
Trinidad	(58,445	)	(111,996	)	(12,631	)	-	-	22,913	(128	)	(85	)	(71,204	)	(89,168	)
Kurdistan	(1,851	)	(40,455	)	(38,919	)	-	-	-	-		(25	)	(40,770	)	(40,480	)
Brazil	(13,956	)	-		-		-	-	-	-		-		(13,956	)	-

Indonesia

During the current year, the Company expensed exploration and evaluation costs of $60 million related to unsuccessful wells drilled in Indonesia in the year, including three wells in the Lhokseumawe block, and recognized an asset impairment of $16 million related to the Lhokseumawe block as the Company had given notice to surrender its interest to the operator of the block. In addition, exploration and evaluation costs expensed directly to income in the current year included $17 million for seismic and other exploration projects, $8 million for branch office costs, $4 million for share-based compensation costs, and $3 million for new ventures costs. For the prior year, the exploration and evaluation expenses related primarily to costs expensed directly to income in the year.

Trinidad and Tobago

During the current year, the Company expensed exploration and evaluation costs of $34 million related to unsuccessful wells drilled in Block 2(ab) and recognized an asset impairment of $13 million for Block 2(ab). In addition, exploration and evaluation costs expensed directly to income in the current year included $10 million for seismic and other exploration projects, $9 million for payments specified in various PSCs, and $5 million for branch office costs. For the prior year, the exploration and evaluation expenses included costs of $24 million related to unsuccessful wells and costs of $88 million expensed directly to income in the year.

Kurdistan

In the current year, the Company recognized an asset impairment of $39 million when it wrote down the carrying value of the Qara Dagh Block exploration and evaluation asset to the expected net proceeds to be received after relinquishment of the block.

Brazil

In the current year, the Company incurred $14 million of costs related to the acquisition of multi beam data over various blocks in Brazil. In May 2013, the Company and its joint venture partner were awarded two blocks offshore the north eastern coast of Brazil. The Company plans to market the multi-beam data to other successful bidders of blocks in the Brazil bid round.

Corporate

	Year ended March 31,
(thousands of U.S. dollars)	2013		2012
Share-based compensation expense	10,894		35,516
Finance income	(1,999	)	(4,302	)
Finance expense	33,768		34,970
Foreign exchange loss	3,200		14,366
Loss on short-term investments	2,106		5,823
Deferred tax recovery	7,476		-

Share-based compensation expense

The fair value per stock option granted decreased in the year due to decreased stock price in the period. Share-based compensation expense also decreased during the year due to the reversal of share-based compensation expense resulting from the forfeiture of stock options.

Finance expense

	Year ended March 31,
(thousands of U.S. dollars)	2013	2012
Interest expense	21,806	21,674
Accretion expense	8,677	7,612
Other	3,285	5,464
Finance expense	33,768	34,750

Interest expense includes interest on the Company's finance lease obligation, interest on borrowings on the Company's credit facility since March 2012, interest on the 5% Cdn$310 million of convertible debentures repaid in December 2012, and interest on the 7% Cdn$115 million of convertible notes issued in December 2012. Accretion expense relates to the recorded liabilities for the convertible notes, the convertible debentures and decommissioning obligations. The recorded liabilities increase as time progresses to the final settlement date, resulting in increased accretion expenses each year. Other finance expenses include costs related to pursuing financing options.

Foreign Exchange

	Year ended March 31,
(thousands of U.S. dollars)	2013	2012
Realized foreign exchange loss	3,123	8,271
Unrealized foreign exchange loss	77	6,095
Total foreign exchange loss	3,200	14,366

Due to the weakening of the Indian rupee versus the U.S. dollar in the current and prior years, the Company has realized foreign exchange losses primarily related to the differences in the Indian rupee to U.S. dollar exchange rate at the time of recording versus the time of settlement of individual accounts receivable and accounts payable. Unrealized foreign exchange losses have arisen on the translation of the Indian-rupee denominated income tax receivable and site restoration deposits.

Foreign exchange gains in the year on U.S. dollar cash held by a company whose functional currency is the Canadian dollar have increased accumulated other comprehensive income but do not flow through the income statement.

Short-Term Investments

The loss on short-term investments for the year was a result of marking the short-term investments to market value.

Deferred Tax Recovery

As a result of the issuance of convertible notes in December 2012, the Company recognized a deferred tax recovery as an unrecognized deferred tax asset was recognized to offset the deferred tax liability associated with the convertible notes.

NETBACKS

The following tables outline the Company's operating, funds from operations and earnings netbacks (all of which are non-IFRS measures):

	Year ended March 31, 2013						Year ended March 31, 2012
($/Mcfe)	India		Bangladesh		Total		India		Bangladesh		Total
Oil and natural gas revenue	4.89		2.61		4.09		4.97		2.64		4.36
Royalties	(0.25	)	-		(0.16	)	(0.25	)	-		(0.19	)
Government share of profit petroleum	(0.26	)	(0.88	)	(0.48	)	(0.10	)	(0.89	)	(0.31	)
Production and operating expenses	(0.70	)	(0.47	)	(0.6	)	(0.52	)	(0.29	)	(0.46	)
Operating netback	3.68		1.26		2.84		4.10		1.46		3.40
G&A					(0.12	)					(0.11	)
Farm out recovery income					0.01						0.08
Net finance expense					(0.45	)					(0.35	)
Current income tax expense					0.01						(0.07	)
Minimum alternate tax					-						(0.11	)
Funds from operations netback					2.27						2.84
Production and operating expenses					(0.02	)					(0.02	)
Depletion and depreciation expense					(2.51	)					(1.74	)
Exploration and evaluation expenses					(2.99	)					(2.80	)
Asset Impairment					(1.17	)					(1.60	)
Reversal of asset impairment					1.76						-
Impairment of long-term receivable					-						(0.30	)
Share based compensation expense					(0.19	)					(0.26	)
Net finance expense					(0.15	)					(0.09	)
Unrealized foreign exchange loss					(0.04	)					(0.07	)
(Loss) / gain on short-term investment
Deferred income tax (expense) / reduction					(0.70	)					1.10
Change in accounting estimate - deferred taxes					-						(0.69	)
Share-based compensation expense - impact of option cancellation					-						(0.17	)
Earnings netback					(3.74	)					(3.87	)

Netbacks for India, Bangladesh and in total are calculated by dividing the revenue and costs for each country and in total by the total sales volume for each country and in total measured in Mcfe.

LIQUIDITY AND CAPITAL RESOURCES

The Company's funding strategy is to use funds from operations from its producing properties, proceeds from non-core asset dispositions, farm-outs and other arrangements, and equity financing to fund its exploration programs and use funds from operations from its producing properties, and debt and equity financing to fund its development programs. Due to the timing and availability of the funding from various sources, the Company may, on occasion, utilize debt financing to fund its exploration programs and repay the debt with funds from operations, proceeds from non-core asset dispositions, farm-outs and other arrangements, and/or equity financing. If excess funds are available after funding the Company's planned capital programs for the foreseeable future, then the Company's Board of Directors would evaluate the option of paying dividends to its shareholders.

Credit Facility

In January 2012, the Company entered into a three-year facility agreement for a $225 million revolving credit facility and a $25 million operating facility for general corporate purposes.

The financial covenants of the credit facilities, calculated at the end of each fiscal quarter, are as follows:

Senior Debt to EBITDAX ratio not greater than 3:1;
Debt to EBITDAX ratio not greater than 3.75:1;
EBITDAX to Interest Expense ratio greater than 3:1; and
Debt to Capitalization ratio not greater than 50%.

As at March 31, 2013, as defined in the Credit Agreement:

Senior Debt includes the Company's a) borrowings under credit facilities and b) finance lease obligation;
Debt includes the Company's a) Senior Debt and b) senior unsecured convertible notes, less c) unrestricted cash and cash equivalents;
EBITDAX (for the trailing 12 months ending at the end of each fiscal quarter) includes the Company's net income less a) Interest Expense, b) income taxes, c) depletion and depreciation expense, d) exploration and evaluation expenses, and e) other non-cash items;
Interest Expense includes the Company's a) interest expense and b) standby and other fees in respect of Debt; and
Capitalization includes the Company's a) Debt and b) Shareholders' Equity (adjusted for the impact of conversion to IFRS).

As at March 31, 2013, the Senior Debt to EBITDAX ratio was 0.9:1, the Debt to EBITDAX ratio was 1.0:1, the EDITDAX to Interest Expense ratio was 7.0:1, and the Debt to Capitalization ratio was 14%, well within the specified financial covenants. Based on the Company's financial forecasts for fiscal 2014 and fiscal 2015, the Company expects to remain in compliance with the financial covenants of the credit facility throughout fiscal 2014 and fiscal 2015.

The maximum available credit under the credit agreement is subject to review based on, among other things, updates to the Company's reserves. In September, 2012, the syndicate of lenders confirmed a revised borrowing base amount under the facility to an aggregate of $100 million, based on the evaluation of the Company's reserves as at March 31, 2012 and based on an assumption that the pricing for gas sales from the D6 Block in India would remain unchanged at US$4.20 per MMBtu for the life of the D6 gas fields. As at March 31, 2013, the Company had borrowed $90 million under the credit facilities. Upon closing of the Company's private placement of the senior unsecured notes in June 2013, the amounts outstanding and the availability under the credit facility were reduced to $80 million. In connection with the completion of the Company's annual independent reserves evaluation as at March 31, 2013, the borrowing base of the facility will be re-determined by the syndicate banks on or before July 31, 2013, using the new pricing mechanism for domestic gas produced in India that was recently approved by the Government of India and will result in a significant increase in the price for the D6 Block natural gas sales contracts that expire on March 31, 2014.

Suspension of Quarterly Dividends

In September 2012, Niko's board of directors decided to suspend the Company's quarterly dividend in connection with the commencement of the Company's significant exploration drilling program. The timing and level of future dividends, if any, will be reviewed periodically by the board of directors.

Repayment of Convertible Debentures

In December 2012, the Company repaid its Cdn$310 million convertible debentures due December 30, 2012 at par plus accrued interest, using the net proceeds of Cdn$273 million of offerings of common shares and convertible notes, along with cash on hand and advances under the Company's credit facility. The Cdn$115 million principal amount of convertible senior unsecured notes issued in December 2012 mature on December 31, 2017 and bear interest at a rate of seven percent, with interest payable semi-annually in arrears on June 30 and December 31 of each year, commencing June 30, 2013. The notes are convertible at the option of each holder into common shares at a conversion price of Cdn$11.30 per share. After December 31, 2015, the notes are redeemable by the Company, in whole or in part from time to time, provided that the market price of the Company's common shares (defined as the weighted average trading price of the common shares for the twenty consecutive trading days ending five trading days prior to the issue of the notice of redemption) is at least 130% of the conversion price. The Company has the right to use common shares to satisfy some or all of its obligations for the notes.

Non-core Asset Dispositions, Farm-outs and Other Arrangements

Executed transactions resulting from the Company's program of farm-outs and other arrangements raised $70 million in fiscal 2013 and will provide an additional $44 million in fiscal 2014. The Company is also currently in negotiations with various third parties regarding non-core asset dispositions, further farm-outs, and other arrangements that are expected to provide significant liquidity for the Company in the future.

Contractual Obligations

The Company has various contractual obligations, as follows:

As at March 31, 2013		Obligations by Period
(thousands of U.S. dollars)	Total	< 1 year	1 to 3 years	3 to 5 years	> 5 years
Guarantees	7,991	1,416	6,575	-	-
Finance lease obligations ⁽¹⁾	58,292	10,757	21,513	21,513	4,509
Convertible notes payable ⁽²⁾	153,396	8,510	15,847	129,039	-
Decommissioning obligations ⁽³⁾	84,258	1,796	6,626	-	75,836
Exploration work commitments ⁽⁴⁾	289,000	88,000	201,000	-	-
Operating lease obligation ⁽⁵⁾	492,000	141,000	281,000	70,000	-
Total contractual obligations	1,084,937	251,479	532,561	220,552	80,345

The finance lease obligation relates to the charter of the FPSO used in the MA field in the D6 Block and includes both the current and long-term portions.
The convertible notes are recorded in the consolidated financial statements at $80 million, which is a discounted value to reflect the fact that the interest rate is lower than the market interest rate on similar notes without a conversion feature. The convertible notes are included in the table based on the sum of principal amount that would be required to be repay the Cdn$115 million convertible debentures plus quarterly interest payments, converted at the year-end exchange rate.
Decommissioning obligations are based on the undiscounted estimated future liability of the Company as disclosed in the notes of the financial statements for the year ended March 31, 2013. They do not include costs related to wells or facilities that were not complete as at March 31, 2013.
Details of the exploration work commitments by country are included in the Background of Properties section of this MD&A. The majority of the exploration work commitments relate to production sharing contracts where the Company is working on farm-outs to joint venture partners in exchange for a re-imbursement a portion of the sunk costs, funding of a disproportionate share of future costs, and/or future payments related to commencement of production or other milestones. Completion of these farm-outs could significantly reduce the Company's share of the future commitment costs. The Company has in the past and may in the future receive extensions to the periods required to complete the work commitments.
The operating lease obligation relates to the multi-year drilling rig contract for the Ocean Monarch that commenced on October 2, 2012 and runs for a term of four years, with a fifth year at the Company's option. The obligations shown in the table above reflect the gross minimum commitment amounts, before re-imbursement from partners in future wells and before potential assignment of the rig contract to third parties. The Company plans to use the drilling rig to fulfill its exploration drilling work commitments in Indonesia (included in the Exploration Work Commitments line item). The Company expects that a significant portion of the obligation will be funded by joint venture partners or by third parties who utilize the rig upon assignment of the rig contract. The table does not include costs related to the service contracts for the Indonesian drilling program as these contracts are generally based on usage and can be terminated with one week's notice.

Cash and Working Capital Deficit as at March 31, 2013

As at March 31, 2013, the Company had unrestricted cash of $56 million and a working capital deficit (current assets less current liabilities) of $32 million.

Issuance of Senior Unsecured Notes Subsequent to Year-end

In June 2013, the Company issued $63.5 million of senior unsecured notes. The notes bear interest at 7.00% per annum, payable monthly, and will be repaid through twelve equal monthly principal payments commencing August 13, 2013. Principal and interest payments are payable in cash or, at the Company's option, in common shares of the Company. If the Company elects to make any portion of a payment in common shares of the Company, the number of shares to be issued will be determined by dividing the amount to be paid in stock by 94.5% of the lower of the volume weighted average price of the shares for the fifteen day period prior to the payment date and the volume weighted average price of the shares for the five day period prior to the payment date, subject to certain restrictions. The notes are ranked equally with the Company's Cdn$115 million senior unsecured convertible notes issued in December, 2012. The net proceeds from the issue of the notes were approximately US$58.5 million, after deducting the initial purchasers' discount and the estimated related expenses payable by Niko. Under the terms of the notes, the net proceeds are available for general corporate purposes.

