CALGARY, ALBERTA--(Marketwire - Aug. 25, 2011) - Niko Resources Ltd. ("Niko" or "the Company") (TSX:NKO) 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 quarter ended June 30, 2011. The operating results are effective August 24, 2011. All amounts are in U.S. dollars unless otherwise indicated and all amounts are reported using International Financial Reporting Standards unless otherwise indicated.
FINANCIAL AND OPERATING HIGHLIGHTS
-- Natural gas production from the D6 Block averaged 170 MMcf/d compared to
the Company's F2012 forecast of 158 MMcf/d.
-- Mechanical problems at Block 9 resulted in natural gas production of 55
MMcf/d during the quarter compared to a F2012 forecast of 62 MMcf/d. Gas
production from Block 9 returned to 63 MMcf/d by mid-July.
-- Operating cash flow in the quarter was $79 million and in line with the
Company's forecast for fiscal 2012.
-- The Company adopted international financial reporting standards (IFRS).
Please see note 24 to the consolidated financial statements for a
detailed reconciliation of Canadian GAAP to IFRS.
-- Earnings for the quarter under IFRS were $2.9 million before the $57.9
million loss related to a change in accounting estimate with respect to
deferred income taxes as discussed in detail in "Segment Profit -
India - Income Taxes" in the Company's management's discussion and
analysis.
EXPLORATION HIGHLIGHTS
-- Indonesia: Planning for drilling activities commenced and Niko expects
to award a drilling contract late September 2011. In early August, Niko
received a prospective resource report for its Kofiau block. The report
shows a best estimate gross unrisked prospective resources of 787
million barrels of oil equivalent. To date, the Company has received
prospective resource reports on four of its sixteen blocks in Indonesia.
Total best estimate of gross unrisked prospective resources for the four
blocks is 4.6 billion barrels of oil equivalent. See more detailed
discussion below.
-- Trinidad: The Company increased its exploration acreage in Trinidad with
three new offshore blocks, all of which are in proximity to producing
gas fields, and entered into an agreement, which closed subsequent to
year-end, to acquire a 25 percent working interest in Block 5(c),
located 94 kilometres off the east coast of Trinidad. In addition,
drilling has now commenced on the Central Range Block.
-- Kurdistan: The Qara Dagh well has been drilled to a depth of 3,908
metres, log evaluated and flowed marginal volumes of light oil. The
Company intends to deepen the well to 4,150 metres. In August, the
Company increased its interest in the block from 37 percent to 49
percent for a total cost of $9 million. The transaction is subject to
approval by the Kurdistan Regional Government.
-- India: Development drilling on the D6 Block recommenced in July 2011.
REVIEW OF OPERATIONS AND GUIDANCE
Sales Volumes
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Three months ended June 30,
2010 2011 Forecast 2012
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Oil and condensate production (bbls/d) 2,959 2,020 1,500
Gas production (Mcf/d) 283,574 234,261 227,000
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Total production (Mcfe/d) 301,330 246,379 236,000
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Natural gas production at the D6 block was 170 MMcf/d during the quarter compared to 210 MMcf/d in the prior year's quarter. D6 gas production in July averaged approximately 164 MMcf/d. Declines are expected to continue until workovers are completed and/or additional wells are tied-in. Block 9 produced 55 MMcf/d of natural gas in the quarter compared to 57 MMcf/d in the prior year's quarter.
Operating Cash flow
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Three months ended June 30,
2010 2011 Forecast 2012
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Operating cash flow ($ millions) (1) 98 79 279
Operating netback ($/Mcfe) 3.56 3.53 3.24
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(1) Operating cash flow is defined as oil and natural gas revenues less
royalties, profit petroleum and the cash-portion of operating expense
and is a non-IFRS measure. Operating netback is the operating cash flow
per unit of production measured in Mcfe and is a non-IFRS measure.
While operating netback per Mcfe was virtually unchanged at $3.53 per Mcfe, operating cash flow decreased in the quarter as a result of the decreases in production described above.
Initial Resource Estimates
The Company has commissioned prospective resource estimates for the Southeast Ganal, North Makassar Strait, West Sageri and Kofiau Blocks located offshore Indonesia, which are provided below. Prospective resources are not reserves. Rather prospective resources are undiscovered resources that indicate exploration opportunities but nothing will be certain until wells are drilled. These estimates were prepared by Netherland Sewell Associates Inc. ("NSAI") as of December 31, 2010 for Southeast Ganal, North Makassar Strait and West Sageri and as of May 31, 2011 for Kofiau. Volume and geological risk estimates are as follows:
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Gross Unrisked Undiscovered In-Place Volumes - Within PSC (1)(2)(3)(9)(10)
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Oil - MMbbl (2) Free Gas - Bcf (2)
Prospects ----------------------------------------------------------------
Low Best High Low Best High
Estimate Estimate Estimate Estimate Estimate Estimate
(4) (5) (6) (4) (5) (6)
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Southeast Ganal 1,957 5,477 11,448 5,520 15,486 32,418
North Makassar
Straight 228 761 1,684 653 2,216 4,756
West Sageri 414 1,196 2,538 1,027 2,943 6,254
Kofiau 842 2,065 4,073 1,236 3,174 6,367
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Arithmetic Sum 3,441 9,499 19,743 8,436 23,819 49,795
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Gross Unrisked Undiscovered In-Place Volumes - Within PSC (1)(2)(3)(9)(10)
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Oil Equivalent (3) - MMboe
Prospects ----------------------------------------------------------------
Low Best High
Estimate Estimate Estimate
(4) (5) (6)
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Southeast Ganal 2,877 8,058 16,851
North Makassar
Straight 337 1,130 2,477
West Sageri 585 1,687 3,580
Kofiau 1,048 2,594 5,135
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Arithmetic Sum 4,847 13,469 28,043
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Gross Unrisked Prospective Resources - Within PSC (1)(2)(3)(9)(10)
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Oil - MMbbl (2) Condensate - MMbbl (2)
Prospects ----------------------------------------------------------------
Low Best High Low Best High
Estimate Estimate Estimate Estimate Estimate Estimate
(4) (5) (6) (4) (5) (6)
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Southeast Ganal 196 1,109 3,749 44 279 1,037
North Makassar
Straight 23 152 505 5 40 152
West Sageri 41 248 945 0 9 100
Kofiau 84 417 1,477 7 40 204
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Arithmetic Sum 344 1,926 6,676 56 368 1,493
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Gross Unrisked Prospective Resources - Within PSC (1)(2)(3)(9)(10)
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Separator Gas - Bcf (2) Oil Equivalent (3) - MMboe
Prospects ----------------------------------------------------------------
Low Best High Low Best High
Estimate Estimate Estimate Estimate Estimate Estimate
(4) (5) (6) (4) (5) (6)
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Southeast Ganal 2,164 9,013 24,897 600 2,890 8,935
North Makassar
Straight 256 1,290 3,653 71 407 1,266
West Sageri 410 1,757 4,903 110 549 1,862
Kofiau 574 1,971 4,890 186 787 2,495
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Arithmetic Sum 3,404 14,031 38,343 967 4,633 14,558
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PSC Risk Factors(7)(8)(Pg)
----------------------------------------
No. of Lowest Highest
Prospects Value(8) Value(8) Midpoint(8)
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Southeast Ganal 11 12% 15% 14%
North Makassar Strait 1 21% 21% 21%
West Sageri 5 16% 29% 23%
Kofiau 3 11% 20% 17%
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The independent assessment prepared by NSAI affirms management's estimates of the significant reserve potential on the first four Blocks. In upcoming months, the company intends to provide independent resource reports for its 12 other Blocks in Indonesia.
Notes:
1. These are the gross volumes estimated for the Blocks, without any
adjustments for working interests or encumbrances. Niko holds a 100%
interest in the Southeast Ganal, West Sageri and Kofiau Blocks and a 30%
interest in the North Makassar Strait Block. A Production Sharing
Contract (PSC) between Niko and the Indonesian Government executed for
each Block gives Niko the right to explore for hydrocarbons. If a
commercial discovery is made, Niko has the right to develop and produce
from the Block containing the discovery.
2. There is uncertainty about the hydrocarbon phase that might be
encountered in the prospects within the three PSCs. If a discovery is
made, the volumes could consist entirely of gas or of oil or any
combination of gas and oil. Volume calculations made by NSAI were based
on a 50 percent probability that each prospect in the PSCs contains oil
in the reservoir and a 50 percent probability that the prospect contains
free gas in the reservoir. Thus, to determine volume ranges on Niko's
PSCs in the case of a gas "only" discovery, NSAI's gas and condensate
volume estimates should be multiplied by two and no oil volume included
to estimate 100 percent gas in-place volumes or prospective resources.
The opposite should be done in the case of an oil "only" discovery on
Niko's PSCs, NSAI's oil volume estimate should be multiplied by two and
no gas or condensate volumes should be included for the 100 percent oil
case. Separator Gas includes the effect of shrinkage resulting from
condensate dropout at surface temperature and pressure.
3. Conversion of gas volume to liquid volume was six to one, or 6 Mcf = 1
boe, based on standard British Thermal Unit (BTU) heating values of gas
and oil.
4. There is a 90-percent chance that the Low Estimate for petroleum
initially in-place or prospective resources will be equalled or
exceeded.
5. There is a 50-percent chance that the Best Estimate for petroleum
initially in-place or prospective resources will be greater or less than
the best estimate.
6. There is a 10-percent chance that the High Estimate for petroleum
initially in-place or prospective resources will be equalled or
exceeded.
7. Risk Factor (Pg) means the geological chance or probability of
discovering hydrocarbons in sufficient quantity for them to be tested to
surface.
8. NSAI assessed Pg for each prospect identified within each PSC. The
Lowest Value means the lowest Pg value assigned to a prospect within the
PSC by NSAI. The Highest Value means the highest Pg value assigned to a
prospect within the PSC by NSAI. The Midpoint was calculated and posted
in the table by Niko and is the mean of Lowest and Highest estimates.
The Midpoint does not represent the average chance of discovering
hydrocarbons within the PSC.
9. The above quantities have not been adjusted for geological risk (chance
of discovery).
10. The resource estimates were prepared in accordance NI 51-101 and the
COGE Handbook.
Prospective resources are those resources of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. The chance of commerciality is the product of these two risk components. There is no certainty that any portion of the prospective resources will be discovered. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing of such development or that it will be commercially viable to produce any portion of the prospective resources.
Prospective oil and gas resources are undiscovered resources that indicate exploration opportunities and development potential in the event a commercial discovery is made and should not be construed as reserves or contingent (discovered) resources.
Forward-Looking Information and Material Assumptions
This report on results for the quarter ended June 30, 2011 contains forward-looking information including forward-looking information about Niko's operations, reserve estimates, production and capital spending.
Forward-looking information is generally signified by words such as "forecast", "projected", "expect", "anticipate", believe", "will", "should" and similar expressions. This forward-looking information is based on assumptions that the Company believes were reasonable at the time such information was prepared, but assurance cannot be given that these assumptions will prove to be correct, and the forward-looking information in this report on results for the quarter ended June 30, 2011 should not be unduly relied upon. The forward-looking information and the Company's assumptions are subject to uncertainties and risks and are based on a number of assumptions made by the Company, any of which may prove to be incorrect.
The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis and updates reserve estimates on an annual basis. Refer to "Risk Factors" contained in the Company's management's discussion and analysis for discussion of uncertainties and risks that may cause actual events to differ from forward-looking information provided in this report on results for the quarter ended June 30, 2011.
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 quarter ended June 30, 2011 should be read in conjunction with the audited consolidated financial statements for the year ended March 31, 2011. This MD&A is effective August 24, 2011. 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 April 1, 2011 through June 30, 2011. The term "prior year's quarter" is used throughout the MD&A for comparative purposes and refers to the period from April 1, 2010 through June 30, 2010.
The fiscal year for the Company is the 12-month period ended March 31. The terms "Fiscal 2011" and "prior year" is used throughout this MD&A and in all cases refers to the period from April 1, 2010 through March 31, 2011. The terms "Fiscal 2012", "current year" and "the year" are used throughout the MD&A and in all cases refer to the period from April 1, 2011 through March 31, 2012.
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. An 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.
Less than 2 percent of total corporate production volumes and total corporate revenue are from Canadian oil and Bangladeshi condensate. Therefore, the results from Canadian oil and Bangladeshi condensate production are not discussed separately.
Forward-Looking Information and Material Assumptions
This MD&A contains forward-looking information including forward-looking information about Niko's operations, reserve estimates, production and capital spending. Forward-looking information is generally signified by words such as "forecast", "projected", "expect", "anticipate", believe", "will", "should" and similar expressions. This forward-looking information is based on assumptions that the Company believes were reasonable at the time such information was prepared, but assurance cannot be given that these assumptions will prove to be correct, and the forward-looking information in this MD&A should not be unduly relied upon. The forward-looking information and the Company's assumptions are subject to uncertainties and risks and are based on a number of assumptions made by the Company, any of which may prove to be incorrect.
Forward-looking information in this MD&A includes, but is not necessarily limited to, the following:
Forecast production rates: 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 the Company's reserve reports.
Forecast capital spending and commitments: 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.
Forecast operating expenses: 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.
Timing of production increases, timing of commencement of production and timing of capital spending: The Company discloses the nature and timing of expected future events based on the Company's 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 the Company's joint venture partners.
The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis and updates reserve estimates on an annual basis. Refer to "Risk Factors" contained in this MD&A for discussion of uncertainties and risks that may cause actual events to differ from forward-looking information provided in this MD&A.
Non-IFRS Measures
The selected financial information presented throughout the MD&A is prepared in accordance with International Financial Reporting Standards (IFRS), except for "funds from operations", "operating netback", "funds from operations netback", "earnings netback" and "segment profit", which are used by the Company to analyze the results of operations.
By examining funds from operations, the Company is able to assess its 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 and the change in long-term accounts receivable.
By examining operating netback, funds from operations netback, earnings netback and segment profit, the Company is able to evaluate past performance by segment and overall. Operating netback is calculated as oil and natural gas revenues less royalties, profit petroleum expenses 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, profit petroleum expenses, production and operating expenses, depletion expense, exploration and evaluation expense, production sharing contract costs 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
International Financial Reporting Standards
For fiscal periods beginning on or after January 1, 2011, all Canadian publicly accountable enterprises are required to prepare their financial statements using International Financial Reporting Standards (IFRS). Accordingly, the Company has prepared its unaudited consolidated financial statements for the first quarter, the three months ended June 30, 2011, under IFRS and has presented its unaudited consolidated financial statements for the comparative period, the three months ended June 30, 2010 to comply with IFRS. The financial information presented in this MD&A is derived directly from the Company's financial statements and as such certain comparative information may differ from what was originally prepared by the Company using previous Canadian generally accepted accounting principles. For further information on the Company's transition to IFRS and a reconciliation of the affected financial information for the three months ended June 30, 2010, please refer to the Company's unaudited consolidated financial statements for the three months ended June 30, 2011 and 2010 filed on SEDAR at www.sedar.com and available on the Company's website at www.nikoresources.com.
Funds from Operations
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Three months ended June 30,
(thousands of U.S. dollars) 2011 2010
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Oil and natural gas revenue 88,278 104,688
Production and operating expenses (9,031) (6,961)
General and administrative expenses (2,158) (1,739)
Net finance expense (5,950) (6,133)
Current income tax expense (10,987) (11,644)
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Funds from operations (1) 60,152 78,211
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(1) Funds from operations is a non-IFRS measure as defined under "Non-IFRS
measures" in this MD&A.
Oil and natural gas revenue has decreased compared to the prior year's quarter as a result of a decrease in gas production at the D6 Block and at Block 9.
Production and operating expenses increased at the D6 Block related to maintenance of the onshore terminal and subsea systems.
General and administrative expense and net finance expense in the quarter were comparable to the prior year's quarter.
Decreased earnings before tax resulted in lower cash taxes in the current quarter.
Net (Loss) Income
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Three months ended June 30,
(thousands of U.S. dollars) 2011 2010
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Funds from operations (non-IFRS measure) 60,152 78,211
Production and operating expense (524) (493)
Depletion expense (30,294) (25,520)
Exploration and evaluation expense (14,153) (32,839)
Gain (loss) on short-term investments 1,215 (7,826)
Other expenses (7,015) (6,271)
Net finance expense (1,712) (1,863)
Deferred income tax (expense) recovery (4,787) 10,673
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2,882 14,072
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Change in accounting
estimate - deferred taxes (57,865) -
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Net (loss) income (54,983) 14,072
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The decrease in funds from operations contributed to the increased net loss. Other items affecting the net loss are described below.
The non-cash portion of production and operating expense and other expense included above are largely for share-based compensation (refer to notes 16 and 18 to the consolidated financial statements for further details). The increase in share-based compensation expense in the year is primarily a result of the increased number of stock options being expensed.
Depletion expense increased as a result of the revision to the reserve volumes and future costs included in the March 31, 2011 reserve report.
In the prior year's quarter, exploration and evaluation costs included the seismic programs in Indonesia and Madagascar and the costs of running the branch offices. In the current quarter, exploration and evaluation costs include geological studies, seismic processing, the costs of running the branch offices and evaluation of new venture opportunities. Exploration and evaluation costs also include payments specified in the Pakistan and Trinidad PSAs and PSCs, respectively.
The gain or loss on short-term investments also contributed to quarter-over-quarter variances.
The non-cash portion of net finance expense included above is for the accretion of the decommissioning obligations, accretion of the convertible debentures (refer to note 19 to the consolidated financial statements for further details) and unrealized foreign exchange.
The deferred income tax recovery in the prior year's quarter consists of a tax credit available for future years related to the minimum alternative tax paid for the D6 Block. In the current quarter, the recovery was more than offset by a deferred income tax expense. Refer to Segment Profit - India - Income Taxes in this MD&A for further details.
The change in accounting estimate is related to deferred income taxes as a result of revising method of estimating the amount of taxable temporary differences reversing during the tax holiday period. Although the Company does not expect a change of this magnitude to occur in the future, there may be future changes in this estimate as the circumstances and facts surrounding this estimate change.
BACKGROUND ON PROPERTIES
Niko Resources Ltd. is engaged in the exploration for and, where successful, the development and production of natural gas and oil in India, Bangladesh, Indonesia, the Kurdistan region of Iraq, Trinidad, Pakistan and Madagascar. The Company has agreements with the governments of these countries for rights to explore for and, if successful, produce natural gas and oil. The Company generally is granted an exploration licence to commence work. The agreements generally involve a number of exploration phases with specified minimum work commitments and the maximum number of years to complete the work. At the end of any exploration phase, the Company has the option of continuing to the next exploration phase and may be required to relinquish a portion of the non-development acreage to the respective government. If a commercial discovery is not made by the end of all the exploration phases, the Company's rights to explore the block generally terminate. In the event of a discovery that is determined to be commercial, the Company prepares a development plan and applies to the government for a petroleum mining licence. The petroleum mining licences are for a specified number of years and may be extended under certain circumstances. During the production phase, the Company is required to pay any royalties specified in the agreements and taxes applicable in the country or as specified in the production sharing contract (PSC). Where the Company is currently producing, the Company pays to the government an increasing share of the profits based on an Investment Multiple (IM) or on production levels plus an IM, or a fixed share of profits, depending on the agreement. The IM is the number of times the Company has recovered its investment in the property from its share of profits from the property. At the end of the life of the field or the mining licence, the field and the assets revert to the government; however, the Company is responsible for the costs of abandonment and restoration.
India
Cauvery - The Company has a 100 percent working interest and operates the block, which covers 957 square kilometres. The Company has performed the seismic work and drilled four of the five wells required under the first exploration phase. The estimated cost of the remaining work commitment is $2 million. Wells drilled to date have been unsuccessful. The Company intends to relinquish the block.
D4 - The Company has a 15 percent interest in the D4 Block, located in the Mahanadi Basin offshore from the east coast of India. The block, which is currently in the exploration phase, encompasses more than 17,000 square kilometres. The commitment for Phase I exploration includes seismic work and three exploration wells. Originally, the work commitment was to be completed by September 2009; however, the Government of India approved a blanket extension to December 31, 2010 for this and other deep-water blocks. This and other extensions allow the Company until June of 2013 to drill the three wells. The Company's share of the estimated cost of the remaining work commitment is $10 million.
D6 - The Company has a 10 percent working interest in the 7,645-square-kilometre D6 Block. The D6 Block comprised 85 percent of the Company's oil and gas revenue during the quarter. Production from the MA discovery began in September 2008 and from the Dhirubhai 1 and 3 discoveries in April 2009. The Company has been granted petroleum mining licences for the discoveries expiring in 2028 and 2025, respectively. Oil production is sold on the spot market at a price based on Bonny Light and adjusted for quality. Gas production is sold under long-term gas contracts using a pricing formula approved by the Government of India, which currently results in a price of $4.20/MMBtu net and there is a marketing margin of $0.135/MMBtu earned in addition to the price formula. This equates to a sales price of approximately $3.95/Mcf.
Under the terms of the production sharing contract (PSC) with the Government of India for the D6 block, the Company is required to pay the government a royalty of 5 percent of the well-head value of crude oil and natural gas for the first seven years from the commencement of commercial production in the field and thereafter to pay 10 percent.
In addition, the Company pays a percentage of the profits from the block to the government, which varies with the Investment Multiple (IM). The Company pays 10 percent of profits when the IM is less than 1.5; 16 percent between 1.5 and 2; 28 percent between 2 and 2.5; and 85 percent thereafter. As at June 30, 2011, the profit share was 10 percent.
Hazira - The Company has a 33 percent working interest in the 50-square-kilometre Hazira onshore and offshore block on the west coast of India. The Hazira Block comprised four percent of the Company's oil and gas revenues in the quarter.
The Company has a petroleum mining licence that expires in September 2014, which can be extended. The Company has one significant contract for the sale of gas production from the field expiring in April 2016 at a current price of $4.86/Mcf.
NEC-25 - The Company has a 10 percent working interest in the NEC-25 Block, which covers 9,461 square kilometres in the Mahanadi Basin off the east coast of India. The Company has fulfilled its capital commitments for the block.
Surat - The Company holds a development area of 24 square kilometres containing the Bheema and NSA shallow natural gas fields. The block comprised one percent of the Company's oil and gas revenue in the quarter. The Company has one contract for the sale of gas production at a price of $6.00/ Mcf until March 31, 2013.
Bangladesh
Block 9 - The Company holds a 60 percent interest in this 6,880-square-kilometre onshore block that encompasses the capital city of Dhaka. Natural gas and condensate production from this field began in May 2006 and comprised 10 percent of the Company's oil and gas revenues for the quarter. As per the PSC, the Company has rights to produce for a period of 25 years and this arrangement is extendable if production continues beyond this period. The Company sells gas under a gas purchase and sales agreement (GPSA) at a current price of $2.34/MMBtu (approximately $2.33/Mcf) for a period up to 25 years. The Company shares a percentage of the profits from the block with the government, which varies with production and whether or not the Company has recovered its investment. The Company pays to the government 61 percent and 66 percent of profits, respectively, before and after costs are recovered on natural gas production up to 150 MMcf/d. Profits on natural gas are calculated as the minimum of (i) 55 percent of revenue for the period and (ii) revenue less operating and capital costs incurred to date. As at June 30, 2011, the profit share was 61 percent.