Funding of Working Capital Deficit, Planned Capital Spending and Repayment of Senior Unsecured Notes

For fiscal 2014, the Company's planned capital spending will be focused on development activities in India and exploration activities in Indonesia and Trinidad. The level of capital spending is flexible with decisions about capital spending to be made throughout the year. Funding for the Company's capital spending and repayment of the senior unsecured notes is expected to be provided by a combination of ongoing funds from operations from its producing properties, proceeds from non-core asset dispositions, farm-outs, and other arrangements, potential increases in the availability under its current credit facility or a replacement credit facility, additional debt financing, or issuance of equity.

Contingencies

The Company has a number of contingencies as at March 31, 2013 that could significantly impact liquidity. Refer to note 14 to the consolidated financial statements for the year ended March 31, 2013 for a complete discussion of these contingencies.

SUMMARY OF QUARTERLY RESULTS

The following tables set forth selected financial information of the Company, in thousands of U.S. dollars unless otherwise indicated, for the eight most recently completed quarters to March 31, 2013:

Three months ended		June 30, 2012		Sept. 30, 2012		Dec. 31, 2012		Mar. 31, 2013
Oil and natural gas revenue ⁽¹⁾		55,099		58,080		46,515		39,670
Net income (loss)		(92,121	)	(28,573	)	(93,709	)	(2,092	)
Per share
	Basic and diluted ($)	(1.78	)	(0.55	)	(1.64	)	(0.03	)

Three months ended		June 30, 2011		Sept. 30, 2011		Dec. 31, 2011		Mar. 31, 2012
Oil and natural gas revenue ⁽¹⁾		88,277		86,810		74,789		71,434
Net income (loss)		(54,983	)	(43,916	)	(40,405	)	(183,324	)
Per share
	Basic ($)	(1.07	)	(0.85	)	(0.78	)	(3.55	)

(1)	Oil and natural gas revenue is oil and natural gas sales less royalties and the government share of profit petroleum.

Net income in the quarters was affected by:

Over the quarters, oil and natural gas revenue from the D6 Block has declined due to reservoir performance.
In each quarter, the Company expenses a portion of its exploration and evaluation costs and the level of activity has varied over the periods.
In the quarter ended March 31, 2013, the Company recognized a $102 million reversal of asset impairment related to the D6 Block in India. The reversal of the impairment resulted from the impact of increased reserves volumes assigned to the D6 Block as at March 31, 2013 by Deloitte AJM. Management's estimate of value in use for the block was determined using forecasted cash flows using escalated prices and estimates of future production, capital and operating expenses. The prices used were based on gas pricing formula approved by the Government of India in June 2013, which is expected to increase natural gas sales price from the current price of $4.20/MMBtu to an estimated $8.40/MMbtu, effective April 1, 2014.
In the quarter ended March 31, 2013, the Company recorded a minimum alternate tax recovery of $6 million due to adjustment of D6 reserves in March 2013 reserve report, calculated according to Indian GAAP.
In the quarter ended December 31, 2012, there was a deferred tax recovery of $7 million due to the issuance of the convertible notes.
In the quarter ended September 30, 2012, there was a deferred tax recovery of $22 million, due to a reduction in exploration and evaluation assets related to proceeds from a farm out and from a former partner in exchange for assuming the partner's obligation for future drilling commitments.
In the quarter ended June 30, 2012, the Company recorded an additional $6 million of the government share of profit petroleum for the Hazira Field, reducing oil and natural gas revenue. The adjustment to the government share of profit petroleum was the result of a court ruling finding that the 36-inch natural gas sales pipeline that Niko and GSPC constructed to connect the Hazira Field to the local industrial area was not eligible for cost recovery.
In the quarter ended March 31, 2012, depletion expense increased as a result of revisions to the reserves and estimated future costs to develop the reserves.
In the quarter ended March 31, 2012, the Company impaired assets of $133 million and long term receivables of $23 million, in the quarter ended June 30, 2012, the Company impaired assets of $39 million, and in the quarter ended December 31, 2012, the Company impaired assets of $29 million.
In the quarter ended March 31, 2012, there was a deferred income tax recovery related to the revision of the reserve estimate, which increased the value of the tax holiday for the D6 Block. There were deferred income tax recoveries related to spending in Indonesia and Trinidad applied against the deferred income tax liabilities recorded upon the acquisitions of Voyager Energy Ltd. and Black Gold Energy LLC.
In each quarter, gains and losses are recognized based on fluctuations in the market prices of the Company's short-term investments that are valued at fair value.
In the quarter ended September 30, 2011, there was a $14 million expense upon cancellation of stock options to recognize the remainder of the expense associated with the options.
In the quarter ended June 30, 2011, there was a change in accounting estimate related to deferred income tax expense.
There was a revision in the method of estimating the amount of taxable temporary differences reversing during the tax holiday period.

FOURTH QUARTER

Funds from Operations

	Quarter ended March 31,
(thousands of U.S. dollars)	2013		2012
Oil and natural gas revenue	39,670		71,434
Production and operating expenses	(10,104	)	(10,920	)
General and administrative expenses	(1,942	)	(3,429	)
Finance income	980		1,598
Bank charges and other finance income	(756	)	(3,378	)
Realized foreign exchange loss	861		(3,868	)
EBITDAX⁽¹⁾	28,709		51,437
Interest expense	(4,200	)	(5,527	)
Current income tax expense	(1,010	)	(2,872	)
Minimum alternate tax recovery	6,249		9,914
Funds from operations ⁽¹⁾	29,748		52,952

(1)	Funds from operations is a non-IFRS measure as defined under "Non-IFRS measures" in this MD&A.

The explanations provided in "Overall Performance" apply to the changes in the quarter ended March 31, 2013 compared to the quarter ended March 31, 2012 except as follows:

There was minimum alternate tax (MAT) expense in the current year quarter and prior year's quarter on Indian GAAP accounting profits from the D6 block. There was an adjustment to MAT expense in the current year's quarter as a result of the change in Indian GAAP accounting profits as due to the change in estimate of reserves and its effect on depletion expense.

Net Income (Loss)

	Quarters ended March 31,
(thousands of U.S. dollars)	2013		2012
Funds from operations (non-IFRS measure)	29,748		52,952
Production and operating expenses	(264	)	(55	)
Depletion and depreciation expense	(32,654	)	(58,569	)
Exploration and evaluation expense	(21,579	)	(116,015	)
Gain on short-term investments	(1,547	)	360
Asset impairment	-		(133,504	)
Reversal of asset impairment	101,544		-
Share-based compensation expense	(2,883	)	(3,738	)
Other expenses	-		-
Finance expense	(1,982	)	(1,970	)
Impairment of long-term receivable	-		(22,996	)
Unrealized foreign exchange (loss) / gain	(1,512	)	1,531
Deferred income tax (expense) / reduction	(70,963	)	98,679
Net income (loss)	(2,092	)	(183,325	)

The explanations provided in "Overall Performance" applies to the changes in the quarter ended March 31, 2013 compared to the quarter ended March 31, 2012 except as follows:

Exploration expense in the prior year quarter is comprised primarily of the costs to exit the D4 block in India, seismic in Trinidad, unsuccessful exploration wells in in Trinidad and India, branch operating costs and annual payments specified in the various PSCs.

SELECTED ANNUAL INFORMATION

	Years ended March 31,
(thousands of U.S. dollars)	2013		2012		2011
Oil and natural gas revenue⁽¹⁾	199,364		321,311		403,856
Net income (loss)	(216,496	)	(322,628	)	69,897
Per share basic ($)	(3.76	)	(6.25	)	1.37
Per share diluted ($)	(3.76	)	(6.25	)	1.36
Total assets	1,493,807		1,618,487		1,889,741
Total long-term financial liabilities	169,785		25,000		309,221
Dividends per share (Cdn$)	0.06		0.24		0.21

(1)	Oil and natural gas revenue is oil and natural gas sales less royalties and the government share of profit petroleum.

The decrease in revenue and changes in net income is described above in the Overall Performance section. Some of the major changes in Assets and Liabilities are described below:

Total assets decreased each year primarily due to depletion and asset impairments.
Total long term financial liabilities in fiscal 2011 included the Cdn$310 million convertible debentures that moved to current liabilities in fiscal 2012. These debentures were repaid in fiscal 2013 using proceeds from issuance of Cdn$115 million senior unsecured convertible notes and Cdn$158 million of common shares, along with borrowings on the Company's credit facility and cash on hand.

RELATED PARTIES

The Company has a 45 percent interest in a Canadian property that is operated by a related party, a Company owned by the President and CEO of the Company. This joint interest originated as a result of the related party buying the interest of the third-party operator of the property in 2002. The transactions with the related party are not significant to operations or consolidated financial statements. The transactions with the related party are measured at estimated fair value.

FINANCIAL INSTRUMENTS

The Company's financial instruments consist of short and long-term investments, accounts receivable, long-term accounts receivable, accounts payable and accrued liabilities, borrowings, convertible notes and convertible debentures.

The Company is exposed to fluctuations in the value of cash, accounts receivable, short-term investments, accounts payable and accrued liabilities due to changes in foreign exchange rates as these financial instruments are partially or wholly denominated in Canadian dollars and the local currencies of the countries in which it operate. The Company manages the risk by converting cash held in foreign currencies to U.S. dollars as required to fund forecasted expenditures. The Company is exposed to changes in foreign exchange rates as the future interest and principal amounts on the convertible notes are in Canadian dollars.

The Company is exposed to changes in the market value of the short-term investments.

The Company is exposed to credit risk with respect to all of its financial instruments if a customer or counterparty fails to meet its contractual obligations. The Company has deposited cash and restricted cash with reputable financial institutions, for which management believes the risk of loss to be remote. The Company takes measures in order to mitigate any risk of loss with respect to the accounts receivable, which may include obtaining guarantees.

The Company is exposed to the risk of changes in market prices of commodities. The Company enters into physical commodity contracts for the sale of natural gas, which partially mitigates this risk. The Company does so in the normal course of business by entering into contracts with fixed natural gas prices. The contracts are not classified as financial instruments because the Company expects to deliver all required volumes under the contracts. No amounts are recognized in the consolidated financial statements related to the contracts until such time as the associated volumes are delivered. The Company is exposed to the changes in the Brent crude price as the average Brent crude price from the preceding year (to a defined maximum) is a variable in the natural gas price for the current year, calculated annually, for the D6 Block natural gas contracts.

The fair values of accounts receivable, accounts payable and accrued liabilities approximate their carrying values due to their short periods to maturity. The fair value of the short-term investments is based on publicly quoted market values. The fair value of the long-term investments is based on their historical cost as they are not traded on publicly quoted markets

The fair value of the borrowings approximates its carrying value due to the nature of the borrowings. Interest expense on the borrowings of $1 million and $4 million was recorded for the three and twelve months ended March 31, 2013.

The debt component of the convertible notes has been recorded net of the fair value of the conversion feature. The fair value of the conversion feature of the notes included in shareholders' equity at the date of issue was $31 million ($24 million net of a deferred tax recovery). The fair value of the conversion feature of the debentures was determined based on the discounted future payments using a discount rate of a similar financial instrument without a conversion feature compared to the fixed rate of interest on the notes. Interest and financing expense of $3 million and $19 million for the three and twelve months ended March 31, 2013 were recorded for interest expense and accretion of the discount on the convertible notes and debentures.

CRITICAL ACCOUNTING ESTIMATES

The Company makes assumptions in applying certain critical accounting estimates that are uncertain at the time the accounting estimate is made and may have a significant effect on the consolidated financial statements of the Company.

Oil and Natural Gas Reserves

Reserves estimated can have a significant effect on net earnings as a result of their impact on the depletion rate, provisions for decommissioning obligations and asset impairments. Independent qualified engineers in conjunction with the Company's reserve engineer estimate the value of oil and natural gas reserves on an annual basis. The estimation of reserves is an inherently complex process requiring significant judgment. Estimates of economically recoverable oil and gas reserves and future cash flows from those reserves are based upon a number of variables and assumptions such as geological interpretation, commodity prices, operation and capital costs and production forecasts, all of which may vary considerable from actual results. These estimates are expected to revised upward or downward over time, as additional information such as reservoir performance becomes available, or as economic conditions change.

Depletion and Impairment of Producing Assets

The net carrying value of producing asset is depleted using the unit-of-production method by reference to the ratio of production in the year to the related total proved reserves of oil and natural gas, taking into account estimated future development costs necessary to bring those reserves into production. Revisions to reserve estimates and the associated future cash flows could significantly increase or decrease depletion expense charged to net income and could result in an impairment of property, plant and equipment charged as an expense to net income.

Impairment of Tangible and Intangible Assets

At the end of each reporting period, the Company assesses whether there is any indication that an asset may be impaired. If any such indication exists, the Company estimates the recoverable amount of the asset. Indications include: a significant decline in market value of the asset; significant changes have taken or will take place in the technological; market, economic or legal environment in which the Company operates or in the market to which an asset is dedicated; a significant increase in market interest rates that would affect the discount rate and value of the asset; and the carrying amount of the net assets of the entity is more than its market capitalization. Irrespective of whether there is any indication of impairment, the Company tests intangible assets with an indefinite useful life and intangible assets not yet available for use for impairment annually by comparing its carrying amount with its recoverable amount. The recoverable amount requires the use of assumptions and estimates including quantities of recoverable resources, estimated production quantities, future commodity prices and further exploration, development and production costs. Changes in any of these assumptions could impact the estimated recoverable amount and result in an impairment of exploration and evaluation assets, development assets, capital work-in-progress and other property, plant and equipment.

Decommissioning Obligations

Production sharing contracts that the Company has entered into indicate an obligation for abandonment of wells and facilities including removal of all equipment and installations and site restoration, collectively termed decommissioning obligations. Provision is made for the estimated cost of decommissioning obligations for a well that has been drilled and for equipment or installations upon completion. The provision is capitalized in the relevant asset category and a corresponding liability is recognized.

The provision for decommissioning obligations is calculated as the present value of the expenditures expected to be required to settle the obligation in the future. The present value is based on the best estimate of future costs and the economic lives of the wells, facilities and pipelines. There is uncertainty regarding both the amount and timing of incurring these costs and a change in either could result in an adjustment to the relevant capital asset and the decommissioning obligation.

Income Taxes

The Company estimates current and future income taxes based on its interpretation of tax laws in the various jurisdictions in which it operates and pays income taxes. The Company recorded its income tax expense including provisions that provide for a tax holiday deduction for various undertakings related to the Hazira and Surat properties for the taxation years 1998 to 2008. Should the tax authorities determine that the tax holiday deduction does not apply to natural gas, the Company would pay additional cash taxes, write-off the net income tax receivable on the statement of financial position and recognize additional income tax expense as a charge to net income. This may also impact the oil and natural gas reserves and asset impairment related to these properties. See note 31 to the consolidated financial statements for further discussion.

Share-Based Compensation

Compensation expense associated with the Company's share-based compensation plan is calculated and, recognized in net income or capitalized, over the vesting period of the stock option with a corresponding increase in contributed surplus. A forfeiture rate used in the calculation of compensation expense is estimated on the grant date and is adjusted to reflect the actual number of options that vest.

ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED

As of January 1, 2013, Niko will be required to adopt amendments to IAS 1 "Presentation of Financial Statements" which will require companies to group together items within other comprehensive income that may be reclassified to the net earnings section of the comprehensive income statement. Niko does not expect a material impact as a result of the amendments. Each of the additional new standards outlined below is effective for annual periods beginning on or after January 1, 2013 with early adoption permitted, except for IFRS 9 "Financial Instruments" which is effective for annual periods beginning on or after January 1, 2015. The Company has not yet assessed the impact, if any, that the new amended standards will have on its financial statements or whether to early adopt any of the new requirements.

IFRS 9 - Financial Instruments

The result of the first phase of the IASB's project to replace IAS 39, "Financial Instruments: Recognition and Measurement". The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value.

IFRS 10 - Consolidated Financial Statements

Replaces Standing Interpretations Committee 12, "Consolidation - Special Purpose Entities" and the consolidation requirements of IAS 27 "Consolidated and Separate Financial Statements". The new standard replaces the existing risk and rewards based approaches and establish control as the determining factor when determining whether an interest in another entity should be included in the consolidated financial statements.

IFRS 11 - Joint Arrangements

Replaces IAS 31 "Interests in Joint Ventures" and IAS 28 "Investment in Associates". IFRS 11, "Joint Arrangements", requires a venturer to classify its interest in a joint arrangement as a joint venture or joint operation. Joint ventures will be accounted for using the equity method of accounting whereas for a joint operation the venturer will recognize its share of the assets, liabilities, revenue and expenses of the joint operation. Under existing IFRS, entities have the choice to proportionately consolidate or equity account for interests in joint ventures.

IFRS 12 - Disclosure of Interests in Other Entities

Provides comprehensive disclosure requirements on interests in other entities, including joint arrangements, associates, and special purpose vehicles. The new disclosure requires information that will assist financial statement users in evaluating the nature, risks and financial effects of an entity's interest in subsidiaries and joint arrangements.

IFRS 13 - Fair Value Measurement

Provides a common definition of fair value within IFRS. The new standard provides measurement and disclosure guidance and applies when IFRS requires or permits the item to be measured at fair value, with limited exceptions. This standard does not determine when an item is measured at fair value and as such does not require new fair value measurements.

DISCLOSURE CONTROLS AND PROCEDURES

The Company's Chief Executive Officer and Chief Financial Officer are responsible for designing disclosure controls and procedures or causing them to be designed under their supervision and evaluating the effectiveness of disclosure controls and procedures. The Company's Chief Executive Officer and Chief Financial Officer oversee the design and evaluation process and have concluded that the design and operation of these disclosure controls and procedures were effective in ensuring material information required to be disclosed in quarterly filings or other reports filed or submitted under applicable Canadian securities laws is made known to management on a timely basis to allow decisions regarding required disclosure.

RISK FACTORS

In the normal course of business the Company is exposed to a variety of actual and potential events, uncertainties, trends and risks. In addition to the risks associated with the use of assumptions in the critical accounting estimates, financial instruments, the Company's commitments and actual and expected operating events, all of which are discussed above, the Company has identified the following events, uncertainties, trends and risks that could have a material adverse impact on the Company:

The Company may not be able to find reserves at a reasonable cost, develop reserves within required time-frames or at a reasonable cost, or sell these reserves for a reasonable profit;
Reserves may be revised due to economic and technical factors;
The Company may not be able to obtain approval, or obtain approval on a timely basis for exploration and development activities;
Changing governmental policies, social instability and other political, economic or diplomatic developments in the countries in which the Company operates;
Changing taxation policies, taxation laws and interpretations thereof;
Adverse factors including climate and geographical conditions, weather conditions and labour disputes;
Changes in foreign exchange rates that impact the Company's non-U.S. dollar transactions; and
Changes in future oil and natural gas prices.

For a comprehensive discussion of all identified risks, refer to the Company's Annual Information Form, which can be found at www.sedar.com.

The Company has a number of contingencies as at March 31, 2013. Refer to the notes to the Company's consolidated financial statements for a complete list of the contingencies and any potential effects on the Company.

OUTSTANDING SHARE DATA

At July 8, 2013, the Company had the following amounts outstanding:

	Number	Cdn$ Amount ⁽¹	⁾
Common shares	70,215,911	1,477,585,000
Preferred shares	Nil	Nil
Stock options	4,866,936	-

This is the dollar amount received for common shares issued excluding share issue costs and is presented in Canadian dollars. The U.S. dollar equivalent at July 8, 2013 is $1,324,234,000.

MANAGEMENT'S REPORT

The accompanying consolidated financial statements and all other information contained elsewhere in this report is the responsibility of the management of Niko Resources Ltd. The consolidated financial statements necessarily include amounts that are based on estimates, which have been objectively developed by management using all relevant information. The financial information contained elsewhere in this report has been reviewed to ensure consistency with the consolidated financial statements.

Management maintains and evaluates the effectiveness of disclosure controls and procedures and internal control over financial reporting for Niko Resources Ltd. Disclosure controls and procedures are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with International Financial Reporting Standards. The Company evaluates the effectiveness of internal controls over financial reporting at the financial year end and discloses its conclusions about the effectiveness in the Company's annual Management's Discussion and Analysis.

The Audit Committee of the Board of Directors, comprised of non-management directors, has reviewed the consolidated financial statements with management and the auditors. The consolidated financial statements have been approved by the Board of Directors on recommendation of the Audit Committee.

The consolidated financial statements have been audited by KPMG LLP, the external auditors, in accordance with auditing standards generally accepted in Canada on behalf of the shareholders.

(signed) "Edward S. Sampson"	(signed) "Glen R. Valk"
Edward S. Sampson	Glen R. Valk
President and CEO	Vice President, Finance and CFO
July 8, 2013

INDEPENDENT AUDITORS' REPORT

To the Shareholders of Niko Resources Ltd.

We have audited the accompanying consolidated financial statements of Niko Resources Ltd., which comprise the consolidated statements of financial position as at March 31, 2013 and March 31, 2012, the consolidated statements of comprehensive income (loss), changes in shareholders' equity and cash flows for the years ended March 31, 2013 and 2012, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management's responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Niko Resources Ltd. as at March 31, 2013 and March 31, 2012, and its consolidated financial performance and its consolidated cash flows for the years ended March 31, 2013 and 2012 in accordance with International Financial Reporting Standards.

(signed) "KPMG LLP"

Chartered Accountants

Calgary, Canada

July 8, 2013

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(thousands of U.S. dollars)		As at March 31, 2013		As at March 31, 2012
Assets
Current assets
	Cash and cash equivalents	56,393		64,495
	Restricted cash (note 5)	1,416		6,790
	Accounts receivable (note 6)	84,834		61,247
	Inventories (note 7)	10,100		9,961
	Short-term investment (note 8)	92		748
		152,835		143,241
Restricted cash (note 5)		14,029		11,283
Long-term investment (note 9)		1,270		2,752
Long-term accounts receivable (note 10)		1,528		2,202
Exploration and evaluation assets (note 11)		695,624		856,880
Property, plant and equipment (note 12)		594,166		509,091
Income tax receivable (note 30e)		34,355		34,724
Deferred tax asset (note 24)		-		58,314
		1,493,807		1,618,487
Liabilities
Current liabilities
	Accounts payable and accrued liabilities (note 13)	177,576		101,660
	Current tax payable	1,272		1,220
	Current portion of finance lease obligation (note 15)	6,057		4,804
	Convertible debentures (note 16)	-		306,052
		184,905		413,736
Credit facility borrowings (note 14)		90,000		25,000
Finance lease obligation (note 15)		37,024		43,671
Convertible notes payable (note 16)		79,785		-
Decommissioning obligation (note 17)		41,177		40,017
Deferred tax liabilities (note 24)		185,109		195,515
		618,000		717,939
Shareholders' Equity
Share capital (note 19)		1,324,234		1,171,439
Contributed surplus		139,137		104,964
Equity component of convertible debentures		23,232		14,765
Currency translation reserve		(2,757	)	(2,094	)
Deficit		(608,039	)	(388,526	)
		875,807		900,548
		1,493,807		1,618,487

The accompanying notes are an integral part of these financial statements.

Approved on behalf of the Board

(signed) "Wendell W. Robinson"
Wendell W. Robinson
Chairman of the Audit Committee, Director

(signed) "William T. Hornday"
William T. Hornday
Chief Operating Officer, Director

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

		Year ended March 31,
(thousands of U.S. dollars, except per share amounts)		2013		2012

Oil and natural gas revenue (note 20)		199,364		321,311
Production and operating expenses		(36,778	)	(40,196	)
Depletion and depreciation expenses (note 12)		(145,250	)	(144,595	)
Exploration and evaluation expenses (note 21)		(172,811	)	(232,692	)
Loss on investments (note 8 & 9)		(2,106	)	(5,823	)
Asset impairment (note 11 & 12)		(67,831	)	(133,578	)
Reversal of asset impairment (note 12)		101,544		-
Other income		311		6,440
Share-based compensation expense		(10,894	)	(35,516	)
General and administrative expenses		(6,931	)	(8,776	)
		(141,382	)	(273,425	)

Finance income		1,999		4,302
Finance expense (note 23)		(33,768	)	(57,856	)
Foreign exchange loss		(3,200	)	(14,366	)
		(34,969	)	(67,920	)

Loss before income tax		(176,351	)	(341,345	)

Current income tax reduction/(expense)		289		(5,920	)
Minimum alternate tax expense		-		(9,105	)
Deferred income tax (expense)/reduction		(40,434	)	33,742
Income tax (expense)/reduction (note 24)		(40,145	)	18,717

Net loss		(216,496	)	(322,628	)

Foreign currency translation gain/(loss)		(663	)	6,250
Comprehensive loss for the year		(217,159	)	(316,378	)

Loss per share: (note 25)
	Basic and diluted	$ (3.76	)	$ (6.25	)
The accompanying notes are an integral part of these financial statements.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

(thousands of U.S. dollars, except number of common shares)	Common shares (#	)	Share capital	Contributed surplus		Currency translation reserve		Equity component of convertible debentures		Deficit		Total
Balance, March 31, 2011	51,526,901		1,162,319	63,037		(8,344	)	14,765		(53,392	)	1,178,385
Options exercised	114,944		9,120	(2,288	)	-		-		-		6,832
Share-based compensation expense	-		-	44,215		-		-		-		44,215
Net income for the year	-		-	-		-		-		(322,628	)	(322,628	)
Payment of dividends⁽¹⁾	-		-	-		-		-		(12,506	)	(12,506	)
Foreign currency translation	-		-	-		6,250		-		-		6,250
Balance, March 31, 2012	51,641,845		1,171,439	104,964		(2,094	)	14,765		(388,526	)	900,548
Options exercised	-		-	-		-		-		-		-
Share-based compensation expense	-		-	19,408		-		-		-		19,408
Issuance of common shares	18,570,350		152,752	-		-		-		-		152,752
Issuance of convertible notes	-		-	-		-		30,724		-		30,724
Deferred tax	-		-	-		-		(7,492	)	-		(7,492	)
Repayment of convertible debentures	3,716		43	14,765		-		(14,765	)	-		43
Net loss for the year	-		-	-		-		-		(216,496	)	(216,496	)
Payment of dividends¹	-		-	-		-		-		(3,017	)	(3,017	)
Foreign currency translation	-		-	-		(663	)	-		-		(663	)
Balance, March 31, 2013	70,215,911		1,324,234	139,137		(2,757	)	23,232		(608,039	)	875,807

¹	The Company paid dividends of $0.24 per share and $0.06 per share in the years ended March 31, 2012 and 2013, respectively.

The accompanying notes are an integral part of these financial statements.

CONSOLIDATED STATEMENTS OF CASHFLOWS

(thousands of U.S. dollars, except per share amounts)		Year ended March 31,
		2013		2012

Cash flows from operating activities:
Net (loss) / income		(216,496	)	(322,628	)

Adjustments for:
	Depletion and depreciation expense	145,250		144,595
	Accretion expense	8,678		7,612
	Deferred income tax expense (reduction)	40,434		(33,742	)
	Unrealized foreign exchange loss	76		6,095
	Loss on short-term investment	2,106		5,823
	Asset impairment	67,831		133,415
	Reversal of asset impairment	(101,544	)	-
	Exploration and evaluation write-off	94,089		71,816
	Share-based compensation expense	18,378		43,358
	Impairment of long-term receivable	-		22,996
Change in non-cash working capital		(1,734	)	11,744
Change in long-term accounts receivable		2,446		16,550
Net cash from operating activities		59,514		107,634

Cash flows from investing activities:
	Exploration and evaluation expenditures	(173,212	)	(162,901	)
	Disposition of exploration and evaluation assets	-		2,355
	Property, plant and equipment expenditures	(30,542	)	(25,089	)
	Proceeds from farm-outs and other arrangements (note 11)	70,203		-
	Restricted cash contributions	(4,835	)	(9,500	)
	Release of restricted cash	7,089		8,550
	Disposition of investments	-		7,970
	Change in non-cash working capital	55,536		13,009
Net cash used in investing activities		(75,761	)	(165,606	)

Cash flows from financing activities:
	Proceeds from issuance of common shares, net of issuance costs	152,752		6,832
	Proceeds from issuance of convertible notes, net of issuance costs (note 16)	110,892		-
	Repayment of convertible debentures (note 16)	(312,106	)	-
	Change in borrowings	65,000		25,000
	Reduction in finance lease obligation	(5,394	)	(4,804	)
	Dividends paid	(3,017	)	(12,506	)
Net cash from financing activities		8,127		14,522

Change in cash and cash equivalents		(8,120	)	(43,450	)

Effect of translation on foreign currency cash		18		(397	)
Cash and cash equivalents, beginning of year		64,495		108,342
Cash and cash equivalents, end of year		56,393		64,495

The accompanying notes are an integral part of these financial statements.

SUBSEQUENT EVENTS

Issuance of unsecured notes

On June 13, 2013, the Company issued US$63.5 million principal amount of Unsecured Notes for aggregate net proceeds of approximately US$58.5 million, after deducting the initial purchasers' discount and the estimated related expenses payable by the Company. The Unsecured Notes bear interest at the rate of 7 percent per annum, payable monthly, and will be repaid through twelve equal monthly principal payments commencing August 13, 2013. The Company may repay some or all of the Unsecured Notes, plus any accrued and unpaid interest, by issuing Common Shares of the Company, rather than repaying the Unsecured Notes in money. If the Company elects to make any portion of a payment in Common Shares, the number of Common Shares to be issued will be determined by dividing the amount to be paid in Common Shares by 94.5 percent of the lower of the volume weighted average price of the shares for the 15 day period prior to the payment date and the volume weighted average price of the Common Shares for the five day period prior to the payment date, subject to certain restrictions. To the extent that the applicable price determined under the above formula is less than 85 percent of the volume weighted average price of the Common Shares for the five day period prior to the payment date then, in lieu of delivering Common Shares, the Company will make a cash payment to the holders of the Unsecured Notes. Additional details regarding the terms of the Unsecured Notes are contained in the material change report of the Company dated June 24, 2013, a copy of which is available at www.sedar.com.