Indonesia
The Company holds interests in PSCs for 16 offshore exploration blocks covering 79,739 square kilometres. The chart below indicates the location, award date, the Company's working interest and the size of the block.
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Area
Offshore Working (Square
Block Name Area Award Date Interest Kilometres)
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Bone Bay Sulawesi SW Nov. 2008 45% 4,969
South East Ganal (1) Makassar Nov. 2008 100% 4,868
Strait
Seram (1) Seram North Nov. 2008 55% 4,991
South Matindok (1) Sulawesi NE Nov. 2008 100% 5,182
West Sageri (1) Makassar Nov. 2008 100% 4,977
Strait
Cendrawasih Papua NW May 2009 45% 4,991
Kofiau (1) West Papua May 2009 100% 5,000
Kumawa Papua SW May 2009 45% 5,004
East Bula (1) Seram NE Nov. 2009 55% 6,029
Halmahera-Kofiau (1) Papua W Nov. 2009 48% 4,926
North Makasar (1) Makassar Nov. 2009 30% 1,787
Strait
West Papua IV (1) Papua SW Nov. 2009 48% 6,389
Cendrawasih Bay II Papua NW May 2010 50% 5,073
Cendrawasih Bay III (1) Papua NW May 2010 50% 4,689
Cendrawasih Bay IV (1) Papua NW May 2010 50% 3,904
Sunda Strait I (1) Sunda Strait May 2010 100% 6,960
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(1) Operated by the Company.
All of the blocks are in the first exploration period, which is a three-year period. The seismic commitments have been met and 10 of the blocks have a single well commitment. The Company has estimated the costs associated with the remaining work commitments to complete the first exploration period. These costs are estimated to be $148 million to be spent by November 2011; an additional $54 million by May 2012; an additional $6 million by November 2012; and an additional $46 million by May 2013. The Company has applied or plans to apply for extensions where drilling activity is planned. The Company expects to be granted approval from the Government of Indonesia before the PSC three-year anniversary. The Company is required to relinquish a portion of the exploration acreage after the first exploration period. The drilling program for the Company's operated blocks could commence early 2012.
Kurdistan
The Company has a 37 percent interest and carries the proportionate cost for the regional government's interest, resulting in a 46 percent cost interest in the onshore Qara Dagh block. In August, the Company increased its interest in the block from 37 percent to 49 percent for a total cost of $9 million. The transaction is subject to approval by the Kurdistan Regional Government. The block covers approximately 846 square kilometres, in the Sulaymaniyah Governorate of the Federal Region of Kurdistan in Iraq. The exploration period is for a term of five years and is extendable by two one-year terms. An exploratory well was drilled between May 2010 and May 2011, log and test evaluated and the Company plans to deepen the well. The Company's share of the estimated remaining costs for the exploration period is $31 million.
Trinidad
The Company holds interests in nine PSCs for seven exploration areas. The chart below indicates the location, PSC date, the Company's working interest and the size of the block.
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Working Area (Square
Exploration Area Location PSC Date Interest Kilometres)
----------------------------------------------------------------------------
Block 2AB (1) Offshore July 2009 35.75% 1,605
Guayaguayare -
Shallow Horizon (1) Onshore/Offshore July 2009 65% 1,134
Guayaguayare - Deep
Horizon (1) Onshore/Offshore July 2009 80% 1,190
Central Range -
Shallow Horizon Onshore Sept. 2008 32.5% 734
Central Range - Deep
Horizon Onshore Sept. 2008 40% 856
Block 4(b) (1) Offshore April 2011 100% 754
NCMA2(1) Offshore April 2011 56% 1,020
NCMA3(1) Offshore April 2011 80% 2,107
Block 5(c) Offshore July 2005 25% 324
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(1) Operated by the Company.
The Company has minimum work commitments for the acquisition or reprocessing of seismic for all of the blocks and to drill a total of 14 wells on the blocks. The estimated cost to complete these commitments is: $24 million to be spent by July 2012; an additional $46 million by September 2012; and additional $14 million by July 2013; an additional $60 million by April 2014; and an additional $44 million by April 2016.
The Company closed the acquisition of Block 5(c) in June 2011 for a purchase price of $78.1 million. Block 5(c) is located 94 kilometres off the east coast of Trinidad. The transfer of the Block MG license, which was also part of an agreement signed by the Company in December 2010 has not been completed and is subject to the satisfaction of certain conditions.
Madagascar
The Company has a 75 percent working interest in a PSC for a 16,845-square-kilometre block off the west coast of Madagascar with water depths ranging from shallow water to 1,500 metres. The Company completed a 31,944-line kilometre aero-magnetic survey and a 10,000 square kilometre multi-beam survey. A 3,236-square-kilometre 3D survey was completed in July 2010. The 3D seismic will fulfill the Phase II work commitment. The cost of the Phase III work commitment is estimated at $40 million and includes drilling a well. A well location is expected to be selected after seismic interpretation.
Pakistan
The Company has production sharing agreements (PSAs) for four blocks in Pakistan. The blocks are located in the Arabian Sea offshore the city of Karachi and cover a combined area of almost 10,000 square kilometres. Each agreement is for a three-Phase exploration period that ends March 2013 and a further renewal of two years in the event of commercial production. Phase II of the exploration period ends March 2012 and the Company has substantially completed the commitments under this phase through seismic activity. The Company has evaluated the seismic, has selected drilling locations and plans to target drilling in late 2012.
Expenditures
----------------------------------------------------------------------------
Three months ended June 30, 2011
----------------------------------------------------------------------------
Additions to Additions to
exploration property, Expensed to
(thousands of U.S. and evaluation plant and profit and Total
dollars) assets equipment loss expenditures
----------------------------------------------------------------------------
Exploration
India 885 - 457 1,342
Indonesia 3,067 - 6,093 9,160
Kurdistan 6,133 37 918 7,088
Madagascar - - 257 257
Pakistan - - 206 206
Trinidad 96,843 666 5,400 102,909
Development
India - 2,588 - 2,588
Bangladesh - 279 259 538
Other
New ventures and
other - 214 563 777
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Total 106,928 3,784 14,153 124,865
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(1) The amounts presented are the Company's share of expenditures.
Expenditures include allocated share-based compensation expense,
capitalized general and administrative expenses and decommissioning
obligations.
Additions to exploration and evaluation assets in Indonesia were related to activities preparing for the upcoming drilling campaign. The spending expensed to the profit and loss included geological studies and evaluation of new venture opportunities.
Spending in Kurdistan relates to drilling and testing the Company's first well on the Qara Dagh block. The well has been drilled to a depth of 3,908 metres, log evaluated and flowed marginal light oil in multiple zones between 3,200 and total depth. The Company plans to deepen the well to target the main prospective zones within the Cretaceous.
The Company signed production sharing contracts for three additional blocks in Trinidad in April 2011 and paid the required signing bonuses of $18 million. In June 2011, the Company's purchase of Block 5(c) closed for a total purchase price of $79 million. Payments required as per the production sharing contracts and the costs of operating the branch office in Trinidad are expensed to profit and loss.
SEGMENT PROFIT
INDIA
----------------------------------------------------------------------------
Three months ended June 30,
(thousands of U.S. dollars) 2011 2010
----------------------------------------------------------------------------
Natural gas revenue 66,813 83,463
Oil and condensate revenue (1) 18,769 19,348
Royalties (4,405) (5,200)
Profit petroleum (1,923) (2,050)
Production and operating expenses (7,453) (5,399)
Depletion expense (27,508) (23,024)
Exploration and evaluation costs (457) (514)
Current income tax expense (10,994) (11,633)
Deferred income tax expense (4,787) 10,672
Change in accounting
Estimate - deferred taxes (57,865) -
----------------------------------------------------------------------------
Segment profit (2) (29,810) 65,663
----------------------------------------------------------------------------
Daily natural gas sales (Mcf/d) 178,992 225,599
Daily oil and condensate sales (bbls/d) (1) 1,819 2,755
Operating costs ($/Mcfe) 0.43 0.24
Depletion rate ($/Mcfe) 1.59 1.04
----------------------------------------------------------------------------
(1) Production that is in inventory has not been included in the revenue or
cost amounts indicated.
(2) Segment profit is a non-IFRS measure as calculated above.
Segment profit from India includes the results from the Dhirubhai 1 and 3 gas fields and the MA oil field in the D6 Block, the Hazira oil and gas field and the Surat gas field.
Revenue and Royalties
The Company's gas production for the year from the D6 block averaged 170 MMcf/d compared to 210 MMcf/d in the prior year's quarter. Production from the D6 block is expected to decline until workovers are completed and/or additional wells are tied-in. In addition, natural declines are continuing at the Hazira and Surat blocks.
Oil and condensate sales decreased to average 1,819 in the current quarter. Oil production from the D6 Block decreased as five wells were producing in the quarter compared to six wells for the majority of the prior year's quarter and a decrease in production from the remaining wells. The decrease as a result of volumes was partially offset by an increase in realized oil price to $113/bbl in the quarter compared to $77/bbl in the prior year's quarter.
The decrease in royalties is a result of the decreased revenues described above. Royalties applicable to production from the D6 Block are 5 percent for the first seven years of commercial production and gas royalties applicable to the Hazira and Surat fields are currently 10 percent of the sales price.
Profit Petroleum
Pursuant to the terms of the 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. The decrease in profit petroleum is a result of the decreased revenues described above.
For the D6 Block, the Company is able to use up to 90 percent of profits to recover costs. The government was entitled to 10 percent of the profits not used to recover costs during the year. Profit petroleum during the quarter was $0.8 million, which is one percent of revenues, and will continue at this level until the Company has recovered its costs.
The government was entitled to 25 percent and 20 percent of the profits from Hazira and Surat, respectively.
Operating Expenses
Operating expenses increased during the quarter compared to the prior year's quarter on absolute and unit-of-production bases. Production and operating expenses increased at the D6 Block related to maintenance of the onshore terminal and subsea systems and increased on a unit-of-production basis as these costs are primarily fixed.
Depletion, Depreciation and Accretion
Depletion expense and the depletion rate increased as a result of the revision to the reserve volumes and future costs included in the March 31, 2011 reserve report.
Income Taxes
The Company pays minimum alternative tax on the accounting profits from the D6 Block. The decrease in current income tax expense is primarily a result of the decreased revenues and increased depletion expense as described above.
Deferred income tax liability is calculated by first determining the difference between book value of assets and liabilities in the financial statements and the remaining tax basis ("temporary differences"). To estimate the deferred tax liability, temporary differences are multiplied by the anticipated tax rate during the period in which the difference is expected to reverse. For the quarter ended June 30, 2010, it was anticipated that the temporary differences would largely reverse during the tax holiday period when the tax rate would be nil resulting in no deferred tax liability for the D6 Block in India.
The change in accounting estimate is related to deferred income taxes as a result of revising the method of estimating the amount of taxable temporary differences reversing during the tax holiday period. Although the Company does not expect a change of this magnitude to occur in the future, there may be future changes in this estimate as the circumstances and facts surrounding this estimate change.
For the quarter ended June 30, 2011, the Company is recognizing a deferred income tax expense related to forecast drilling costs that will be capitalized for accounting and claimed as a deduction for income taxes creating a taxable temporary difference.
Contingencies
The Company has contingencies related to gas sales contracts, the profit petroleum calculation and ownership of the 36" pipeline for Hazira and related to income taxes for Hazira and Surat as at June 30, 2011. Refer to the consolidated financial statements and notes for the quarter ended June 30, 2011 for a complete discussion of the contingencies.