Kurdistan block

In June 2013, the Company recovered a net amount of approximately $15 million related to its Company 49% working interest in the Qara Dagh Block in Kurdistan. In November 2012, the Company and its consortium partners had entered into an agreement with the Kurdistan Regional Government to surrender their collective interests in the block. Pursuant to the agreement, none of the consortium partners will have any future obligations or liabilities with regard to the original production sharing agreement. .

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. General information

Niko Resources Ltd. (the "Company") is a limited company incorporated in Alberta, Canada. The addresses of its registered office and principal place of business is 4600, 400 - 3 Avenue SW, Calgary, AB, T2P4H2. The Company is engaged in the exploration for and development and production of oil and natural gas in the countries listed in note 26. The Company's common shares and convertible notes are traded on the Toronto Stock Exchange.

2. Basis of presentation and significant accounting policies

a. Statement of compliance

The financial statements have been prepared by management in accordance with International Financial Reporting Standards (IFRS). Issued by the International Accounting Standards Board (IASB).

The financial statements were approved by the board of directors and authorized for issue on July 8, 2013.

b. Basis of preparation and presentation

The financial statements have been prepared on the historical cost basis except for the revaluation of certain financial instruments as described in sections g. and o. of this note.

The consolidated financial statements are presented in US dollars and all values are rounded to the nearest thousand dollars ($000), except where otherwise indicated.

c. Basis of consolidation

The consolidated financial statements incorporate the financial statements of the Company and entities controlled by the Company (its subsidiaries). Control is achieved where the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities.

The results of subsidiaries acquired or disposed of during the year are included in the consolidated statement of comprehensive income (loss) from the effective date of acquisition and up to the effective date of disposal, as appropriate.

Where necessary, adjustments are made to the financial statements of subsidiaries to bring their accounting policies in line with those used by the Company.

All significant intra-group transactions, balances, income and expenses are eliminated in full on consolidation.

d. Cash and cash equivalents

Cash and cash equivalents consist of cash and demand deposits.

e. Business combinations

The purchase method of accounting is used to account for acquisitions of subsidiaries and assets that meet the definition of a business under IFRS. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. Costs incurred by the Company related to the acquisition are expensed in the periods they are incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the cost of acquisition over the fair value of identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of acquisition is less than the fair value of the net assets acquired, the difference is recognized immediately in earnings.

If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the Company reports provisional amounts for the items for which the accounting is incomplete. Those provisional amounts are adjusted when the Company obtains complete information about facts and circumstances that existed as of the acquisition date that, if known, would have affected the amounts recognized as of that date.

f. Interests in joint ventures

The Company is engaged in oil and gas exploration, development and production through unincorporated joint ventures. The consolidated financial statements include the Company's share of the assets, liabilities and cash flows of the joint venture. The Company combines its share of the joint ventures' individual income and expenses, assets and liabilities and cash flows on a line-by-line basis with similar items in the Company's financial statements. Income taxes are recorded based on the Company's share of the joint venture's activities.

The following table sets out a listing and description of the Company's interests in joint ventures:¹

Block	Country	Working interest %	Block	Country	Working interest %
Block 9	Bangladesh	60	Obi	Indonesia	51
Feni/Chattak	Bangladesh	100	Seram	Indonesia	55
D6	India	10	South East Ganal I	Indonesia	100
Hazira Field	India	33	South East Seram	Indonesia	100
NEC	India	10	South Matindok	Indonesia	100
Aru	Indonesia	60	Sunda Strait I	Indonesia	100
Bone Bay	Indonesia	100	West Papua IV	Indonesia	49.90
Cendrawasih	Indonesia	100	West Sageri	Indonesia	100
Cendrawasih Bay II	Indonesia	50	Grand Prix	Madagascar	75
Cendrawasih Bay III	Indonesia	50	Central Range, Shallow Horizon	Trinidad	32.50
Cendrawasih Bay IV	Indonesia	50	Central Range, Deep Horizon	Trinidad	40
East Bula	Indonesia	55	Guayaguayare, Shallow Horizon	Trinidad	65
Halmahera-Kofiau	Indonesia	51	Guayaguayare, Deep Horizon	Trinidad	80
Halmahera II	Indonesia	20	Block 4(b)	Trinidad	100
Kofiau	Indonesia	57.50	NCMA2	Trinidad	56
Kumawa	Indonesia	100	NCMA3	Trinidad	80
North Ganal	Indonesia	31	Block 5(c)	Trinidad	25
North Makassar	Indonesia	30	MG Block	Trinidad	70

¹	Excludes properties that the Company intends to relinquish. Working interest is as at March 31, 2013 and does not reflect farm-outs or farm-in transactions that are awaiting government approval.

g. Financial assets

Financial assets are initially measured at fair value, plus transaction costs, except for those financial assets classified as fair value through profit or loss, which are initially measured at fair value.

All recognized financial assets are subsequently measured in their entirety at either amortized cost or fair value depending on their classification. The Company classifies financial assets into the following categories: financial assets at fair value through profit or loss; loans and receivables; held-to-maturity investments and available-for-sale financial assets.

Financial assets at fair value through profit or loss are measured at fair value with the corresponding gains or losses recognized in profit or loss. The Company classifies cash and cash equivalents, restricted cash, short-term investments and long-term investments as held-for-trading financial assets.

Loans and receivables and held-to-maturity investments are measured at amortized cost using the effective interest method. The Company classifies accounts receivable and long-term accounts receivables as loans and receivables. The Company does not have any financial instruments classified as held-to-maturity.

Available-for-sale financial assets are recognized at fair value with the gains and losses, except for impairment losses and foreign exchange gains and losses, being recognized in other comprehensive income (loss) and transferred to profit or loss when the asset is derecognized or impaired. The Company does not have any financial assets classified as held-for-sale.

The Company assesses whether there is any objective evidence that a financial asset or group of financial assets is impaired at the end of each reporting period. Any loss determined is recognized in earnings.

h. Inventories

Inventories of stock, spares and consumables are purchased for use in oil and gas operations and are valued at the lesser of cost and fair value less cost to sell. The costs of purchase of inventories comprise the purchase price, import duties and other taxes, and transport, handling and other costs directly attributable to the acquisition of finished goods, materials and services.

Inventory of oil and condensate is valued at the lower of the weighted average cost and net realizable value. Cost is comprised of operating expenses that have been incurred in bringing inventories to their present location and condition and the portion of depletion expense associated with the oil and condensate production. The cost of inventories is assigned using the weighted average cost formula, whereby the cost of each barrel of oil or condensate is determined from the weighted average of the cost of each barrel at the beginning of a period and the cost of barrels produced during the period. Net realizable value is the estimated selling price in the ordinary course of business less the estimated costs necessary to make the sale.

i. Oil and natural gas exploration and development expenditure

Oil and natural gas exploration and development expenditure is accounted for using the method described below.

(i) Pre-license costs - Pre-licence costs are charged against income as incurred.

(ii) Licence and property acquisition costs - Exploration licence and property acquisition costs are capitalized as exploration and evaluation assets pending drilling results on the licence.

(iii) Exploration expenditure - Geological and geophysical exploration costs are charged against income as incurred.

Costs directly attributable to an exploration well are initially capitalized as exploration and evaluation assets. If hydrocarbons are not found, the exploration expenditure is written off as a dry hole. If hydrocarbons are found and, subject to further appraisal activity, which may include the drilling of further wells, may be capable of commercial development, the costs continue to be carried as an asset. All such carried costs are subject to regular technical, commercial and management review to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are written off. When proved reserves of oil and natural gas are determined and development is sanctioned, the relevant expenditure is transferred to development assets.

All other exploration costs are expensed when incurred.

(iv) Development and production expenditure

Expenditure for development and production assets including the costs of drilling development wells and the construction of production facilities are capitalized under development assets and transferred to producing assets when they are put in use. After recognition as an asset, development and producing assets are carried at cost less any accumulated depletion and impairment losses.

(v) Farm-outs

The Company enters into agreements to transfer a portion of its interests in oil and gas properties (farm-outs) to third parties. Proceeds from these arrangements are first deducted from any exploration and evaluation and development assets recorded for the property and any excess is recognized as other income.

j. Other property, plant and equipment

Items of property, plant and equipment are initially recorded at cost and subsequently measured at cost less accumulated depreciation and impairment losses. Initial costs include expenditure that is directly attributable to the acquisition of the asset. The costs of the day-to-day servicing of items of property, plant and equipment are recognized in income as incurred.

k. Intangible assets

Intangible assets acquired separately and with finite useful lives are carried at cost less accumulated amortization and impairment losses. Amortization of intangible assets with finite useful lives is provided on a straight-line basis over their estimated useful lives. Alternatively, intangible assets with indefinite useful lives are carried at cost less any subsequent accumulated impairment losses.

Gains or losses arising from derecognition of an intangible asset are measured at the difference between the net disposal proceeds and the carrying amount of the asset and are recognized in income when the asset is derecognized.

l. Depletion and depreciation

Exploration and evaluation assets and development assets are not depreciated.

The net carrying value of producing assets is depleted using the unit-of-production method by reference to the ratio of production in the year to the related total proved reserves of oil and natural gas, taking into account estimated future development costs necessary to bring those reserves into production.

Depreciation for finance lease assets is consistent with that for depreciable assets that are owned. Depreciation for finance lease assets is charged based on the unit-of-production method over the life of the total proved reserves.

For other assets, depreciation is recognized in profit or loss on a diminishing balance or straight-line basis depending on the nature of the asset over the estimated useful lives of each group of property, plant and equipment. Land is not depreciated.

The estimated useful lives of other property, plant and equipment are:

Buildings	27 - 30 years
Plant and machinery	7 - 9 years
Office equipment/furniture and fittings	3 - 10 years
Computers	3 - 5 years
Vehicles and aircraft	4 - 7 years
Pipeline	20 years

m. Borrowing costs

Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use.

Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalization.

All other borrowing costs are recognized in income in the period in which they are incurred.

n. Impairment of tangible and intangible assets

At the end of each reporting period, the Company assesses whether there is any indication that an asset may be impaired or may require a reversal of impairment. Impairment is assessed at the CGU level and the determination of CGUs is an area of judgment. If any such indication exists, the Company estimates the recoverable amount of the asset. Indications include: a significant decline in market value of the asset; significant changes have taken or will take place in the technological market, economic or legal environment in which the Company operates or in the market to which an asset is dedicated; a significant increase in market interest rates that would affect the discount rate and value of the asset; and the carrying amount of the net assets of the entity is more than its market capitalization. The recoverable amount is defined as the greater of the asset's fair value less cost to sell and its value in use.

Irrespective of whether there is any indication of impairment, the Company tests intangible assets with an indefinite useful life and intangible assets not yet available for use for impairment annually by comparing its carrying amount with its recoverable amount.

o. Financial liabilities and equity instruments issued by the Company

Financial liabilities are initially measured at fair value, plus transaction costs, except for those financial liabilities classified as at fair value through profit or loss, which are initially measured at fair value. All recognized financial liabilities are subsequently measured in their entirety at either amortized cost or fair value depending on their nature.

Financial liabilities at fair value through profit or loss are measured at fair value with the corresponding gains or losses recognized in profit or loss. The Company does not have any financial liabilities at fair value through profit or loss.

All other financial liabilities are measured at amortized cost using the effective interest method. The Company classified accounts payable and provisions, long-term debt, convertible debentures and convertible notes as other financial liabilities.

p. Derivative financial instruments

A derivative liability that is linked to and must be settled by delivery of an unquoted equity instrument whose fair value cannot be reliably measured is measured at cost. The Company does not have any derivative liabilities.

Derivative financial instruments are measured at fair value through profit or loss. The Company does not currently have any derivative financial instruments.

q. Leasing

A lease is classified as a finance lease whenever the terms of the lease transfer substantially all the risks and rewards incidental to ownership to the lessee. At the commencement of the lease term, the Company recognizes the finance lease as assets and liabilities in the statements of financial position at the lesser of the fair value of the leased property and the present value of the minimum lease payments. Any initial direct costs of the lessee are added to the amount recognised as an asset.

Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset.

Minimum lease payments are apportioned between the finance charge and the reduction of the outstanding liability. The finance charge is allocated to each period during the lease term so as to produce a constant periodic rate of interest on the remaining balance of the liability. Finance charges are charged directly against income, unless they are directly attributable to qualifying assets, in which case they are capitalized in accordance with the Group's policy on borrowing costs. Contingent rents are charged as expenses in the periods in which they are incurred.

An operating lease is a lease other than a finance lease.

Lease payments under an operating lease are generally recognised as an expense on a straight-line basis over the lease term.

r. Decommissioning obligations

Certain production sharing contracts that the Company has entered into indicate an obligation for abandonment of wells and facilities including removal of all equipment and installations and site restoration, collectively termed decommissioning obligations. Provision is made for the estimated cost of decommissioning obligations for a well that has been drilled and for equipment or installations upon completion. The provision is capitalized in the relevant asset category.

The provision for decommissioning obligations is management's best estimate of the expenditure required to settle the present obligation at the end of the reporting period. The provision is calculated as the present value of the expenditures expected to be required to settle the obligation in the future, discounted using a risk-free rate. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision to the extent the provision was established.

s. Revenue recognition

Revenue resulting from the sale of oil, condensate and natural gas from properties in which the Company has an interest with other producers is recognized on the basis of the Company's working interest.

Revenue from the sale of oil, condensate and natural gas is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer, which is at the delivery point as defined in the various sales contracts. Revenue is measured at the fair value of the consideration received or receivable. Revenue recorded is net of VAT, other sales-related taxes, royalties and the profit oil and gas sold and paid to the various governments as profit sharing.

t. Finance income and finance expense

Finance income is accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable.

Finance expense comprises i) interest expense on borrowings, convertible debentures and notes payable, ii) accretion on decommissioning obligations and convertible debentures and notes, iii) bank charges and other finance costs and iv) impairment losses recognized on financial assets.

u. Foreign currencies

The individual financial statements of each group entity are presented in the currency of the primary economic environment in which the entity operates (its functional currency), which is U.S. dollars for the foreign entities and Canadian dollars for Canadian entities. For the purpose of the consolidated financial statements, the results and financial position of each group entity are expressed in U.S. dollars, which is the presentation currency for the consolidated financial statements.

In preparing financial statements of the individual entities, transactions in currencies other than the entity's functional currency (foreign currencies) are recognized at the rates of exchange prevailing at the date of the transactions. At the end of each reporting period, monetary items denominated in foreign currencies are retranslated at the rates prevailing at that date. Non-monetary items carried at fair value that are denominated in foreign currencies are retranslated at the rates prevailing at the date when the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated. Exchange differences are recognized in the statement of comprehensive income (loss) in the period in which they arise.

For the purpose of presenting consolidated financial statements, the assets and liabilities of the Canadian entities with the Canadian dollar as their functional currency are expressed in U.S. dollars using exchange rates prevailing at the end of the reporting period. Income and expense items are translated at the average exchange rates for the period. Exchange differences arising, if any, are recognized in other comprehensive income (loss) and accumulated in equity.

v. Share-based payments

The Company has a share-based compensation plan as described in note 18(b). All share-based awards of the Company are equity settled. Compensation expense associated with the plan is calculated and, recognized in income or capitalized, over the vesting period of the stock option with a corresponding increase in contributed surplus. The consideration received upon exercise of the stock options, together with the amount previously recognized in contributed surplus, is recorded as an increase to share capital. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest.

w. Taxation

Income tax expense is the sum of current tax, minimum alternate tax and deferred tax.