BANGLADESH
----------------------------------------------------------------------------
Three months ended June 30,
(thousands of U.S. dollars) 2011 2010
----------------------------------------------------------------------------
Natural gas revenue 11,617 12,206
Condensate revenue 1,960 1,271
Profit petroleum (4,598) (4,544)
Operating expenses (2,096) (2,034)
Exploration and evaluation costs (259) (180)
Depletion (2,786) (2,496)
Current income tax expense - (6)
----------------------------------------------------------------------------
Segment profit (1) 3,838 4,217
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Daily natural gas sales (Mcf/d) 55,269 57,975
Daily condensate sales (Bbls/d) 182 175
Operating costs ($/Mcfe) 0.41 0.38
Depletion rate ($/Mcfe) 0.54 0.46
----------------------------------------------------------------------------
(1) Segment profit is a non-IFRS measure as calculated above. Segment
profit includes the results from Block 9 and Feni in Bangladesh.
Production from Feni ceased in April 2010.
Revenue, Profit Petroleum, Depletion and Operating Expenses
Block 9 experienced technical problems during the quarter and the Company's share of gas production from the field decreased to 55 MMcf/d compared to 57 MMcf/d in the prior year's quarter. Production from the block was brought up to 63 MMcf/d in mid-July and is continuing at this level. The decrease in production is the cause of the revenue decline as the gas price was consistent quarter-over-quarter at $2.32/Mcf.
There was an increase in condensate production and price, both of which contributed to the increase in revenues year-over-year. Recovery of condensate from gas production increased as a result of the installation of the dew-point control unit since the prior year's quarter.
Pursuant to the terms of the PSC for Block 9, the Government of Bangladesh was entitled to 61 percent of profit gas in the year and prior year. Overall, profit petroleum expense increased due to increased revenues from Block 9.
Depletion expense increased on a unit-of-production basis as a result of the change in estimate of future development costs.
Contingencies
The Company has contingencies related to a receivable for production from the Feni field in Bangladesh and various claims raised against the Company as at June 30, 2011. Refer to the consolidated financial statements and notes for the period ended June 30, 2011 for a complete discussion of the contingencies.
NETBACKS
The following tables outline the Company's operating, funds from operations and earnings netbacks (all of which are non-IFRS measures):
----------------------------------------------------------------------------
Three months ended June 30, Three months ended June 30,
2011 2010
($/Mcfe) India Bangladesh Total India Bangladesh Total
----------------------------------------------------------------------------
Oil and natural
gas revenue 4.95 2.65 4.42 4.67 2.51 4.25
Royalties (0.25) - (0.20) (0.25) - (0.19)
Profit petroleum (0.11) (0.90) (0.29) (0.09) (0.85) (0.24)
Production and
operating
expense (0.43) (0.41) (0.40) (0.24) (0.38) (0.26)
----------------------------------------------------------------------------
Operating
netback 4.16 1.34 3.53 4.09 1.28 3.56
----------------------------------------------------------------------------
G&A (0.10) (0.06)
Net finance
expense (0.27) (0.22)
Current income
tax expense (0.49) (0.42)
----------------------------------------------------------------------------
Funds from
operations
netback 2.67 2.86
----------------------------------------------------------------------------
Production and
operating
expense (0.02) (0.02)
Exploration &
evaluation
costs (0.63) (1.20)
Other expense (0.31) (0.23)
Gain (loss) on
short-term
investment 0.05 (0.29)
Deferred income
tax (expense)/
reduction (0.21) 0.39
Change in
accounting
estimate
- deferred taxes (2.57) -
Net finance
expense (0.08) (0.07)
Depletion
expense (1.35) (0.93)
----------------------------------------------------------------------------
Earnings netback (2.45) 0.51
----------------------------------------------------------------------------
The netback for India, Bangladesh and in total for the Company is a non-IFRS measure calculated by dividing the revenue and costs for each country and in total for the Company by the total sales volume for each country and in total for the Company measured in Mcfe.
CORPORATE
----------------------------------------------------------------------------
Three months ended June 30,
(thousands of U.S. dollars) 2011 2010
----------------------------------------------------------------------------
General and administrative (2,158) (1,739)
Other expense - share-based compensation (6,196) (5,739)
Other expense - depreciation and other (819) (532)
Finance expense (7,799) (8,414)
Gain (loss) on short-term investments 1,215 (7,826)
----------------------------------------------------------------------------
(1) Other expense is comprised of share-based compensation expense and
depreciation expense.
General and administrative
General and administrative costs increased primarily as a result of increased use of outside legal services.
Other expense - Share-based compensation expense
There was an increase in share-based compensation expense in the quarter primarily as a result of an increase in the number of stock options being expensed on the addition of corporate personnel required for expanded operations.
Finance expense
----------------------------------------------------------------------------
Three months ended June 30,
(thousands of U.S. dollars) 2011 2010
----------------------------------------------------------------------------
Interest expense 5,758 7,586
Accretion expense 1,790 1,575
Foreign exchange (see below) 62 (818)
Other 189 70
----------------------------------------------------------------------------
Finance expense 7,799 8,414
----------------------------------------------------------------------------
Interest expense decreased as a result of the repayment of the long-term debt since the prior year's quarter. Accretion expense is on the Company's convertible debentures and decommissioning obligations.
Foreign Exchange
----------------------------------------------------------------------------
Three months ended June 30,
(thousands of U.S. dollars) 2011 2010
----------------------------------------------------------------------------
Realized foreign exchange (gain) loss 151 (1,092)
Unrealized foreign exchange (gain) loss (89) 274
----------------------------------------------------------------------------
Total foreign exchange (gain) loss 62 (818)
----------------------------------------------------------------------------
The Company's realized foreign exchange gains and losses arise because of the difference between the Indian rupee to U.S. dollar exchange rate at the time of recording individual accounts receivable and accounts payable compared to the exchange rate at the time of receipt of funds to settle recorded accounts receivable and payment to settle recorded accounts payable.
The unrealized foreign exchange gain arose primarily on the translation of the Indian-rupee denominated income tax receivable and deferred income tax asset to U.S. dollars.
There were additional foreign exchange losses in the year on U.S. dollar cash held by the parent whose functional currency is the Canadian dollar. An offsetting entry decreases the accumulated other comprehensive income but does not flow through the income statement.
Short-term Investments
The gain on short-term investments in the quarter was a result of marking the short-term investments to market value. In the prior year's quarter, there was an unrealized loss as a result of the changes in market value during the periods.
The Company sold investments during the year and sold investments resulting in realized losses of $1 million. The majority of the losses had been included in income in prior periods as the investments have been marked to market since the time of purchase.
LIQUIDITY AND CAPITAL RESOURCES
At June 30, 2011, the Company had total restricted and unrestricted cash of $103 million (March 31, 2011 - $126 million). The Company's unrestricted cash position decreased by $19 million during the quarter primarily as a result of the closing of the acquisition of Block 5(c) in Trinidad resulting in payment of the remaining $58 million towards the purchase price and capital spending, partially offset by cashflow from operations.
The Company had a working capital surplus of $86 million at June 30, 2011 ($119 million - March 31, 2011), calculated as current assets less current liabilities. The Company collected $30 million during the quarter that had been advanced for a new venture with conditions precedent. The conditions were not met and the advance was returned to the Company during the quarter. The Company's accounts payable decreased during the quarter as a result of decreased capital activity.
On December 30, 2009, the Company entered into a Cdn$310 million convertible debenture credit facility (the "Debentures"). The Debentures bear a coupon rate of 5 percent and mature on December 30, 2012. The interest is paid semi-annually in arrears on January 1st and July 1st of each year. Debentures are convertible at the option of the holder into common shares of the Company at a conversion price of Cdn$110.50 per common share until 60 days prior to the maturity date. In May 2011, the terms of the debentures were altered such that the Company now may elect to convert all of the Debentures at maturity into common shares at a 6% discount to the weighted average trading price for the 20 trading days prior to the election.
The Company has a $40 million credit facility for general corporate purposes and has not borrowed against this facility. In April 2011, the Company entered into an account performance security agreement under which it could issue performance security guarantees up to an aggregate amount of $36.5 million, however, this facility was cancelled in July 2011.
The Company has estimated the cost of its remaining work commitments as at March 31, 2011 under the various PSCs including $10 million for drilling three wells in the D4 Block, $2 million to drill the remaining well required for the Cauvery Block, $254 million for the remaining seismic and planned drilling for Indonesian blocks, $31 million for drilling in Kurdistan, $40 million for drilling in Madagascar and $188 million for the remaining seismic and drilling commitments for the Trinidad blocks.
The cost of the remainder of the Company's planned capital program for Fiscal 2012 is $270 million, which is comprised of $146 million for exploration and $124 million for development.
The Company expects that it will use cash on hand, cash from operations and its current credit facility in order to fund its planned capital program for Fiscal 2012. Cashflow from operations is affected by production levels, by fluctuations in foreign exchange rates, changes in operating costs and the market price of oil. The Company has entered into gas contracts for production from the D6 Block with a gas price that is fixed at $3.95/Mcf until March 2014.
During Fiscal 2012, due to a pre-emptive right, Niko expects to have the opportunity to increase its net interest by 30 percent in each or all of the D6, NEC-25 and D4 blocks in India. Niko expects this opportunity, if acted upon, would be financed with debt.
SUMMARY OF QUARTERLY RESULTS
The following tables set forth selected financial information of the Company for the eight most recently completed quarters to June 30, 2011:
----------------------------------------------------------------------------
Sept. 30, Dec. 31, Mar. 31, June 30,
Three months ended 2010 2010 2011 2011
----------------------------------------------------------------------------
Oil and natural gas revenue(1) 105,855 99,315 93,999 88,277
Net income (loss) 23,785 27,504 4,536 (54,983)
Per share
Basic ($) 0.47 0.54 0.09 (1.07)
Diluted ($) 0.46 0.53 0.09 (1.07)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sept. 30, Dec. 31, Mar. 31, June 30,
Three months ended 2009(2) 2009(2) 2010(2) 2010
----------------------------------------------------------------------------
Oil and natural gas revenue(1) 77,879 91,757 110,662 104,687
Net income 45,043 14,637 38,667 14,072
Per share
Basic ($) 0.91 0.29 0.77 0.28
Diluted ($) 0.90 0.29 0.76 0.27
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(1) Oil and natural gas revenue is oil and natural gas sales less royalties
and profit petroleum expense.
(2) The Fiscal 2010 comparative numbers are non-adjusted Canadian GAAP
amounts.
Gas production from the D6 Block commenced in the quarter ended June 30, 2009 and ramped-up during the subsequent quarters, substantially increasing revenues in each quarter to the quarter ended September 30, 2010. D6 gas production began to decline in the subsequent quarters due to well performance. Operating expense increased as additional wells in the D6 Block came on-stream and in 2010 when gas production commenced from the MA oil field.
Net income in the quarters were affected by:
-- The Company's issued convertible debentures in December 2009 increasing
finance expense and repaid its long-term debt in October 2010 decreasing
finance expense, thereafter.
-- The Company's short-term investments are valued at fair value, which is
the quoted market price. Gains and losses are recognized throughout the
quarters based on fluctuations in the market prices.
-- Net income for the quarters from June 30, 2010 indicated above are
stated under IFRS and the Company expensed a portion of the exploration
and evaluation costs during these quarters decreasing net income. In the
quarters to March 31, 2010, exploration and evaluation costs were
capitalized.
-- For 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.
-- Depletion expense increased in the quarters ended March 31, 2010 and
again in March 31, 2011 as a result of revisions to the reserves and
estimated future costs to develop the reserves.
-- The Company recorded an adjustment of $9 million relating to the award
of the 36-inch pipeline that is connected to the Hazira facilities as a
result of arbitration in the quarter ended December 31, 2009. In the
quarter ended March 31, 2011, $9.7 million fine was recorded related to
the Company's guilty plea to one count of bribery under the Corruption
of Foreign Public Officials Act relating to two specific instances that
occurred in 2005.
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 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 not significant to the operations or the consolidated financial statements. The transactions with the related party are measured at the exchange amount, which is the amount agreed to between related parties.
FINANCIAL INSTRUMENTS
Financial instruments of the Company consist of short-term investments, accounts receivable, long-term accounts receivable, accounts payable and accrued liabilities and convertible debentures.
The Company is exposed to fluctuations in the value of its 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 the Company operates. The Company manages the risk by converting cash held in foreign currencies to U.S. dollars as required to fund forecast expenditures. The Company is exposed to changes in foreign exchange rates as the future interest payments on the convertible debentures 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 the 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 manages this risk. The Company does so in the normal course of business by entering into contracts with fixed 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 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 current year, calculated annually, for the D6 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. A gain on the recognition of the short-term investments at fair value of $1 million was recognized in income. The Company realized previously recorded mark-to-market losses on the sale of investments of $1 million in the quarter. The fair value of the long-term account receivable is calculated based on the amount receivable discounted at 6.5 percent for three years as collection is assumed in three years. The loss on recognition of the fair value of the long-term account receivable was not significant during the quarter and was recognized in finance expense.
The debt component of the convertible debentures has been recorded net of the fair value of the conversion feature. The fair value of the conversion feature of the debentures included in shareholders' equity at the date of issue was $15 million. The fair value of the conversion feature of the debentures was determine 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 debentures. Interest and financing expense of $5 million was recorded for interest paid and accretion of the discount on the convertible debentures during the quarter.
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.
The critical accounting estimates include oil and natural gas reserves, depletion, depreciation and amortization expense, asset impairment, decommissioning obligations, the amount and likelihood of contingent liabilities and income taxes. The critical accounting estimates are based on variable inputs including:
-- estimation of recoverable oil and natural gas reserves and future cash
flows from the reserves;
-- geological interpretations, exploration activities and success or
failure, and the Company's plans with respect to the property and
financial ability to hold the property;
-- risk-free interest rates;
-- estimation of future abandonment costs;
-- facts and circumstances supporting the likelihood and amount of
contingent liabilities; and
-- interpretation of income tax laws.
A change in a critical accounting estimate can have a significant effect on net earnings as a result of their impact on the depletion rate, decommissioning obligations, asset impairments, losses and income taxes. A change in a critical accounting estimate can have a significant effect on the value of property, plant and equipment, decommissioning obligations and accounts payable.
For a complete discussion of the critical accounting estimates, please refer to the MD&A for the Company's fiscal year ended March 31, 2011, available at www.sedar.com.
INITIAL ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS)
In February 2008, the Accounting Standards Board confirmed that IFRS will be required for interim and annual reporting by publicly accountable enterprises effective for January 1, 2011 including 2010 comparative information. The consolidated financial statements for the three months ended June 30, 2011 have been prepared in accordance with IFRS applicable to the preparation of interim financial statements including International Accounts Standard (IAS) 34, "Interim Financial Reporting" and IFRS 1 "First-time Adoption of International Financial Reporting Standards".
The accounting policies adopted by the Company under IFRS are set out in note 2 to the consolidated financial statements for the three months ended June 30, 2011. Note 24 to the same consolidated financial statements discloses the impact of the transition to IFRS on the Company's reported financial position, earnings and cash flows, including the nature and effect of certain transition elections and significant changes in accounting policies from those used in the Company's Canadian IFRS consolidated financial statements for fiscal 2011.
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
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 Company is currently assessing the impact of the new standard on its consolidated financial statements.
In May 2011, 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 judgement 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 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 is currently assessing the disclosure impact of the standards listed above on its consolidated financial statements.
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 the Company's 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 relating to the Company required to be disclosed by the Company in its annual 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.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
The Chief Executive Officer and Chief Financial Officer of the Company are responsible for designing internal controls over financial reporting or causing them to be designed under their supervision and evaluating the effectiveness of the Company's internal controls over financial reporting. The Chief Executive Officer and Chief Financial Officer have overseen the design and evaluation of internal controls over financial reporting and have concluded that the design and operation of these internal controls over financial reporting were effective in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with International Financial Reporting Standards.
Because of their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, errors or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. There were no changes in internal controls over financial reporting during the quarter ended June 30, 2011. In August 2011, the Company hired a dedicated employee to function as the Chief Compliance Officer and perform the duties previously fulfilled by an existing officer. The Chief Compliance Officer reports to the Audit Committee.
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 June 30, 2011. 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 August 23, 2011, the Company had the following outstanding shares:
Number Cdn$ Amount (1)
----------------------------------------------------------------------------
Common shares 51,600,971 $ 1,321,029,000
Preferred shares nil nil
Stock options 3,786,752 -
----------------------------------------------------------------------------
(1) 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 August 23, 2011 is $1,167,196,000.
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
----------------------------------------------------------------------------
(unaudited)
(thousands of U.S. As at As at As at
dollars) Notes June 30, 2011 March 31, 2011 April 1, 2010
----------------------------------------------------------------------------
Assets (note 24) (note 24)
Current assets
Cash and cash
equivalents 89,186 108,342 196,813
Restricted cash 4, 22 3,374 7,704 28,245
Accounts receivable 5 43,772 75,160 44,298
Short-term investments 6 15,146 14,922 32,081
Inventory 7 11,041 7,212 7,255
----------------------------------------------------------------------------
162,519 213,340 308,692
----------------------------------------------------------------------------
Restricted cash 4, 22 10,704 10,232 21,026
Long-term accounts
receivable 26,005 46,549 29,920
Long-term investment 2,852 2,830 -
Exploration and
evaluation assets 8 868,519 762,221 708,478
Property, plant and
equipment 9 731,575 763,019 864,444
Income tax receivable 27,936 34,747 27,299
Deferred tax assets - 56,803 20,410
----------------------------------------------------------------------------
1,830,110 1,889,741 1,980,269
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable 69,601 87,305 121,810
Current tax payable 2,341 2,351 2,072
Finance lease obligation 4,804 4,804 4,278
Borrowings 10 - - 154,811
----------------------------------------------------------------------------
76,746 94,460 282,971
Decommissioning
obligation 11 31,979 31,454 27,117
Finance lease obligation 47,333 48,475 53,278
Borrowings 10 - - 38,003
Deferred tax liabilities 233,671 227,746 227,746
Convertible debentures 12 312,910 309,221 291,063
----------------------------------------------------------------------------
702,639 711,356 920,178
----------------------------------------------------------------------------
Shareholders' Equity
Share capital 14 1,162,462 1,162,319 1,111,593
Contributed surplus 71,305 63,037 45,077
Equity component of
convertible debentures 14,765 14,765 14,765
Accumulated other
comprehensive income (9,461) (8,344) 1,184
Deficit (111,600) (53,392) (112,528)
----------------------------------------------------------------------------
1,127,471 1,178,385 1,060,091
----------------------------------------------------------------------------
1,830,110 1,889,741 1,980,269
----------------------------------------------------------------------------
Financial Instruments (note 13)
Segmented Information (note 21)
Contingencies (note 23)
The accompanying notes are an integral part of these interim financial
statements.
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
----------------------------------------------------------------------------
(unaudited)
(thousands of U.S. dollars, Three months ended June 30,
except per share amounts) Notes 2011 2010
----------------------------------------------------------------------------
(note 24)
Oil and natural gas revenue 15 88,278 104,688
Production and operating expenses (9,555) (7,454)
Depletion expense (30,294) (25,520)
Exploration and evaluation costs (14,153) (32,839)
Gain / (loss) on short-term investments 1,215 (7,826)
Other expenses 16 (7,015) (6,271)
General and administrative expenses 17 (2,158) (1,739)
----------------------------------------------------------------------------
Operating profit 26,318 23,039
----------------------------------------------------------------------------
Finance income 137 418
Finance expense 19 (7,799) (8,414)
----------------------------------------------------------------------------
Net finance expense (7,662) (7,996)
----------------------------------------------------------------------------
Profit before income tax 18,656 15,043
----------------------------------------------------------------------------
Current income tax (expense) (10,987) (11,644)
Deferred income tax (expense) / reduction (62,652) 10,673
----------------------------------------------------------------------------
Income tax (expense) / reduction (73,639) (971)
----------------------------------------------------------------------------
Net (loss) / income (54,983) 14,072
----------------------------------------------------------------------------
Earnings per share:
Basic 20 ($ 1.07) $0.28
Diluted ($ 1.07) $0.27
----------------------------------------------------------------------------
Net (loss) / income for the period (54,983) 14,072
Foreign currency translation (loss) / gain (1,117) 6,915
----------------------------------------------------------------------------
Comprehensive (loss) / income for the period (56,100) 20,987
----------------------------------------------------------------------------
The accompanying notes are an integral part of these interim financial
statements.
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
----------------------------------------------------------------------------
(unaudited) Foreign currency
(thousands of U.S. Common Share Contributed translation on
dollars) Shares (#) Capital Surplus reserve
----------------------------------------------------------------------------
Balance at April 1,
2010 50,818,110 1,111,593 45,077 1,184
Options exercised 150,437 11,620 (2,597) -
Share-based compensation
expense - - 7,576 -
Profit for the period - - - -
Payment of dividends - - - -
Other comprehensive
income - - - 6,915
----------------------------------------------------------------------------
Balance at June 30,
2010 50,968,547 1,123,213 50,056 8,099
Options exercised 558,354 39,106 (9,364) -
Share-based compensation
expense - - 22,345 -
Profit for the period - - - -
Payment of dividends - - - -
Other comprehensive (loss) - - - (16,443)
----------------------------------------------------------------------------
Balance at March 31,
2011 51,526,901 1,162,319 63,037 (8,344)
Options exercised 1,570 143 (35) -
Share-based compensation
expense - - 8,303 -
Profit for the period - - - -
Payment of dividends - - - -
Other comprehensive (loss) - - - (1,117)
----------------------------------------------------------------------------
Balance at June 30,
2011 51,528,471 1,162,462 71,305 (9,461)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Equity component
(unaudited) of convertible
(thousands of U.S. dollars) debentures Deficit Total
----------------------------------------------------------------------------
Balance at April 1, 2010 14,765 (112,528) 1,060,091
Options exercised - - 9,023
Share-based compensation expense - - 7,576
Profit for the period - 14,072 14,072
Payment of dividends - (1,499) (1,499)
Other comprehensive income - - 6,915
----------------------------------------------------------------------------
Balance at June 30, 2010 14,765 (99,955) 1,096,178
Options exercised - - 29,742
Share-based compensation expense - - 22,345
Profit for the period - 55,825 55,825
Payment of dividends - (9,262) (9,262)
Other comprehensive (loss) - - (16,443)
----------------------------------------------------------------------------
Balance at March 31, 2011 14,765 (53,392) 1,178,385
Options exercised - - 108
Share-based compensation expense - - 8,303
Profit for the period - (54,983) (54,983)
Payment of dividends - (3,225) (3,225)
Other comprehensive (loss) - - (1,117)
----------------------------------------------------------------------------
Balance at June 30, 2011 14,765 (111,600) 1,127,471
----------------------------------------------------------------------------
The accompanying notes are an integral part of these interim financial
statements.