Current tax is the amount of income taxes payable in respect of the taxable profit for the period. Taxable profit differs from profit as reported in the consolidated statement of comprehensive income because of items of income or expense that are taxable or deductible in other years and items that are never taxable or deductible. The Company's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the end of the reporting period.

Minimum alternate tax is the amount of tax payable in respect of accounting profits. The Company pays the greater of minimum alternate tax and current tax for blocks in India.

Deferred tax is recognized on temporary differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the calculation of taxable profit. Deferred tax liabilities are the amounts of income taxes payable in future periods in respect of taxable temporary differences. Deferred tax assets are the amounts of income taxes recoverable in future periods in respect of deductible temporary differences and the carry-forward of unused tax losses and unused tax credits.

Deferred tax liabilities are recognized for taxable temporary differences associated with investments in subsidiaries and associates, and interests in joint ventures, except where the Company is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future. Deferred tax assets arising from deductible temporary differences associated with such investments and interests are only recognized to the extent that it is probable there will be sufficient taxable profits against which to utilise the benefits of the temporary differences and they are expected to reverse in the foreseeable future.

The carrying amount of deferred tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is settled or the asset realized, based on tax rates and tax laws that have been enacted or substantively enacted by the end of the reporting period. The measurement of deferred tax liabilities and assets reflects the tax consequences that would follow from the manner in which the Company expects, at the end of the reporting period, to recover or settle the carrying amount of its assets and liabilities.

Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority and the Company intends to settle its current tax assets and liabilities on a net basis.

Current and deferred tax are recognized as an expense or income in net income, except when they relate to items that are recognized outside profit or loss (whether in other comprehensive income or directly in equity), in which case the tax is also recognized outside profit or loss, or where they arise from the initial accounting for a business combination. In the case of a business combination, the tax effect is included in the accounting for the business combination.

x. Earnings per share

Basic earnings per share is calculated by dividing the income or loss attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined by adjusting the income or loss attributable to common shareholders and the weighted average number of common shares outstanding, for the effects of all dilutive potential common shares, which comprise convertible notes and share options granted to employees.

3. Future accounting changes

The International Accounting Standards Board (IASB) has issued IFRS 9 "Financial Instruments" to replace IAS 39 "Financial Instruments: Recognition and Measurement". The new standard replaces the multiple classification and measurement models for financial assets and liabilities with a new model that has only two categories: amortized cost and fair value through profit and loss. Under IFRS 9, fair value changes due to credit risk for liabilities designated at fair value through profit and loss would generally be recorded in other comprehensive income. The new standard is effective for annual periods beginning on or after January 1, 2015. The Company is currently assessing the impact of the new standard on its consolidated financial statements.

In May 2012, the IASB issued or amended a number of standards that will be effective for annual periods beginning on or after January 1, 2013.

Three new standards are IFRS 10 "Consolidated Financial Statements", IFRS 11 "Joint Arrangements" and IFRS 12 "Disclosure of Interests in Other Entities". IFRS 10 establishes a single control model that applies to all entities and will require management to exercise judgment to determine which entities are controlled and need to be consolidated by the parent. The Company will continue to consolidate all of its wholly-owned subsidiaries and is currently assessing the accounting impact of its investments in other companies. IFRS 11 replaces IAS 31 "Interest in Joint Ventures" and SIC-13 "Jointly-controlled Entities - Non-monetary Contributions by Venturers". IFRS 11 identifies two forms of joint ventures when there is joint control: joint operations and joint ventures. Joint operations are accounted for using proportionate consolidation and joint ventures are accounted for using the equity method. IFRS 11 focuses on the nature of the rights and obligations associated with the joint arrangements and the Company is currently evaluating the effect of this standard on its joint arrangements. IFRS 12 introduces a number of new disclosures related to consolidated financial statements and interests in subsidiaries, joint arrangements, associates and structured entities.

As a result of the new standards described above, the IAS has amended IAS 28 "Investments in Associates and Joint Ventures" to prescribe the accounting for investments in associates and to set out the requirements for the application of the equity method when accounting for investments in associates and joint ventures.

The IASB published IFRS 13 "Fair Value Measurement" which provides a precise definition of fair value and a single source of fair value measurement disclosures requirements for use across IFRSs.

The IASB issued amendments to IAS 1 Presentation of Financial Statements requiring companies preparing financial statements in accordance with IFRSs to group together items within other comprehensive income (OCI) that may be reclassified to the profit or loss section of the income statement. The amendments apply to annual periods beginning on or after July 1, 2013.

The IASB reissued IAS 27 "Separate Financial Statements" to focus solely on accounting and disclosure requirements when an entity presents separate financial statements that are not consolidated financial statements.

The Company plans to adopt these standards when they become effective and is currently assessing the impact of the standards listed above on its consolidated financial statements.

4. Management's judgements and estimation uncertainty

The preparation of the consolidated financial statements in conformity with IFRS 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 dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. By their nature, these estimates are subject to measurement uncertainty and actual results may differ from those estimated.

Significant estimates and judgement made by management in the preparation of these consolidated financial statements are as follows:

Critical accounting estimates

Amounts recorded for depletion and amounts used for impairment calculations are based on estimates of petroleum and natural gas reserves. By their nature, the estimates of reserves, including the estimates of future prices, costs, discount rates and the related future cash flows, are subject to measurement uncertainty. Accordingly, the impact to the consolidated financial statements in future periods could be material.
Amounts recorded for decommissioning obligations and the related accretion expense requires the use of estimates with respect to the amount and timing of decommissioning expenditures. Other provisions are recognized in the period when it becomes probable that there will be a future cash outflow.
Compensation costs recognized for the share-based compensation plan are subject to the estimate of what the ultimate payout will be using the Black-Scholes-Merton model, which is based on significant assumptions such as volatility, expected life, expected dividends and expected forfeiture rates.
Tax interpretations, regulations and legislation in the various jurisdictions in which the Company operates are subject to change. As such, income taxes are subject to measurement uncertainty. Management makes certain judgements in estimating the timing of temporary difference reversals and the likelihood that deferred tax assets will be realized from future taxable earnings. Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.

Critical accounting judgements

At the end of each reporting period, the Company assesses whether there is any indication that an asset may be impaired. If any such indication exists, the Company estimates the recoverable amount of the asset. Events and circumstances may change resulting in indicators of impairment in future periods that could result in a material impairment.

The recoverability of production asset carrying values is assessed at the cash generating unit (CGU) level. Determination of what constitutes a CGU is subject to management judgements and the circumstances, but generally, each production sharing contract (PSC) constitutes a CGU. The composition of a CGU can impact the recoverability of the assets included therein. In assessing the recoverability of oil and gas properties, each CGU's carrying value is compared to its recoverable amount, defined as the greater of its fair value less cost to sell and value in use. At March 31, 2013, the recoverable amounts of the Company's CGUs for producing assets were estimated as the value in use based on the net present value of the cash flows from oil and gas reserves for the CGU for the D6 Block based on reserves estimated by the Company's independent reserve evaluator and for the Hazira and Surat Blocks based on reserves estimated by the Company. By their nature, the estimates of reserves, including the estimates of future prices, costs, discount rates and the related future cash flows, are subject to measurement uncertainty. Accordingly, the impact to the consolidated financial statements in future periods could be material.

The following commodity price estimates were used in the calculation of net present value of the cash flows from oil and gas reserves:

Year ending March 31,	India Natural Gas ($/MMbtu	)	India Crude Oil ($/bbl	)	India MA NGL ($/bbl	)	Trinidad and Tobago Local Market ($/MMbtu	)	Block 9 gas price ($/Mcf	)	Block 9 condensate price ($/bbl	)
2014	4.21		107.63		88.53		4.85		2.31		103.59
2015	10.45		101.36		82.26		4.55		2.31		99.84
2016	12.13		94.09		74.99		4.80		2.31		99.36
2017	13.67		95.23		76.13		5.00		2.31		98.74
2018	13.95		94.74		75.64		5.35		2.31		97.95
Thereafter	+2	%	+2	%	+2	%	+2	%	2.31		99.47

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company operates are subject to change. As such, income taxes are subject to measurement uncertainty. Management makes certain judgements in estimating the timing of temporary difference reversals and the likelihood that deferred tax assets will be realized from future taxable earnings. Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.

5. Restricted cash

(thousands of U.S. dollars)	As at March 31, 2013	As at March 31, 2012
Current portion of restricted cash
Guarantees ¹	1,416	6,790
	1,416	6,790

Non-current portion of restricted cash
Guarantees ¹	6,575	4,540
Site restoration funds ²	7,454	6,743
	14,029	11,283

¹	The Company has performance security guarantees related to the work commitments for exploration blocks. The Company is required to provide funds to support the guarantees in the amounts indicated above. See note 27 for details of the guarantees.
²	In accordance with the Site Restoration Fund Scheme, 1999 in India, the Company is required to accumulate funds in a separate restricted account related to future decommissioning obligations. The funds may be used for site restoration on the expiry or termination of an agreement or relinquishment of part of the contract area.

6. Accounts receivable

(thousands of U.S. dollars)	As at March 31, 2013	As at March 31, 2012
Oil and gas revenues receivable	17,804	28,033
Receivable from joint venture partners	39,170	13,004
Advances to vendors	1,618	1,751
Prepaid expenses and deposits	3,860	4,816
VAT receivable	18,505	9,405
Other receivables	3,877	4,238
	84,834	61,247

7. Inventories

(thousands of U.S. dollars)	As at March 31, 2013	As at March 31, 2012
Stock, spares and consumables	9,617	9,596
Oil and condensate inventories	483	365
	10,100	9,961

8. Short-term investments

(thousands of U.S. dollars)	Year ended March 31, 2013		Year ended March 31, 2012
Opening balance	748		14,922
Disposals	-		(7,970	)
Loss on short-term investments	(653	)	(5,823	)
Foreign exchange	(3	)	(381	)
Closing balance	92		748

9. Long-term investments

(thousands of U.S. dollars)	Year ended March 31, 2013		Year ended March 31, 2012
Opening balance	2,752		2,830
Loss on long-term investments	(1,453	)	-
Foreign exchange	(29	)	(78	)
Closing balance	1,270		2,752

Long-term investments consist of shares in a Canadian company that were not traded on an active market during 2012 and as such were carried at cost and adjusted for changes in the USD-CAD exchange rate. In February 2013 the shares began trading on the Canadian Venture Stock Exchange, at which point the Company began carrying the shares at fair value based on the quoted market price. The shares owned by the Company comprise approximately 25% of the issued and outstanding shares of the company but does not control the company. In addition, the Company's holdings exceed the average daily transaction volume. As such management has determined that it has no intention of disposing the shares within the next twelve months.

10. Long-term accounts receivable

(thousands of U.S. dollars)	As at March 31, 2013		As at March 31, 2012
Joint venture receivable - 36-inch pipeline	1,528		2,202

Joint venture receivable - 36-inch pipeline: The Company has recognized a receivable for a refund of previously paid profit petroleum and a receivable from its joint venture partner as a result of the award of ownership of a 36-inch pipeline that is connected to the Hazira facilities.

11. Exploration and evaluation assets

(thousands of U.S. dollars)	Year ended March 31, 2013		Year ended March 31, 2012
Opening balance	856,880		762,221
Additions (note 26)	174,242		164,976
Transfers	(102,766	)	5,354
Expensed	(94,089	)	(71,500	)
Impairment	(66,896	)	-
Disposals and other arrangements	(70,697	)	(2,355	)
Foreign currency translation	(1,050	)	(1,816	)
Closing balance	695,624		856,880

During the year, the Company expensed $94 million of exploration costs primarily related to unsuccessful exploration wells in Indonesia and Trinidad. The Company also estimated the recoverable amount of Kurdistan exploration and evaluation assets and certain exploration and evaluation assets in Indonesian and Trinidad associated with unsuccessful wells and recognized impairments of $67 million. In addition, the Company recorded proceeds of a farm-out of $9 million and received $61 million from two former partners in exchange for assuming the partners' obligations for future drilling commitments

12. Property, plant and equipment

a. Development assets

(thousands of U.S. dollars)	Year ended March 31, 2013	Year ended March 31, 2012
Opening balance	16,988	18,421
Additions	10,044	7,447
Transfers from/to other asset categories	102,790	(8,880	)
Closing balance	129,822	16,988

b. Producing assets

(thousands of U.S. dollars)	Year ended March 31, 2013		Year ended March 31, 2012
Cost
Opening balance	1,042,869		1,019,696
Additions	134		16,458
Transfers from other asset categories/adjustments	(40	)	6,791
Disposals	(3,711	)	-
Foreign currency translation	(44	)	(76	)
Closing balance	1,039,208		1,042,869
Accumulated depletion
Opening balance	(587,372	)	(312,767	)
Additions	(142,099	)	(141,266	)
Foreign currency translation	45		76
Closing balance	(729,426	)	(587,372	)
Impairment	101,544		(133,415	)
Net producing assets	411,325		455,497

For the year ended March 31, 2012, the Company recognized a $133 million impairment related to the producing assets in the D6 Block in India as a result of reduced reserves volumes assigned to the D6 Block as at March 31, 2012. The producing assets were written down to management's estimate of value in use and determined using proved reserves and forecast cash flows using escalated prices and estimates of future production, capital and operating expenses, discounted at 10 percent, obtained from the reserve report. The prices used were those forecast by management and included in the company's independent reserve report for that year.