CONDENSED INTERIM CONSOLIDATED STATEMENT OF CASHFLOWS
----------------------------------------------------------------------------
(unaudited) Three month ended June 30,
(thousands of U.S. dollars) Notes 2011 2010
----------------------------------------------------------------------------
(note 24)
Cash flow from operating activities:
Net income (loss) (54,983) 14,072
Adjustments for:
Depletion and depreciation expense 31,193 26,052
Accretion expense 1,790 1,575
Other expenses (income) (69) 13
Deferred income taxes 62,652 (10,673)
Unrealized foreign exchange (gain) loss (89) 274
Exploration and evaluation expense 14,153 32,839
(Gain) loss on short-term investment (1,215) 7,826
Share-based compensation expense 6,720 6,233
Change in non-cash working capital 16,741 (13,448)
Change in long-term accounts receivable 27,390 4,456
----------------------------------------------------------------------------
Net cash from operating activities 104,283 69,219
----------------------------------------------------------------------------
Cash flows from investing activities:
Additions to exploration and evaluation (115,583) (41,601)
assets
Capital expenditures (3,010) (1,901)
Restricted cash contributions (600) (33,589)
Release of restricted cash 4,459 10,215
Investments 1,106 (2,698)
Change in non-cash working capital (6,967) (4,606)
----------------------------------------------------------------------------
Net cash (used in) investing activities (120,595) (74,180)
----------------------------------------------------------------------------
Cash flows from financing activities:
Proceeds from issuance of share capital, 109 9,023
net of issuance costs
Repayment of loans and borrowings - (26,489)
Reduction in finance lease liability (1,141) (1,016)
Dividends paid (3,225) (1,499)
----------------------------------------------------------------------------
Net cash (used in) financing activities (4,257) (19,981)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Change in cash and cash equivalents (20,569) (24,942)
----------------------------------------------------------------------------
Effect of translation on foreign currency 1,413 (3,702)
cash
Cash and cash equivalents beginning of 108,342 196,813
period
----------------------------------------------------------------------------
Cash and cash equivalents end of period 89,186 168,169
----------------------------------------------------------------------------
The accompanying notes are an integral part of these interim financial
statements.
NOTES TO THE CONDENSED INTERIM 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 21. The Company's common shares are traded on the Toronto Stock Exchange.
2. Basis of Presentation and Significant Accounting Policies
a. Statement of Compliance
The interim financial statements have been prepared in accordance with International Accounting Standard 34 "Interim Financial Reporting". The interim financial statements are the first financial statements reported under International Financial Reporting Standards (IFRS). "First-time Adoption of International Financial Reporting Standards" has been applied. These interim consolidated financial statements do not include all of the information required for full annual financial statements.
This note outlines the significant accounting policies selected under IFRS, which differ from the Canadian GAAP policies used in the Company's most recent annual financial statements. These policies have been retrospectively and consistently applied except where specific exemptions permitted an alternative treatment upon transition to IFRS in accordance with IFRS 1. The impact of the new standards, including reconciliations presenting the change from previous GAAP to IFRS as at April 1, 2010, as at and for the three months ended June 30, 2010 and as at and for the year ended March 31, 2011, is presented in note 24.
The financial statements were approved by the board of directors and authorized for issue on August 24, 2011.
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. Historical cost is generally based on the fair value of the consideration given in exchange for assets.
The condensed interim 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 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 included as an acquisition cost. 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 the income statement.
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:
------------------------------------ ------------------------------------
Block Country Working Block Country Working
interest interest
% %
------------------------------------ ------------------------------------
Block 9 Bangladesh 60 South Matindok Indonesia 100
Feni/Chattak Bangladesh 100 Sunda Strait I Indonesia 100
Cauvery India 100 West Papua IV Indonesia 48
D4 India 15 West Sageri Indonesia 100
D6 India 10 Qara Dagh Iraq 37
Hazira Field India 33 Grand Prix Madagascar 75
NEC India 10 Indus-X Pakistan 100
Bone Bay Indonesia 45 Indus-Y Pakistan 100
Cendrawasih Indonesia 45 Indus-Z Pakistan 100
Cendrawasih Bay
II Indonesia 50 Indus-North Pakistan 100
Cendrawasih Bay
III Indonesia 50 Block 2AB Trinidad 35.75
Cendrawasih Bay Central Range,
IV Indonesia 50 Shallow Horizon Trinidad 32.5
East Bula Indonesia 55 Central Range, Trinidad 40
Deep Horizon
Halmahera-Kofiau Indonesia 48 Guayaguayare, Trinidad 65
Shallow Horizon
Kofiau Indonesia 100 Guayaguayare, Trinidad 80
Deep Horizon
Kumawa Indonesia 45 Block 4(b) Trinidad 100
North Makassar Indonesia 30 NCMA2 Trinidad 56
Seram Indonesia 55 NCMA3 Trinidad 80
South East Ganal
I Indonesia 100 Block 5(c) Trinidad 25
------------------------------------ ------------------------------------
g. Financial Assets
Financial assets are initially measured at fair value, plus transaction costs, except for those financial assets classified as at 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 and short-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.
Investments in equity instruments that do not have a quoted market price and whose fair value cannot be reliably measured and derivatives that are linked to and must be settled by delivery of such unquoted equity instruments are measured at cost. The Company has one investment in an equity instrument fitting the description above, which is classified as a long-term investment and does not have any derivatives fitting the description above.
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 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 profit or loss.
h. Inventories
Inventories of stores, spares and consumables are purchased for use in oil and gas operations and are valued at cost, which is also the net realizable value. 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 successful efforts method of accounting as 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 technical, commercial and management review at least once a year 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.
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 the statement of comprehensive 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 the consolidated income statement when the asset is derecognized.
i. 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 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 the income statement 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. 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.
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.
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.
All other financial liabilities are measured at amortized cost using the effective interest method. The Company classified accounts payable and provisions, long-term debt and convertible debentures as other financial liabilities.
p. Derivative Financial Instruments
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
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. 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. Share-based Payments
The Company has a share-based compensation plan as described in note 14(b). All share-based awards of the Company are equity settled. Compensation expense associated with the 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. 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.
u. 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 interest expense on borrowings, accretion of the discount on decommissioning obligations and borrowings, impairment losses recognized on financial assets and bank charges.
v. 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 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 and accumulated in equity.
w. Taxation
Income tax expense is the sum of current 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.
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.
3. 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 interim consolidated financial statements are as follows:
-- 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 depreciation are based on the estimated useful life
of the underlying assets.
-- 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.
-- The fair value of the long-term account receivable is based on a
discount rate and timing of collection.
-- 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.
4. Restricted cash
----------------------------------------------------------------------------
As at June As at March As at April
(thousands of U.S. dollars) 30, 2011 31, 2011 1, 2010
----------------------------------------------------------------------------
Current portion of restricted cash
Guarantees(1) 3,374 7,704 21,838
Funds restricted under the facility
agreement (2) - - 6,407
----------------------------------------------------------------------------
3,374 7,704 28,245
----------------------------------------------------------------------------
Non-current portion of restricted cash
Guarantees (1) 4,427 3,947 1,500
Funds restricted under the facility
agreement (2) - - 14,489
Site restoration fund (3) 6,277 6,285 5,037
----------------------------------------------------------------------------
10,704 10,232 21,026
----------------------------------------------------------------------------
(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
22 for details of the guarantees.
(2) The cash that was restricted in accordance with the facility agreement
was released upon repayment of the long-term debt.
(3) 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.
5. Accounts receivable
----------------------------------------------------------------------------
As at As at As at
June 30, March 31, April 1,
(thousands of U.S. dollars) 2011 2011 2010
----------------------------------------------------------------------------
Oil and gas revenues receivable 32,326 34,055 36,138
Receivable from joint venture partners 7,405 3,339 696
Advances to vendors 1,709 33,809 3,252
Prepaid expenses and deposits 1,629 1,974 695
Other receivables 703 1,983 3,517
----------------------------------------------------------------------------
43,772 75,160 44,298
----------------------------------------------------------------------------
6. Short-term Investments
----------------------------------------------------------------------------
Three months ended Year ended
(thousands of U.S. dollars) June 30, 2011 March 31, 2011
----------------------------------------------------------------------------
Opening Balance 14,922 32,081
Purchases - 6,135
Disposals (1,106) (11,103)
Gain / (loss) on short-term investments 1,215 (12,720)
Foreign exchange 115 529
----------------------------------------------------------------------------
Closing balance 15,146 14,922
----------------------------------------------------------------------------
7. Inventories
----------------------------------------------------------------------------
As at June As at March As at April
(thousands of U.S. dollars) 30, 2011 31, 2011 1, 2010
----------------------------------------------------------------------------
Stock, spares and consumables 10,412 6,849 6,999
Oil and condensate inventories 629 363 256
----------------------------------------------------------------------------
11,041 7,212 7,255
----------------------------------------------------------------------------
8. Exploration and evaluation assets
----------------------------------------------------------------------------
Three months ended Year ended
(thousands of U.S. dollars) June 30, 2011 March 31, 2011
----------------------------------------------------------------------------
Opening balance 762,221 708,478
Additions during the period 106,298 54,018
Transfers - (275)
----------------------------------------------------------------------------
Closing balance 868,519 762,221
----------------------------------------------------------------------------
9. Property, plant and equipment
a. Development Assets
----------------------------------------------------------------------------
Three months ended Year ended
(thousands of U.S. dollars) June 30, 2011 March 31, 2011
----------------------------------------------------------------------------
Opening balance 18,421 4,572
Additions 2,862 22,803
Transfers - (8,954)
----------------------------------------------------------------------------
Closing balance 21,283 18,421
----------------------------------------------------------------------------
b. Producing Assets
----------------------------------------------------------------------------
Three months ended Year ended
(thousands of U.S. dollars) June 30, 2011 March 31, 2011
----------------------------------------------------------------------------
Cost
Opening balance 1,019,696 1,012,905
Transfers - 8,134
Disposals - (1,464)
Foreign currency translation gain 22 121
----------------------------------------------------------------------------
Closing balance 1,019,718 1,019,696
----------------------------------------------------------------------------
Depletion
Opening balance (312,767) (203,463)
Additions (30,294) (109,184)
Foreign currency translation (loss) (22) (120)
----------------------------------------------------------------------------
Closing balance (343,083) (312,767)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net producing assets 676,635 706,929
----------------------------------------------------------------------------
c. Other Property, Plant and Equipment
----------------------------------------------------------------------------
Office
Vehicles, Equipment,
Helicopters Furniture
(thousands Land and and and
of U.S. dollars) Buildings Aircraft Fittings Pipelines Total
----------------------------------------------------------------------------
Cost
Opening balance,
April 1, 2011 18,108 2,395 5,978 10,752 37,233
Additions - - 204 10 214
Disposals - - (60) - (60)
Foreign currency
translation gain - - 16 - 16
----------------------------------------------------------------------------
Balance, June 30,
2011 18,108 2,395 6,138 10,762 37,403
Depreciation
Opening balance,
April 1, 2011 (4,880) (1,148) (3,390) (6,738) (16,156)
Additions (347) (51) (182) (319) (899)
Disposals - - 14 - 14
Foreign currency
translation (loss) - - (10) - (10)
----------------------------------------------------------------------------
Balance, June 30,
2011 (5,227) (1,199) (3,568) (7,057) (17,051)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book Value, June
30, 2011 12,881 1,196 2,570 3,705 20,352
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Office
Vehicles, Equipment,
Helicopters Furniture
(thousands Land and and and
of U.S. dollars) Buildings Aircraft Fittings Pipelines Total
----------------------------------------------------------------------------
Cost
Opening balance,
April 1, 2010 16,299 2,445 4,257 9,928 32,929
Additions 1,809 - 1,643 824 4,276
Disposals - (50) - - (50)
Foreign currency
translation gain - - 78 - 78
----------------------------------------------------------------------------
Balance, March 31,
2011 18,108 2,395 5,978 10,752 37,233
----------------------------------------------------------------------------
Depreciation
Opening balance,
April 1, 2010 (3,322) (901) (2,839) (5,891) (12,953)
Additions (1,558) (260) (516) (847) (3,181)
Disposals - 13 - - 13
Foreign currency
translation (loss) - - (35) - (35)
----------------------------------------------------------------------------
Balance, March 31,
2011 (4,880) (1,148) (3,390) (6,738) (16,156)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value,
March 31, 2011 13,228 1,247 2,588 4,014 21,077
----------------------------------------------------------------------------
d. Capital Work-in-Progress
----------------------------------------------------------------------------
As at As at
(thousands of U.S. dollars) June 30, 2011 March 31, 2011
----------------------------------------------------------------------------
Capital work-in-progress 13,305 16,592
----------------------------------------------------------------------------
10. Borrowings
a. In March 2011, the Company entered into a three-year credit facility agreement for a $40 million (or the equivalent in Canadian dollars) revolving demand facility. The facility is available for general corporate purposes and bears interest at the Prime rate, US Base Rate, Libor or no base rate depending on the type of loan drawn, plus the applicable margin. The applicable margins range from 1.5% to 3% depending on the type of loan drawn and a ratio of debt to earnings. The facility is secured by an unlimited liability guarantee the Company and a demand debenture granting first priority security interest over the Company's assets. The Company has not drawn any amounts against the facility.
b. In April 2011, the Company entered into an agreement under which it could issue performance security guarantees up to an aggregate amount of $36.5 million. The agreement for the Company's account performance security guarantee was cancelled in July 2011.
11. Decommissioning Obligations
----------------------------------------------------------------------------
Three months ended Year ended
(thousands of U.S. dollars) June 30, 2011 March 31, 2011
----------------------------------------------------------------------------
Balance, beginning of period 31,454 27,117
Provisions made during the period 1 3,152
Change in estimate during the period - (896)
Accretion 524 2,081
----------------------------------------------------------------------------
Balance, end of period 31,979 31,454
----------------------------------------------------------------------------
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 $32 million as at June 30, 2011 (March 31, 2011 - $31 million) based on an undiscounted total future liability of $76 million (March 31, 2011 - $76 million). These costs are expected to be incurred over the next four to 15 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.
An amount of Rs. 280,920,418 (US$6,276,793) has been deposited with State Bank of India for decommissioning obligations. This amount has been treated as restricted cash included in non-current assets.
12. Convertible debentures
The Company issued Cdn $310 million, 5 percent convertible debentures (the "Debentures") on December 30, 2009. The Debentures mature on December 30, 2012 with interest paid semi-annually in arrears on January 1st and July 1st of each year. The Debentures are convertible at the option of the holder into common shares of the Company at a conversion price of Cdn $110.50 per common share until 60 days prior to the maturity date. In May 2011, the terms of the debentures were altered such that the Company now may elect to convert all of the Debentures at maturity into common shares at a 6 percent discount to the weighted average trading price for the 20 trading days prior to the election.
----------------------------------------------------------------------------
Three months ended Year ended
(thousands of U.S. dollars) June 30, 2011 March 31, 2011
----------------------------------------------------------------------------
Balance, beginning of period 309,221 291,063
Accretion expense 1,266 1,070
Foreign exchange 2,423 17,088
----------------------------------------------------------------------------
Balance, end of period 312,910 309,221
----------------------------------------------------------------------------
Interest of $4 million was expensed in the three months ended June 30, 2011 (June 30, 2010 - $4 million). Interest paid during the three months ended June 30, 2011 was $8 million (June 30, 2010 - $8 million).
13. 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:
(i) 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;
(ii) To maintain resources required to withstand financial difficulties due to exogenous influences such as financial, political, economic, social or market uncertainties and events; and
(iii) 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:
----------------------------------------------------------------------------
June 30, Mar. 31, Apr. 1,
(thousands of U.S. dollars) 2011 2011 2010
----------------------------------------------------------------------------
Borrowings - - 192,814
Convertible debentures 312,910 309,221 291,063
Shareholders' equity 1,127,471 1,178,385 1,060,091
----------------------------------------------------------------------------
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. However, the Company would generally use long-term debt either to fund portions of the development of proven properties or to finance portions of possible acquisitions. Exploration is generally funded by cash flow from operations and equity.
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. The periodic reviews ensure that the company has the short-term and long-term ability to fulfill its obligations, to fund ongoing operations, to pay dividends, to fund opportunities that might arise, to have sufficient funds to withstand financial difficulties or to bridge unexpected delays or satisfy contingencies and to grow the Company's producing assets.
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 four categories:
-- Financial assets and financial liabilities at fair value through profit
and loss
-- Held-to-maturity investments
-- Loans and receivables
-- Available-for-sale financial assets
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, 2011 and June 30, 2011 have been assessed on the fair value hierarchy describe above and have been classified as Level 1. The fair value of the short-term investments was based on publicly quoted market values. There was a gain of $1 million in the quarter (2010 - $8 million loss) on recognizing the short-term investments at their fair value. The fair values of short-term investments approximate their carrying amounts as they are recognized at fair value.
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. The fair value of the long-term account receivable is calculated based on the amount receivable discounted at 6.5 percent for three years as collection is assumed in three years. The long-term accounts receivable is carried at estimated fair value.
Accounts payable and accrued liabilities 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. Interest and accretion expense for the convertible debentures of $5 million was recognized in profit and loss during the quarter (2010 - $5 million). The carrying value of the Company's convertible debentures approximates the fair value.
Fair value information has not been disclosed for the long-term investment because the fair value cannot be measured reliably. The long-term investment is in common shares of a private oil and gas company and the investment is recorded at the cost of Cdn$3 million (US$3 million). There is not a liquid market for the common shares and liquidation would require a private buyer or for the company to list on a stock exchange. The Company intends to hold this investment for the longer-term.
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 June 30, 2011 was:
June 30, 2011
----------------------------------------------------------------------------
0 - 30 days 34,094
30 - 90 days (1) 8,801
90 - 365 days (1) 877
----------------------------------------------------------------------------
43,772
----------------------------------------------------------------------------
(1) Accounts receivable are past due as at June 30, 2011 but not impaired.
The accounts receivable that are not past due are receivable from counterparties with whom the Company has a history of timely collection and the Company considers the accounts receivable collectible.
The long-term account receivable balance consists of gas sales charged to Petrobangla for the production from the Feni field in Bangladesh. Payment of the receivable is being delayed as a result of various claims raised against the Company as described in notes 23(a,b). The long-term accounts receivable is not considered impaired. The Company considered the delay in payment, the writ and the lawsuit raised against the Company and progress towards resolving these issues in reaching the conclusion that the delay in payment is temporary. Despite the temporary delay in payment, the Company expects to collect the full amount of the receivable. The timing of collection is uncertain as the Company will not collect the receivable until resolution of the various claims raised against the Company described in notes 23(a,b).
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 manages 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 June
30, 2011:
----------------------------------------------------------------------------
Carrying less than 1
(thousands of U.S. dollars) Amount year 1 - 3 years
----------------------------------------------------------------------------
Accounts payable 69,601 69,601 -
Capital lease obligations(1) 52,137 4,804 47,333
Repayment of convertible
debentures(2) 312,910 - 312,910
----------------------------------------------------------------------------
(1) The amount of lease payments is $10.8 million per year until August
2018. The above $52 million represents the carrying value of the
liability.
(2) The carrying amount of the convertible debentures is the fair value of
$313 million. The amount that will be required to be repaid assuming
that the debentures are not converted is Cdn$310 million ($321 million
as at June 30, 2011).
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 debentures. 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 of its foreign subsidiaries. The Company does not have any foreign exchange contracts in place to mitigate currency risk.
A two percent strengthening of the Indian rupee against the U.S. dollar at June 30, 2011, which is based on historical movements in the foreign exchange rates, would have decreased net income by $0.4 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 three percent weakening of the Canadian dollar against the U.S. dollar at June 30, 2011, which is based on historical movement in foreign exchange rates, would have decreased net income by $2.1 million with an offsetting decrease to other comprehensive income. 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 prices would not have impacted net income for the quarter ended June 30, 2011. 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.
The Company is exposed to the risk of fluctuations in the market prices of its short-term investments. A sixteen percent change in the publicly quoted market values at the reporting date, which is based on historical changes in market values, would have increased or decreased net income for the quarter by $2.4 million. The fair value was $15.1 million at June 30, 2011.
14. Share Capital
a. Fully paid ordinary shares
The Company has authorized for issue an unlimited number of common shares and an unlimited number of preferred shares. The common shares issued are fully paid and the shares have no par value. No preferred shares have been issued.
b. Share options granted under the employee share option plan
The Company has reserved for issue 5,152,847 common shares for granting under stock options to directors, officers, and employees. The options become vested immediately to five years after the date of grant and expire one to six years after the date of grant.
Stock option transactions for the respective periods were as follows:
Three months ended Year ended
June 30, 2011 March 31, 2011
----------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price (Cdn$) Options Price (Cdn$)
----------------------------------------------------------------------------
Outstanding,
beginning of period 4,243,897 85.37 4,056,714 75.88
Granted 310,750 76.93 1,125,687 101.35
Forfeited (31,750) 101.69 (155,938) 86.82
Expired (8,575) 91.54 (73,775) 92.96
Exercised (1,570) 67.18 (708,791) 55.33
----------------------------------------------------------------------------
Outstanding, end of
period 4,512,752 84.67 4,243,897 85.37
----------------------------------------------------------------------------
Exercisable, end of
period 845,499 79.80 702,144 77.15
----------------------------------------------------------------------------
The following table summarizes stock options outstanding and exercisable
under the plan at June 30, 2011:
Outstanding Exercisable
Options Options
----------------------------------------------------------------------------
Weighted Weighted
Remaining Average Average
Life Exercise Exercise
Exercise Price Options (Years) Price (Cdn$) Options Price (Cdn$)
----------------------------------------------------------------------------
$47.11 - $49.99 783,815 1.9 49.62 146,499 49.62
$50.00 - $59.99 7,000 2.2 54.34 1,250 59.25
$60.00 - $69.99 376,875 2.3 63.46 156,500 69.92
$70.00 - $79.99 82,000 3.1 74.53 13,000 79.54
$80.00 - $89.99 734,313 2.1 85.47 118,750 81.36
$90.00 - $99.99 1,519,875 2.2 95.65 364,625 95.44
$100.00 - $109.99 979,749 3.7 103.54 40,500 106.23
$110.00 - $112.64 29,125 3.0 111.12 4,375 111.30
----------------------------------------------------------------------------
4,512,752 2.5 84.67 845,499 79.80
----------------------------------------------------------------------------
The weighted average share price during the three months ended June 30, 2011 was $75.19 (year ended March 31, 2011 - $97.47).
c. Fair value measure of equity instruments granted
The fair value of each option granted during the quarters was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average inputs:
Three months ended June 30, 2011 2010 ---------------------------------------------------------------------------- Grant-date fair value Cdn$25.53 Cdn$35.79 Share price Cdn$76.93 Cdn$105.49 Exercise price Cdn$76.93 Cdn$105.49 Expected volatility 41% 44% Expected life (years) 4.0 3.6 Expected dividend rate 0.3% 0.1% Risk-free interest rate 2.2% 2.3% Expected forfeiture rate 6.0% 6.7% ----------------------------------------------------------------------------
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 19 for categorization of share-based payment expense during the period.