For the year ended March 31, 2013, the Company recognized a $102 million reversal of asset impairment related to the D6 Block in India. The reversal of the impairment resulted from the impact of increased reserves volumes assigned to the D6 Block as at March 31, 2013 by Deloitte AJM. Management's estimate of value in use for the block was determined using forecasted cash flows using escalated prices and estimates of future production, capital and operating expenses. The prices used were based on gas pricing formula approved by the Government of India in June 2013, which is expected to increase natural gas sales price from the current price of $4.20/MMBtu to an estimated $8.42/MMbtu, effective April 1, 2014.

c. Other property, plant and equipment

(thousands of U.S. dollars)	Land and buildings		Vehicles, helicopters and aircraft		Office equipment, furniture and fittings		Pipelines		Total
Cost
Balance, April 1, 2012	18,346		2,376		8,754		10,772		40,248
Additions / Transfers	(112	)	(3	)	1,196		(10	)	1,071
Disposals	-		(27	)	(535	)	-		(562	)
Foreign currency translation	-		-		(62	)	-		(62	)
Balance, March 31, 2013	18,234		2,346		9,353		10,762		40,695

Accumulated depreciation
Balance, April 1, 2012	(6,127	)	(1,482	)	(4,449	)	(7,341	)	(19,399	)
Additions	(1,034	)	(172	)	(1,344	)	(511	)	(3,061	)
Foreign currency translation	-		-		38		-		38
Balance, March 31, 2013	(7,161	)	(1,654	)	(5,755	)	(7,852	)	(22,422	)

Net book value, March 31, 2013	11,073		692		3,598		2,910		18,273

(thousands of U.S. dollars)	Land and buildings		Vehicles, helicopters and aircraft		Office equipment, furniture and fittings		Pipelines		Total
Cost
Balance, April 1, 2011	18,108		2,395		5,978		10,752		37,233
Additions	238		-		2,907		20		3,165
Disposals	-		(19	)	(89	)	-		(108	)
Foreign currency translation loss	-		-		(42	)	-		(42	)
Balance, March 31, 2012	18,346		2,376		8,754		10,772		40,248

Accumulated depreciation
Balance, April 1, 2011	(4,880	)	(1,148	)	(3,390	)	(6,738	)	(16,156	)
Additions / Transfers	(1,247	)	(352	)	(1,126	)	(603	)	(3,328	)
Disposals	-		18		34		-		52
Foreign currency translation gain	-		-		33		-		33
Balance, March 31, 2012	(6,127	)	(1,482	)	(4,449	)	(7,341	)	(19,399	)

Net book value, March 31, 2012	12,219		894		4,305		3,431		20,849

d. Capital work-in-progress

(thousands of U.S. dollars)	As at March 31, 2013		As at March 31, 2012
Capital work-in-progress	34,746		15,757

13. Trade and other payables

(thousands of U.S. dollars)	Year ended March 31, 2013	Year ended March 31, 2012
Joint venture payables (operated)	50,621	12,810
Joint venture payables (non-operated)	11,422	8,642
Accruals	115,535	80,208
Closing balance	177,578	101,660

14. Credit facility borrowings

The Company has a $225 million three year, extendible, revolving credit facility and a $25 million three year, extendible, operating facility pursuant to a credit agreement with a syndicate of banks and financial institutions

15. Finance lease obligation

The Company has recognized a finance lease for the floating, production, storage and offloading vessel (FPSO) used in the D6 Block in India. The fair value of $43 million for the finance lease is calculated based on future lease payments discounted at a rate of 11.65 percent. The finance lease asset is included in producing properties within property, plant and equipment and the net carrying amount is $32 million. The future minimum lease payments as at the end of the reporting period and their net present value are:

	Lease payments
<1 year	10,757
1-5 years	43,026
> 5 years	4,509
Subtotal	58,292
Imputed interest	(15,211)
Carrying value	43,081

The lease has an initial charter period of 3,650 days maturing in 2018, which is cancellable by paying exit costs. The Company has an option to purchase the leased asset.

16. Convertible debentures and notes payable

a. Convertible debentures

(thousands of U.S. dollars)	Year ended March 31, 2013		Year ended March 31, 2012
Opening balance	306,052		309,221
Accretion expense	4,242		5,336
Foreign currency translation	1,854		(8,505	)
Repaid	(312,148	)	-
Closing balance	-		306,052

On December 30, 2009, the Company issued Cdn$310 million, five percent convertible debentures (the "Debentures"), with a maturity date of December 30, 2012. The convertible debentures were repaid in full in December, 2012.

b. Notes payable

(thousands of U.S. dollars)	Year ended March 31, 2013		Year ended March 31, 2012
Opening balance	-		-
Additions	80,168		-
Accretion expense	1,527		-
Foreign currency translation	(1,868	)	-
Repaid	(42	)	-
Closing balance	79,785		-

In December 2012, the Company issued Cdn$115 million principal amount of convertible senior unsecured notes (the "Notes") of which Cdn$32 million (less issuance costs of Cdn$1 million) was allocated to the conversion option and classified in the equity section on the Statement of Financial Position. The equity portion is recorded net of a Cdn$7 million deferred tax liability which results from the temporary difference between the carrying amount and the tax value of the Notes. The liability portion of the Notes is carried net of issuance costs of Cdn$4 million. The issuance costs were allocated between the debt and equity portion of the notes pro-rata based on the valuation of the gross proceeds.

The Notes mature on December 31, 2017 and bear interest at a rate of 7 percent, with interest payable semi-annually in arrears on June 30 and December 31 of each year, commencing June 30, 2013. The Notes are convertible at the option of the holders into common shares at a conversion price of Cdn$11.30 per share. After December 31, 2015, the Notes are redeemable by the Company, in whole or in part from time to time, provided that the market price of the Company's common shares (defined as the weighted average trading price of the common shares for the twenty consecutive trading days ending five trading days prior to the issue of the notice of redemption) is at least 130% of the conversion price. The Company has the right to use common shares to satisfy some or all of its obligations for the Notes.

17. Decommissioning obligations

(thousands of U.S. dollars)	Year ended March 31, 2013		Year ended March 31, 2012
Opening balance	40,017		31,454
Provisions made during the year	(1,563	)	537
Change in estimate during the year	(185	)	5,750
Accretion	2,908		2,276
Closing balance	41,177		40,017

The Company's decommissioning obligations result from its ownership interest in oil and natural gas assets including well sites and facilities. The total decommissioning obligation is estimated based on the Company's net ownership interest in wells and facilities, estimated costs of removal of all equipment and installations and site restoration and the estimated timing of the costs to be incurred in future years. The Company has estimated the net present value of the decommissioning obligations to be $41 million as at March 31, 2013 (March 31, 2012 - $40 million) based on an undiscounted total future liability of $84 million (March 31, 2012 - $67 million). These costs are expected to be incurred over the next two to 13 years. The discount rate used to calculate the net present value of the future decommissioning obligations is the pre-tax rate reflecting current market assessments of the time value of money. Amounts totalling Rs. 406 million (US$ 7.5 million) have been deposited with State Bank of India for decommissioning obligations. These amounts have been treated as restricted cash included in non-current assets.

18. Financial instruments

a. Capital risk management

The Company's policy is to maintain a strong capital base and related capital structure. The objectives of this policy are:

To promote confidence in the Company by the capital markets, by investors, by creditors and by government agencies in the countries in which the Company bids for concessions and/or operates;
To maintain resources required to withstand financial difficulties due to exogenous influences such as financial, political, economic, social or market uncertainties and events; and
To facilitate the Company's ability to fulfill exploration and development commitments, and to seek and execute growth opportunities.

The Company's capital base includes shareholders' equity and outstanding borrowings as follows:

(thousands of U.S. dollars)	As at March 31, 2013	As at March 31, 2012
Borrowings	90,000	25,000
Convertible debentures / notes payable	79,785	306,052
Shareholders' equity	875,807	900,548

The Company's objective in capital management is to have the flexibility to alter the capital structure to take advantage of capital-raising opportunities in the capital markets, whether they are equity or debt-related.

To manage capital, the Company uses a rolling three-year projection. The projection provides details for the major components of sources and uses of cash for operations, financing and development and exploration expenditure commitments. Management and the Board of Directors review the projection annually and when contemplating interim financing or expenditure alternatives. As part of the review process, the Company also contemplates using farm-outs to reduce its expenditure commitments. The periodic reviews help ensure that the Company has the ability to fulfill its obligations and to fund ongoing operations. There were no changes in the Company's approach to capital management during the period.

b. Categories and fair value of financial instruments

Financial instruments are recognized under the following categories and have the following carrying values¹:

(thousands of U.S. dollars)	As at March 31, 2013	As at March 31, 2012
Financial assets and financial liabilities at fair value through profit and loss: financial assets classified as held-for-trading
- Restricted cash, current	1,416	6,790
- Short-term investments	92	748
- Restricted cash, non-current	14,029	11,283
- Long-term investments	1,270	2,752
Loans and receivables
- Accounts receivable	84,834	61,247
- Long-term accounts receivable	1,528	2,202
Financial liabilities measured at amortized cost
- Accounts payable	177,576	101,660
- Borrowings	90,000	25,000
- Convertible debentures and notes payable	79,785	306,052

¹	The fair values approximate the carrying values as described below.

The Company's short-term investments are classified as held-for-trading, which is a financial asset at fair value through profit or loss. The Company classifies fair value measurements using the following fair value hierarchy that reflects the significance of the inputs used in making the measurements:

- Level 1: Quoted prices (unadjusted) in active markets for identical assets or liabilities;

- Level 2: Inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices); and

- Level 3: Inputs for the asset or liability that are not based on observable market date (unobservable inputs).

Short-term investments as at March 31, 2012 and March 31, 2013 and long-term investments as at March 31, 2013 have been assessed on the fair value hierarchy describe above and have been classified as Level 1. The fair value of the short and long-term investments was based on publicly quoted market values. There was a loss of $0.7 million in the year (2012 - $5.8 million) on recognizing the short-term investments at their fair value. There was a loss of $1.5 million in the year (2012 - nil) on recognizing the long-term investments at their fair value. The fair values of short and long-term investments approximate their carrying amounts as they are recognized at fair value. Long-term investments were recognised at cost of $2.8 million in 2012 as at the time these securities were not traded on an active market.

Cash and cash equivalents and restricted cash are classified as held-for-trading and measured at fair value through profit and loss. Accounts receivable are classified as loans and receivables. The fair values of accounts receivable approximate their carrying value due to their short periods to maturity.

Long-term accounts receivable are classified as loans and receivables. In the prior year the fair value of the long-term account receivable for gas revenue receivable from Petrobangla was determined to be nil. Although the Company has a valid claim to receive payment for gas delivered to Petrobangla and the Company will continue to pursue collection of the receivable, due to the continued uncertainty with respect to timing of resolution of the various claims raised (see notes 30(a) and (b)) against the Company, a provision has been recorded against the full amount of the receivable as at March 31, 2013.

Accounts payable and accrued liabilities, borrowings and convertible debentures are classified as other financial liabilities that are not held for trading. The fair values of accounts payable and accrued liabilities approximate their carrying values due to their short periods to maturity. The fair values of borrowings approximate their carrying values as they are the amounts owing. Interest and accretion expense for the convertible debentures of $15 million (2012 - $21 million) and for the convertible notes of $4 million (2012 - nil) was recognized in profit and loss during the year. The carrying value of the Company's convertible debentures and notes approximates the fair value.

c. Credit risk management

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Company's receivables from customers. The carrying amounts of the cash and cash equivalents, restricted cash, accounts receivable and the undiscounted amount of the long-term account receivable reflect management's assessment of the maximum credit exposure. The Company takes measures in order to mitigate any risk of loss, which may include obtaining guarantees. There were no changes in the Company's exposure to credit risks or any changes to the Company's processes for managing the risks from the previous period.

The aging of the accounts receivable as at March 31, 2013 was:

0-30 days	53,960
30-90 days ¹	2,503
90-365 days ¹	28,371
	84,834

¹	Accounts receivable are past due as at March 31, 2013, but not impaired.

The accounts receivable that are not past due are receivable from counterparties with whom the Company has a history of collection and the Company considers the accounts receivable collectible. The Company has assessed the receivables that have been outstanding for more than 90 days and has determined that they are not impaired.

d. Liquidity risk management

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company has future commitments as described in note 29 in addition to financial liabilities. The Company manages its exposure to this risk by preparing cash flow forecasts to assess whether additional funds are required.

The Company has the following financial liabilities and due dates as at March 31, 2013:

(thousands of U.S. dollars)	Carrying amount	< 1 year	> 1 year
Accounts payable and accrued liabilities	177,576	177,576	-
Capital lease obligations ⁽¹⁾	43,081	6,057	37,024
Repayment of notes payable⁽²⁾	79,785	-	79,785

(1)	The amount of lease payments is $10.8 million per year until August 2018. The above $43 million represents the carrying value of the liability.
(2)	The carrying amount of the notes payable is the fair value of $80 million. The amount that will be required to be repaid assuming that the debentures are not converted is Cdn$115 million ($113 million as at March 31, 2013).

e. Market risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and equity prices, will affect the Company's income or the value of its financial instruments. There were no changes in the Company's exposure to market risks or the Company's processes for managing the risks from the previous period.

(i) Currency risk

The majority of the Company's revenues and expenses are denominated in U.S. dollars and the Company holds the majority of its funds in U.S. dollars, except as required to fund dividends and make interest payments on the convertible notes. As a result, the Company has limited its cash exposure to fluctuations in the value of the U.S. dollar versus other currencies. However, the Company is exposed to changes in the value of the Indian rupee versus the U.S. dollar as they are applied to the Company's working capital, income tax receivable and deferred tax liability of its subsidiaries in India. The Company does not have any foreign exchange contracts in place to mitigate currency risk.

A 5 percent strengthening or a 5 percent weakening of the Indian rupee against the U.S. dollar at March 31, 2013, which is based on historical movements in the foreign exchange rates, would have respectively decreased or increased the net loss by $5 million. This analysis assumes that all other variables remained constant.

The financial instruments are exposed to fluctuations in foreign exchange rates, which are used in the translation of the financial statements of the Canadian and corporate operations to U.S. dollars. The reported U.S. dollar value of the cash and cash equivalents, accounts receivable, short-term investment and accounts payable of the Canadian and corporate operations is exposed to fluctuations in the value of the Canadian dollar versus the U.S. dollar. A 3 percent strengthening or a 3 percent weakening of the Canadian dollar against the U.S. dollar at March 31, 2013, which is based on historical movement in foreign exchange rates, would have respectively increased or decreased other comprehensive loss by $2 million. This analysis assumes that all other variables remained constant.

(ii) Commodity price risk

The Company is exposed to the risk of changes in market prices of commodities. The Company enters into natural gas contracts, which manages this risk. Because the Company has long-term fixed price gas contracts, a change in natural gas market prices would not have impacted the net loss for the period ended March 31, 2013. The Company is exposed to changes in the market price of oil and condensate. In addition, the Company will be exposed to the change in the Brent crude price as the average Brent crude price from the preceding year is a variable in the gas price for the following year, calculated annually, for the D6 gas contracts.

(iii) Other price risk

The Company has deposited the cash equivalents with reputable financial institutions, for which management believes the risk of loss to be remote.

19. Share capital

a. Fully paid ordinary shares

The Company has authorized for issue an unlimited number of common shares and an unlimited number of preferred shares. The common shares issued are fully paid and the shares have no par value. No preferred shares have been issued.

b. Share options granted under the employee share option plan

The Company has reserved for issue 7,021,591 common shares for granting under stock options to directors, officers, and employees. The options become vested immediately to five years after the date of grant and expire one to six years after the date of grant. The stock options are settled in equity.

Stock option transactions for the respective periods were as follows:

	Year ended March 31, 2013				Year ended March 31, 2012
	Number of options		Weighted average exercise price (Cdn$	)	Number of options		Weighted average exercise price (Cdn$	)
Opening balance	3,978,003		75.62		4,243,897		85.37
Granted	2,193,622		10.70		1,160,750		55.70
Forfeited	(282,481	)	76.12		(155,750	)	86.43
Cancelled	-		-		(587,500	)	102.13
Expired	(935,999	)	85.14		(568,450	)	80.97
Exercised	-		-		(114,944	)	58.01
Closing balance	4,953,145		45.04		3,978,003		75.62
Exercisable	1,029,945		68.20		952,624		85.19

The following table summarizes stock options outstanding and exercisable under the plan at March 31, 2013:

	Outstanding options					Exercisable options
Exercise price	Options	Remaining life (years	)	Weighted average exercise price (Cdn$	)	Options	Weighted average exercise price (Cdn$	)
7.65 - 9.99	1,927,992	2.1		8.73		-	-
10.00 - 19.99	125,588	3.7		13.48		-	-
20.00 - 39.99	85,250	3.0		36.91		-	-
40.00 - 49.99	1,009,941	1.7		47.46		569,945	63.71
50.00 - 59.99	240,125	2.9		51.94		2,250	52.92
60.00 - 69.99	200,125	2.2		63.24		43,500	63.35
70.00 - 79.99	65,500	1.8		73.33		6,750	76.87
80.00 - 89.99	302,375	1.5		83.26		33,500	82.14
90.00 - 99.99	693,500	1.3		96.42		347,875	96.64
100.00 - 109.99	278,499	2.2		103.56		21,750	105.03
110.00 - 112.64	24,250	1.6		111.10		4,375	111.30
	4,953,145	2.0		45.04		1,029,945	68.20

The weighted average share price during the year ended March 31, 2013 was $14.91 (2012 - $54.24).

c. Fair value measure of equity instruments granted

The fair value of each option granted was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average inputs:

(thousands of U.S. dollars)	Year ended March 31, 2013		Year ended March 31, 2012
Grant-date fair value	Cdn$3.92		Cdn$17.49
Market price per share	Cdn$10.64		Cdn$55.70
Exercise price per option	Cdn$10.70		Cdn$55.70
Expected volatility	71	%	42	%
Expected life (years)	2.2		3.5
Expected dividend rate	0.1	%	0.5	%
Risk-free interest rate	1.1	%	1.4	%
Expected forfeiture rate	8	%	6	%

Expected volatility was determined based on the historical movements in the closing price of the Company's stock for a length of time equal to the expected life of each option. See note 22 for categorization of share-based compensation expense during the period.

20. Revenue

(thousands of U.S. dollars)		Year ended March 31, 2013		Year ended March 31, 2012
Natural gas sales		190,513		286,077
Oil and condensate sales		45,690		76,707
Less:
	Royalties	(9,239	)	(15,470	)
	Government share of profit petroleum	(27,600	)	(26,003	)
Oil and natural gas revenue		199,364		321,311

Revenues from oil and gas sales to Petrobangla comprised 23 percent of natural gas, oil and condensate sales for the year ended March 31, 2013 (2012 - 16 percent).

21. Exploration and evaluation expenses

(thousands of U.S. dollars)	Year ended March 31, 2013	Year ended March 31, 2012
Geological and geophysical	34,078	114,811
Exploration and evaluation	95,192	71,319
General and administrative	15,552	15,817
Production sharing contract annual payments	10,509	10,805
New ventures	11,250	16,081
Share-based compensation	6,230	3,859
Exploration and evaluation expenses	172,811	232,692

22. Expense disclosure

The Company prepares its statement of comprehensive income (loss) classifying costs according to function as opposed to the nature of the costs.

Share-based compensation expense is charged to various other headings in the statement of comprehensive income (loss).

(thousands of U.S. dollars)		Year ended March 31, 2013	Year ended March 31, 2012
Share-based compensation expense included in:
	Exploration and evaluation assets	1,030	857
	Operating expense	1,255	1,555
	Exploration and evaluation expense	6,230	6,287
	Share-based compensation expense⁽¹⁾	10,894	35,516
Total		19,409	44,215

(1)	Share-based compensation expense includes $14 million with respect to the cancellation of options during the year ended March 31, 2012.

General and administrative expenses are charged to various other headings in the statement of comprehensive income (loss).

(thousands of U.S. dollars)		Year ended March 31, 2013	Year ended March 31, 2012
General and administrative expenses categorized as:
	Exploration and evaluation expense	15,552	11,673
	Production and operating expense	11,871	11,979
Total		27,423	23,652

23. Finance expense

(thousands of U.S. dollars)	Year ended March 31, 2013	Year ended March 31, 2012
Interest expense on financing lease obligation	5,172	5,952
Interest expense on credit facility borrowings	3,610	-
Interest expense on convertible debentures and notes payable	13,024	15,722
Accretion expense on convertible debentures and notes payable	5,769	5,336
Accretion expense on decommissioning obligations	2,908	2,276
Bank charges and other finance costs	3,285	5,464
Impairment of financial assets	-	23,106
Finance expense	33,768	57,856

24. Income taxes

(a) Income tax expense

The Company pays income tax in India for the Hazira, Surat and D6 Blocks. India's federal tax law contains a tax holiday deduction for seven years for profits from the commercial production of mineral oil. As a result of the tax holiday provision in India, the Company pays the greater of 42.04 percent of taxable income in India after a deduction for the tax holiday or a minimum alternate tax of 19.44 percent of Indian income. Indian income is calculated in accordance with Indian generally accepted accounting principles. See discussion of the application of the tax holiday provisions in contingency note 31(e).

The Company does not make payments to the Government of Bangladesh for Block 9 with respect to income tax.

The Company is subject to tax on income earned in the other jurisdictions in which it operates, however, the Company does not have significant oil and gas revenues in these jurisdictions. Income items taxed include interest income and capital gains. Income tax on these items was not significant during the period.

(thousands of U.S. dollars)	Year ended March 31, 2013		Year ended March 31, 2012
Current year	2,377		1,216
Adjustment for prior years	(2,666	)	4,704
Current tax expense	(289	)	5,920

Minimum alternate tax expense	-		9,105

Origination and reversal of temporary differences	47,234		(14,484	)
Recognition of previously unrecognized tax losses	675		(19,259	)
Recognition of equity portion in convertible notes payable	(7,475	)	-
Deferred income tax expense / (reduction)	40,434		(33,743	)

Total tax expense / (reduction)	40,145		(18,718	)

(b) Reconciliation of effective tax rate

(thousands of U.S. dollars)	Year ended March 31, 2013		Year ended March 31, 2012
(Loss) / Income for the year	(216,496	)	(322,628	)
Total tax recovery / (expense)	(40,143	)	18,717
(Loss) / Income excluding tax	(176,353	)	(341,345	)
Tax using the Company's domestic tax rate (25%)	(44,088	)	(89,176	)
Share-based compensation expensed	2,724		9,174
Income subject to tax holiday	(42,310	)	15,460
Income exempt from tax	7,332		12,681
Adjustment to foreign statutory tax rates	(20,090	)	(47,520)
Capital gains rate difference	376		234
Foreign tax credits	7,005		(6,894	)
Foreign exchange	-		-
Other non-deductible expenses	4,882		10,512
Difference between current and future income tax rates	78,195		1,590
Unrecognized deferred tax asset	42,738		70,754
Prior year adjustments	-		4,702
Other	3,381		-
Total tax expense / (reduction)	40,145		(18,717	)

Deferred tax assets have not been recognized in respect of the following temporary differences:

(thousands of U.S. dollars)	As at March 31, 2013	As at March 31, 2012
Deductible temporary differences	264,967	231,202
Capital tax losses	29,968	27,499
Non-capital tax losses	213,037	173,099
	507,972	431,800

The deductible temporary differences do not expire. Deferred tax assets have not been recognized in respect of these items because it is not probable that future taxable profit will be available against which the Company can utilize the benefits therefrom. The Canadian capital tax losses expire in fiscal 2029 ($2 million), fiscal 2030 ($1.3 million), fiscal 2031 ($13 million), fiscal 2032 ($14 million). The Canadian non-capital tax losses expire in fiscal 2029 ($1.2 million), fiscal 2030 ($13 million), fiscal 2031 ($34 million) and fiscal 2032 ($29 million). The remaining tax losses are in foreign countries and do not expire. The Company recognized $79 million of previously unrecognized tax losses in the year.

The Company has temporary differences associated with its investments in its foreign subsidiaries, branches and interests in joint ventures. At March 31, 2013, the Company has no deferred tax liabilities in respect of these temporary differences.

(d) Recognized deferred tax assets and liabilities

Deferred tax assets and liabilities are attributable to the following:

	Assets		Liabilities				Net
(thousands of U.S. dollars)	2013	2012	2013		2012		2013		2012
Exploration and evaluation assets	-	-	(181,092	)	(196,088	)	(181,092	)	(196,088	)
Property, plant and equipment	-	1,057	(24,119	)	(28,227	)	(24,119	)	(27,170	)
Decommissioning obligations	11,354	10,341			-		11,354		10,341
Capital lease obligation	12,766	17,885			-		12,766		17,885
Convertible debentures	-	-	(7,110	)	(1,057	)	(7,110	)	(1,057	)
Minimum alternate tax credit ⁽¹⁾	54,605	58,314	(78,195	)	-		(23,590	)	58,314
Unused losses	26,863	573			-		26,683		573
Tax assets / (liabilities)	105,408	88,170	(290,516	)	(225,372	)	(185,109	)	(137,201	)

The utilization of the minimum alternate tax credit is dependent on future taxable profits from the D6 Block. MAT paid can be carried forward for 10 years and deducted against regular income taxes in future years. As a result, the Company also recognizes the MAT tax as a deferred tax asset on the statement of financial position and a deferred income tax recovery in the statement of comprehensive income. Based on cashflow projections from the reserve report for the D6 Block, the Company expects to realize the benefit of the tax credit.

Movements in deferred tax balances during the year are as follows:

(thousands of U.S. dollars)	As at March 31, 2012		Recognized in profit or loss		Recognized in Equity		As at March 31, 2013
Exploration and evaluation assets	(196,087	)	14,996		-		(181,091	)
Property, plant and equipment	(27,170	)	3,051		-		(24,119	)
Decommissioning obligations	10,341		1,012		-		11,353
Capital lease obligation	17,885		(5,119	)	-		12,765
Convertible debentures	(1,057	)	1,421		(7,475	)	(7,110	)
Minimum alternate tax credit ⁽¹⁾	58,314		(81,904	)	-		(23,590	)
Unused losses	573		26,109		-		26,683
Tax assets / (liabilities)	(137,201	)	(40,434	)			(185,109	)

25. Earnings per share

The earnings used in the calculation of basic and diluted per share amounts are as follows:

(thousands of U.S. dollars)	Year ended March 31, 2013		Year ended March 31, 2012
Net loss	216,496		322,628

A reconciliation of the weighted average number of ordinary shares for the purpose of calculating basic earnings per share to the weighted average number of ordinary shares for the purpose of calculating diluted earnings per share is as follows:

(thousands of U.S. dollars)	Year ended March 31, 2013	Year ended March 31, 2012
Weighted average number of common shares used in the calculation of basic earnings per share	57,633,285	51,587,246
Shares deemed to be issued for no consideration in respect of employee options	-	-
Weighted average number of ordinary shares used in the calculation of diluted earnings per share	57,633,285	51,587,246

As a result of the net loss in the year ended March 31, 2013, the outstanding stock options of 4,953,145 and shares issuable upon conversion of the outstanding notes of 114,958 as at March 31, 2013 were considered anti-dilutive to the loss per share and were excluded from the weighted average number of common shares for the purposes of diluted earnings per share. The average market value of the Company's common shares for purposes of calculating the dilutive effect of stock options for the year ended March 31, 2012 was based on quoted market prices for the period that the options were outstanding. The number of shares issuable upon conversion of the outstanding convertible notes payable is based on the conversion price of Cdn$11.30 per common share. See note 14 for details of conversion of the convertible notes payable.

26. Segmented information

a. Products and services from which reportable segments derive their revenues

The Company's operations are conducted in one business sector, the oil and natural gas industry. All revenues are from external customers. All of Bangladesh sales are received from one customer and this customer accounted for 23 percent of sales during the year ended March 31, 2013.

b. Determination of reportable segments

Geographical areas are used to identify the Company's reportable segments. A geographic segment is considered a reportable segment once its activities are regularly reviewed by the Company's management. The accounting policies of the information of the reportable segments are the same as those described in the summary of significant accounting policies.

c. Segment assets and liabilities, revenues and results

(thousands of U.S. dollars)	Year ended March 31, 2013				Year ended March 31, 2012
	Additions to:
Segment	Exploration and evaluation assets (E&E	)	Property, plant and equipment (PP&E¹	)	Exploration and evaluation assets	Property, plant and equipment
Bangladesh	-		2,231		63	755
Brazil	-		90		-	-
India	723		7,952		2,432	23,144
Indonesia	133,980		11,021		16,676	-
Kurdistan	537		(184	)	24,795	-
Madagascar	-		-		9	-
Pakistan	-		-		248	-
Trinidad	39,002		11,041		120,753	6
All other	-		597		-	3,165
Total	174,242		32,748		164,976	27,070

¹	Excludes changes in capital work-in-progress.

(thousands of U.S. dollars)	As at March 31, 2013			As at March 31, 2012
Segment	Total E&E	Total PP&E	Total Assets	Total E&E	Total PP&E	Total Assets
Bangladesh	4,737	22,916	35,918	4,737	31,605	46,617
Brazil	-	67	661	-	-	-
India	86,997	492,073	653,584	136,104	454,421	730,134
Indonesia	497,579	12,741	577,311	510,161	-	534,923
Kurdistan	11,866	-	15,024	50,519	749	54,573
Madagascar	1,200	30	1,412	1,209	-	1,377
Pakistan	-	12	87	248	-	310
Trinidad	93,245	65,377	169,591	153,902	1,467	190,617
All other	-	951	40,219	-	20,849	59,936
Total	695,624	594,166	1,493,807	856,880	509,091	1,618,487


(thousands of U.S. dollars)				Year ended March 31, 2013
Segment	Natural gas, condensate and oil sales	Government share of profit petroleum		Royalty expense		Production and operating expense		Depletion and depreciation expense		Exploration and evaluation expense		Other income/(loss) on short-term investments		Share-based compensation		Reversal/(Asset impairment	)	General and administrative expense		Finance income	Finance expense		Income tax reduction / (expense	)	Segment profit (loss	)
Bangladesh	53,335	(18,049	)	-		(10,278	)	(12,441	)	(361	)	-		-		-		-		-	-		-		12,206
Brazil	-	-		-		-		-		(13,956	)	-		-		-		-		-	-		-		(13,956	)
India	182,442	(9,552	)	(9,255	)	(26,042	)	(131,480	)	(1,300	)	-		-		101,544		-		-	-		(82,282	)	24,075
Indonesia	-	-		-		-		(195	)	(92,206	)	311		-		(16,281	)	-		-	-		34,671		(73,700	)
Kurdistan	-	-		-		-		-		(1,851	)	-		-		(38,919	)	-		-	-		-		(40,770	)
Madagascar	-	-		-		-		(28	)	(1,258	)	-		-		-		-		-	-		-		(1,286	)
Pakistan	-	-		-		-		(6	)	(1,254	)	-		-		-		-		-	-		-		(1,260	)
Trinidad	-	-		-		-		(128	)	(58,445	)	-		-		(12,631	)	-		-	-		-		(71,204	)
Canada	427	-		16		(458	)	(972	)	(2,180	)	-		-		-		-		-	-		7,466		4,299
All other	-	-		-		-		-		-		(2,106	)	(10,894	)	-		(6,931	)	1,999	(36,968	)	-		(54,900	)
Total	236,204	(27,601	)	(9,239	)	(36,778	)	(145,250	)	(172,810	)	(1,795	)	(10,894	)	33,713		(6,931	)	1,999	(36,968	)	(40,154	)	(216,496	)

(thousands of U.S. dollars)				Year ended March 31, 2012
Segment	Natural gas, condensate and oil sales	Government share of profit petroleum		Royalty expense		Production and operating expense		Depletion and depreciation expense		Exploration and evaluation expense		Other income/(loss) on short-term investments		Share-based compensation		Asset impairment		General and administrative expense		Finance income	Finance expense		Income tax reduction / (expense	)	Segment profit (loss	)
Bangladesh	57,855	(19,589	)	-		(7,377	)	(13,055	)	(933	)	-		-		-		-		-	(22,996	)	-		(6,095	)
Brazil	-	-		-		-		-		-		-		-		-		-		-	-		-		-
India	304,512	(6,414	)	(15,456	)	(31,795	)	(130,514	)	(12,233	)	-		-		(133,578	)	-		-	-		(14,522	)	(40,000	)
Indonesia	-	-		-		-		(184	)	(61,717	)	6,440		-		-		-		-	-		9,319		(46,142	)
Kurdistan	-	-		-		-		(25	)	(40,455	)	-		-		-		-		-	-		-		(40,480	)
Madagascar	-	-		-		-		(27	)	(1,132	)	-		-		-		-		-	-		-		(1,159	)
Pakistan	-	-		-		-		(7	)	(1,978	)	-		-		-		-		-	-		-		(1,985	)
Trinidad	-	-		-		-		(85	)	(111,996	)	-		-		-		-		-	-		22,913		(89,168	)
Canada	417	-		(14	)	(291	)	(697	)	(1,315	)	-		-		-		-		-	-		1,007		(893	)
All other	-	-		-		-		(1	)	(1,666	)	(5,823	)	(35,516	)	-		(8,776	)	4,302	(49,226	)	-		(96,707	)
Total	362,784	(26,003	)	(15,470	)	(39,463	)	(144,595	)	(233,426	)	617		(35,516	)	(133,578	)	(8,776	)	4,302	(72,222	)	18,717		(322,629	)

27. Guarantees

(thousands of U.S. dollars)	As at March 31, 2013	As at March 31, 2012
Performance security guarantees included in restricted cash ¹
D4-India	331	1,474
Indonesia	7,660	9,857
Performance security guarantees not included in restricted cash ²
Indonesia	-	2,454
Total guarantees	7,991	13,785

¹	The Company is required to provide funds to support the guarantees in the amounts indicated above.
²	These performance security guarantees were not reflected on the balance sheet as they were supported by Export Development Canada. The performance security guarantee outstanding at March 31, 2012 expired on May 5, 2012.

The Company has performance security guarantees related to the capital commitments for exploration blocks. The guarantees are cancelled when the Company completes the work required under the exploration period.

28. Related-party transactions

(a) Oil and gas property

The Company has a 45 percent interest in a Canadian property that is operated by a related party, a Company owned by the President and CEO of Niko Resources Ltd. This joint interest originated as a result of the related party buying the interest of the third-party operator of the property in 2002. The transactions with the related party are measured at the exchange amount, which is the amount agreed to between the related parties. The Company records its share of revenues, royalty expense and production and operating expense as indicated in note 26(c) in the Canada segment.

(b) Key management personnel

Key management personnel of the Company include directors and executive officers. Non-management directors receive an annual fee and participate in the Company's stock option program. Executive officers (Chief Executive Officer, Chief Financial Officer and Chief Operating Officer) receive a salary, are eligible for an annual bonus and participate in the Company's stock option program. The Company does not have other short-term benefits, defined contribution plans or defined benefit plans and does not provide post-employment benefits.

Key management personnel compensation comprised the following:

(thousands of U.S. dollars)	Year ended March 31, 2013	Year ended March 31, 2012
Annual fee for non-management directors	150	95
Executive officers - salary	1,822	1,670
Executive officers - bonus	-	996
Share-based payments ¹	4,771	7,955
	6,743	10,716

¹	The value of share-based payments related to stock options granted during the year is estimated using the Black-Scholes option-pricing model. See note 18 for further details.

29. Commitments and contractual obligations

(a) Exploration commitments

The Company has minimum work commitments as specified in the PSCs for its exploration properties. The Company may apply for extensions to commitment deadline if it is unable to fulfill the commitment by the deadline or may relinquish the property. The estimated cost of the minimum work commitments is as follows:

Property	Estimated Spending (thousands of U.S. dollars	)	Exploration period
Indonesia	112,000		Various¹
Madagascar	10,000		September 2015
Trinidad and Tobago	167,000		Various²
Total	289,000

The deadlines for fulfilling the work commitments in Indonesia are: $59 million by November 2013; $39 million by May 2014; $11 million by November 2014; and $3 million by December 2014. The Company has applied or plans to apply for extensions to commitment deadlines if it is unable to fulfill the commitment by the deadline.
The deadlines for fulfilling the work commitments in Trinidad and Tobago are: $11 million by July 2013; $18 million by September 2013, $64 million by April 2014, $20 million by July 2014 and $54 million by April 2016.

(b) Finance lease obligation

Refer to note 15 for contractual obligations related to the finance lease.

The Company has a contract for a drilling rig for a four-year term, with an additional year at the option of the Company. The contract commenced on October 2, 2012 and based on the daily operating rate of $385,000 per day specified in the contract, the Company expects gross future minimum lease payments, before reimbursement from partners, to be as follows:

(thousands of U.S. dollars)	Lease payments
<1 year	141,000
1-5 years	351,000
> 5 years	Nil
Total	492,000

Under the terms of the contract, the Company has the right to assign the rig contract to third parties

30. Contingent liabilities

a. During the year ended March 31, 2006, a group of petitioners in Bangladesh (the petitioners) filed a writ with the High Court Division of the Supreme Court of Bangladesh (the High Court) against various parties including Niko Resources (Bangladesh) Ltd. (NRBL), a subsidiary of the Company.

In November 2009, the High Court ruled on the writ. Both the Company and the petitioners have the right to appeal the ruling to the Supreme Court. The ruling can be summarized as follows:

Petitioner request		High Court ruling
That the Joint Venture Agreement for the Feni and Chattak fields be declared null and illegal.		The Joint Venture Agreement for Feni and Chattak fields is valid.
That the government realize from the Company compensation for the natural gas lost as a result of the uncontrolled flow problems as well as for damage to the surrounding area.		The compensation claims should be decided by the lawsuit described in note (b) below or by mutual agreement.
That Petrobangla withhold future payments to the Company relating to production from the Feni field ($27.9 million as at December 31, 2012).		Petrobangla to withhold future payments to the Company related to production from the Feni field until the lawsuit described in note (b) below is resolved or both parties agree to a settlement.
That all bank accounts of the Company maintained in Bangladesh be frozen.		The ruling did not address this issue, therefore the previous ruling stands. Funds in the Company's bank accounts maintained in Bangladesh cannot be repatriated pending resolution of the lawsuit described in note (b) below.

On January 7, 2010, NRBL requested an arbitration proceeding with the International Centre for the Settlement of Investment disputes (ICSID). The arbitration is between NRBL and three respondents: The People's Republic of Bangladesh; Bangladesh Oil, Gas & Mineral Corporation (Petrobangla); and Bangladesh Petroleum Exploration & Production Company Limited (Bapex). The arbitration hearing will attempt to settle all compensation claims described in this note and note (b). ICSID registered the request on May 24, 2010.

In June 2010, the Company filed an additional proceeding with ICSID to resolve its claims for payment from Petrobangla in accordance with the Gas Purchase and Sale Agreement with Petrobangla to receive all amounts for previously delivered gas.

b. During the year ended March 31, 2006, Niko Resources (Bangladesh) Ltd. received a letter from Petrobangla demanding compensation related to the uncontrolled flow problems that occurred in the Chattak field in January and June 2005. Subsequent to March 31, 2008, Niko Resources (Bangladesh) Ltd. was named as a defendant in a lawsuit that was filed in Bangladesh by Petrobangla and the Republic of Bangladesh demanding compensation as follows:

taka 422,800,000 ($5.4 million) for 3 Bcf of free natural gas delivered from the Feni field as compensation for the burnt natural gas;
taka 826,900,000 ($10.6 million) for 5.89 Bcf of free natural gas delivered from the Feni field as compensation for the subsurface loss;
taka 845,600,000 ($10.9 million) for environmental damages, an amount subject to be increased upon further assessment;
taka 6,340,000,000 ($81.4 million) for 45 Bcf of natural gas as compensation for further subsurface loss; and
any other claims that arise from time to time.

ICSID has registered the request for arbitration of the issues indicated above as discussed in note 14(a). In addition, the Company will actively defend itself against the lawsuit, which may take an extended period of time to settle. Alternatively, the Company may attempt to receive a stay order on the lawsuit pending either a settlement and/or results of ICSID arbitration. The Company believes that the outcome of the lawsuit and/or ICSID arbitration and the associated cost to the Company, if any, are not determinable. As such, no amounts have been recorded in these consolidated financial statements. Settlement costs, if any, will be recorded in the period of determination.

c. In accordance with natural gas sales contracts to customers of production from the Hazira field in India, the Company had committed to deliver certain minimum quantities and was unable to deliver the minimum quantities for a period ending December 31, 2007. The Company's partner in the Hazira field delivered the shortfall volumes in return for either: (a) delivery of replacement volumes five times greater than the shortfall; (b) a cash payment; or (c) a combination of (a) and (b). The Company's partner has served a notice of arbitration as the Company is unable to supply gas from the D6 block to the partner and the arbitration process has commenced. The Company estimates the cash amount to settle the contingency at US$11.6 million. The Company believes that the agreement with its partner is not effective as the Government of India's gas utilization policy prevents the Company from supplying the gas to the partner. The Company believes that the outcome is not determinable.

The Company may not be able to supply gas to a customer in Hazira whose contract runs until mid-2016. The Company had previously planned to supply gas from the D6 Block to the customer. Due to a change in the gas allocation policy by the Government of India, the Company may not be able to fulfill the contract with gas supply from the D6 Block. The Company has notified the customer that the underperformance of reservoir is a force majeure event. The customer does not agree with this position and has served a notice of arbitration on the Company. The matter is sub judice in a court of law. The Company believes that the outcome is not determinable.

d. In a May 2012 letter, the GOI alleged that the joint venture partners in the D6 Block are in breach of the PSC for the D6 Block as they failed to drill all of the wells and attain production levels contemplated in the Addendum to the Initial Development Plan for the Dhirubhai 1 and 3 fields. The GOI has further asserted that joint venture costs totaling $1.462 billion (the Company's share totaling $146.2 million) are therefore disallowed for cost recovery. The joint venture partners are of the view that the disallowance of recovery of costs incurred by the joint venture has no basis in the terms of the PSC and that there are strong grounds to challenge the action of the GOI. Reliance Industries Ltd. (Reliance) has commenced arbitration proceedings against the GOI challenging the allegations and the disallowance of cost recovery on behalf of the partners. To the extent that any amount of joint venture costs are disallowed, such amount would be treated as profit petroleum in the future, a portion of which would be payable to the GOI under the PSC. Because profit petroleum percentages for the joint venture partners and the GOI change as the joint venture partners recover specified percentages of their investments, the potential impact on the Company's future profit petroleum expense (which represents the GOI's share of profit petroleum) is dependent on the future revenue and expenditures in the block and cannot be precisely determined at this time. The arbitral tribunal is in the process of being constituted with Reliance and the GOI having nominated two of the three arbitrators. The outcome of these proceedings is not determinable at March 31, 2013.

e. The Company has filed its income tax returns in India for the taxation years 1998 through 2008 under provisions that provide for a tax holiday deduction for eligible undertakings related to the Hazira and Surat fields.

The Company has received unfavorable tax assessments related to taxation years 1998 through 2008. The assessments contend that the Company is not eligible for the requested tax holiday because: a) the holiday only applies to "mineral oil" which excludes natural gas; and/or b) the Company has inappropriately defined undertakings. The taxation years 2009 and later have not yet been assessed by the tax authorities. The Company has appealed the tax assessments and has received favorable rulings at the second level of four possible levels of appeals, the Tribunal Court. This decision has been appealed by the Indian tax department to the third level of appeals, the High Court. The fourth level of appeals is the Supreme Court.

In August 2009, the Government of India through the Finance (No.2) Act 2009 amended the tax holiday provisions in the Income Tax Act (Act). The amended Act provides that the blocks licensed under the NELP-VIII round of bidding and starting commercial production on or after April 1, 2009 are eligible for the tax holiday on production of natural gas. However, the budget did not address the issue of whether the tax holiday is applicable to natural gas production from blocks that have been awarded under previous rounds of bidding, which includes all of the Company's Indian blocks. The Company has previously filed and recorded its income taxes on the basis that natural gas will be eligible for the tax holiday.

With respect to undertakings eligible for the tax holiday deduction, the Act was amended to include an "explanation" on how to determine undertakings. The Act now states that all blocks licensed under a single contract shall be treated as a single undertaking. The Company was granted an interim relief by the High Court on instructing the tax Department to not give effect to the "explanation" referred to above retrospectively until the matter is clarified in the courts.

The decision regarding retrospective application of the definition of undertaking and whether or not mineral oil includes natural gas for purposes of tax holiday claim is currently pending with the High Court.

Based on the circumstances described above, the Company continued to calculate its income tax provision in accordance with its earlier practice of treating a single well / cluster of wells as a single undertaking and considering the production of natural gas as eligible for the tax holiday claim. However, to avoid interest and penalties, the Company post amendment of the Income tax act has paid its income tax excluding the tax holiday deduction and has filed its income tax return without tax holiday deduction so as not deemed to be in violation of the current legislation.

Should the High Court overturn the rulings previously awarded in favour of the Company by the Tribunal court, and the Company either decides not to appeal to the Supreme Court or appeals to the Supreme Court and is unsuccessful, the Company would have to accordingly change its tax position and record a tax expense of approximately $59 million (comprised of additional taxes of $36 million and write off of approximately $23 million of the net income tax receivable). In addition, the Company could be obligated to pay interest on taxes for the past periods.

f. The Cauvery and D4 Blocks in India are under relinquishment. The Company believes it has fulfilled all commitments for the Cauvery block while the Government of India contends that the Company has unfulfilled commitments of up to approximately $2 million. The Company believes the outcome is currently not determinable.

g. Various lawsuits have been filed against the Company for incidents arising in the ordinary course of business. In the opinion of management, the outcome of the lawsuits, now pending, is not determinable or not material to the Company's operations. Should any loss result from the resolution of these claims, such loss will be charged to operations in the year of resolution.

Contact Information:
Niko Resources Ltd.
Edward S. Sampson
Chairman of the Board, President & CEO
(403) 262-1020

Niko Resources Ltd.
Glen Valk
VP Finance & CFO
(403) 262-1020
www.nikoresources.com

Marketwired (Canada)

July 9, 2013 - 12:57 AM EDT

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Niko Reports Results for the Year Ended March 31, 2013

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Niko Reports Results for the Year Ended March 31, 2013

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