15. Revenue
----------------------------------------------------------------------------
Three months ended Three months ended
(thousands of U.S. dollars) June 30, 2011 June 30, 2010
----------------------------------------------------------------------------
Natural gas sales 78,430 95,669
Oil and condensate sales 20,773 20,832
Less:
Royalties (4,404) (5,219)
Government's share of profit (6,521) (6,594)
petroleum
----------------------------------------------------------------------------
Oil and natural gas revenue 88,278 104,688
----------------------------------------------------------------------------
Revenues from oil and gas sales to Petrobangla comprised 14% of natural gas,
oil and condensate sales for the quarter (2010 - 12%).
16. Other expenses
----------------------------------------------------------------------------
Three months ended Three months ended
(thousands of U.S. dollars) June 30, 2011 June 30, 2010
----------------------------------------------------------------------------
Share-based compensation expense 6,196 5,739
Depreciation 899 532
Other (80) -
----------------------------------------------------------------------------
Other expenses 7,015 6,271
----------------------------------------------------------------------------
17. General and administrative expense
----------------------------------------------------------------------------
Three months ended Three months ended
(thousands of U.S. dollars) June 30, 2011 June 30, 2010
----------------------------------------------------------------------------
Salaries 238 1,474
Legal fees 2,036 296
Management fees 163 112
Consultants 160 123
Audit fees 113 92
Rent 191 149
Other (325) 202
Overhead recoveries from branch (418) (709)
offices
----------------------------------------------------------------------------
General and administrative expense 2,158 1,739
----------------------------------------------------------------------------
18. Expense disclosure
The Company prepares its statement of comprehensive income classifying costs according to function as opposed to the nature of the costs. As a result, share-based compensation expense is charged to various other headings in the statement of comprehensive income.
----------------------------------------------------------------------------
Three months ended Three months ended
(thousands of U.S. dollars) June 30, 2011 June 30, 2010
----------------------------------------------------------------------------
Share-based compensation expense
included in:
Exploration and evaluation assets 353 -
Operating expense 524 493
Exploration and evaluation expense 1,229 1,344
Other expense 6,196 5,739
----------------------------------------------------------------------------
Total 8,302 7,576
----------------------------------------------------------------------------
The Company prepares its statement of comprehensive income classifying costs according to function as opposed to the nature of the costs. As a result, general and administrative expenses are charged to various other headings in the statement of comprehensive income. General and administrative expenses of $3.7 million (2010 - $4.1 million) are categorized as exploration and evaluation expenses and of $2.7 million (2010 - $1.4 million) are categorized as production and operating expenses.
----------------------------------------------------------------------------
Three months ended Three months ended
(thousands of U.S. dollars) June 30, 2011 June 30, 2010
----------------------------------------------------------------------------
Audit fees 163 128
Management fees 166 115
Legal fees 1,676 484
Salary 2,806 3,601
Insurance 1,594 691
Security 221 285
Rent 390 337
Travel 222 255
Consultants 212 170
Non-operated and other 401 528
Office costs 771 593
----------------------------------------------------------------------------
Total 8,622 7,187
----------------------------------------------------------------------------
19. Finance expense
----------------------------------------------------------------------------
Three months ended Three months ended
(thousands of U.S. dollars) June 30, 2011 June 30, 2010
----------------------------------------------------------------------------
Interest expense related to capital 1,540 1,615
lease
Interest expense on long-term debt - 2,141
Interest expense on convertible 3,987 3,816
debentures
Accretion expense on convertible 1,266 1,070
debentures
Accretion expense on decommissioning 524 506
liabilities
Foreign exchange loss (gain) 62 (818)
Bank fees, bank charges and other 420 84
finance costs
----------------------------------------------------------------------------
Finance expense 7,799 8,414
----------------------------------------------------------------------------
20. Earnings per share
The earnings used in the calculation of basic and diluted earnings per share
are as follows:
----------------------------------------------------------------------------
Three months ended Three months ended
(thousands of U.S. dollars) June 30, 2011 June 30, 2010
----------------------------------------------------------------------------
Net (loss) income for the quarter (54,983) 14,072
----------------------------------------------------------------------------
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:
----------------------------------------------------------------------------
Three months ended Three months ended
June 30, 2011 June 30, 2010
----------------------------------------------------------------------------
Weighted average number of common
shares used in the calculation of
basic earnings per share 51,527,531 50,884,368
Shares deemed to be issued for no
consideration in respect of employee
options - 528,149
----------------------------------------------------------------------------
Weighted average number of ordinary
shares used in the calculation of
diluted earnings per share 51,527,531 51,412,517
----------------------------------------------------------------------------
As a result of the net loss in the quarter ended June 30, 2011, the outstanding stock options of 3,295,812 were considered anti-dilutive and were not included in the diluted per share amounts. The average market value of the Company's common shares for purposes of calculating the dilutive effect of stock options for the quarter ended June 30, 2010 was based on quoted market prices for the period that the options were outstanding. Stock options of 193,625 for the quarter ended June 30, 2010 and shares issuable upon conversion by the holders of the outstanding debentures of 2,805,430 for the quarter ended June 30, 2011 (2010 - 2,805,430) are anti-dilutive and are therefore excluded from the weighted average number of common shares for the purposes of diluted earnings per share.
21. 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.
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 revenues, results, assets and liabilities
----------------------------------------------------------------------------
Three months ended June 30, 2011
----------------------------------------------------------------------------
Natural
gas, Production Exploration
condensate Profit and and
and oil petroleum Royalty operating Depletion evaluation
Segment sales expense expense expense expense expense
----------------------------------------------------------------------------
Bangladesh 13,577 (4,598) - (2,096) (2,786) (259)
India 85,582 (1,923) (4,405) (7,453) (27,508) (457)
Indonesia - - - - - (6,093)
Kurdistan - - - - - (918)
Madagascar - - - - - (257)
Pakistan - - - - - (206)
Trinidad - - - - - (5,400)
Canada 44 - 1 (6) - -
All other - - - - - (563)
----------------------------------------------------------------------------
Total 99,203 (6,521) (4,404) (9,555) (30,294) (14,153)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended June 30, 2011
----------------------------------------------------------------------------
Gain / (loss) General and Net Income Segment
on short-term Other administrative finance tax profit
Segment investments expense expense (expense) expense (loss)
----------------------------------------------------------------------------
Bangladesh - - - - - 3,838
India - - - - (73,646) (29,810)
Indonesia - - - - - (6,093)
Kurdistan - - - - - (918)
Madagascar - - - - - (257)
Pakistan - - - - - (206)
Trinidad - - - - - (5,400)
Canada - - - - - 39
All other 1,215 (7,015) (2,158) (7,662) 7 (16,176)
----------------------------------------------------------------------------
Total 1,215 (7,015) (2,158) (7,662) (73,639) (54,983)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended June 30, 2010
----------------------------------------------------------------------------
Natural
gas, Production Exploration
condensate Profit and and
and oil petroleum Royalty operating Depletion evaluation
Segment sales expense expense expense expense expense
----------------------------------------------------------------------------
Bangladesh 13,477 (4,544) - (2,034) (2,496) (180)
India 102,811 (2,050) (5,200) (5,399) (23,024) (514)
Indonesia - - - - - (11,107)
Kurdistan - - - - - (984)
Madagascar - - - - - (19,440)
Pakistan - - - - - (82)
Trinidad - - - - - (523)
Canada 213 - (19) (21) - -
All other - - - - - (9)
----------------------------------------------------------------------------
Total 116,501 (6,594) (5,219) (7,454) (25,520) (32,839)
----------------------------------------------------------------------------
---------------------------------------------------------------------------
Three months ended June 30, 2010
---------------------------------------------------------------------------
Gain /
(loss) on General and Net Income Segment
short-term Other administrative finance tax profit
Segment investments expense expense (expense) expense (loss)
---------------------------------------------------------------------------
Bangladesh - - - - (6) 4,217
India - - - - (959) 65,665
Indonesia - - - - - (11,107)
Kurdistan - - - - - (984)
Madagascar - - - - - (19,440)
Pakistan - - - - - (82)
Trinidad - - - - - (523)
Canada - - - - - 173
All other (7,826) (6,271) (1,739) (7,996) (6) (23,847)
---------------------------------------------------------------------------
Total (7,826) (6,271) (1,739) (7,996) (971) 14,072
---------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended June 30, 2011 Year ended March 31, 2011
-----------------------------------------------------------------
Additions to:
-----------------------------------------------------------------
Exploration and
evaluation Property, plant Exploration and
assets and equipment evaluation Property, plant
Segment (E&E) (PP&E) assets and equipment
----------------------------------------------------------------------------
Bangladesh - 279 511 5,435
India 885 2,588 22,206 18,125
Indonesia 3,067 - 6,402 -
Kurdistan 6,133 37 20,547 -
Madagascar - - 800 -
Pakistan - - - -
Trinidad 96,843 666 3,552 -
All other - 214 - 4,277
----------------------------------------------------------------------------
Total 106,928 3,784 54,018 27,837
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at June 30, 2011 As at March 31, 2011
-----------------------------------------------------------------
Segment Total Total Total Total Total Total
E&E PP&E assets E&E PP&E assets
----------------------------------------------------------------------------
Bangladesh 5,248 39,816 77,228 5,248 42,323 82,057
India 134,730 669,954 886,238 133,929 698,869 990,857
Indonesia 502,879 - 510,304 499,810 - 510,905
Kurdistan 68,971 786 75,797 62,839 749 96,895
Madagascar 1,200 - 1,280 1,200 - 1,341
Pakistan - - 65 - - 42
Trinidad 155,491 666 162,041 59,195 - 62,104
All other - 20,353 117,157 - 21,078 145,540
----------------------------------------------------------------------------
Total 868,519 731,575 1,830,110 762,221 763,019 1,889,741
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at April 1, 2010
-----------------------------------------------------------------
Segment Total Total Total
E&E PP&E assets
----------------------------------------------------------------------------
Bangladesh 4,737 50,219 91,886
India 111,998 792,925 1,047,580
Indonesia 493,408 125 534,373
Kurdistan 42,293 1,239 45,340
Madagascar 400 - 527
Pakistan - - 19
Trinidad 55,642 - 58,555
All other - 19,936 201,989
----------------------------------------------------------------------------
Total 708,478 864,444 1,980,269
----------------------------------------------------------------------------
22. Guarantees
----------------------------------------------------------------------------
(thousands of U.S. dollars) As at June 30, As at March 31, As at April 1,
2011 2011 2010
----------------------------------------------------------------------------
Performance security guarantees
included in restricted cash (1)
Cauvery - India - 804 804
D4 - India 1,474 3,234 984
Indonesia 6,327 7,613 21,550
Performance security guarantees
not included in restricted
cash (2)
Indonesia 2,454 2,454 2,454
Madagascar - - 1,178
----------------------------------------------------------------------------
Total guarantees 10,255 14,105 26,970
----------------------------------------------------------------------------
(1) The Company is required to provide funds to support the guarantees in
the amounts indicated above.
(2) These performance security guarantees are not reflected on the balance
sheet as they are supported by Export Development Canada. On May 5,
2012, the performance security guarantee will be up for renewal and
the Company will be required to support the guarantee with cash.
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.
23. 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 The Joint Venture Agreement for Feni and
for the Feni and Chattak fields Chattak fields is valid.
be declared null and illegal.
----------------------------------------------------------------------------
That the government realize from The compensation claims should be
the Company compensation for the decided by the lawsuit described in note
natural gas lost as a result (b) below or by mutual agreement.
of the uncontrolled flow
problems as well as for damage
to the surrounding area.
----------------------------------------------------------------------------
That Petrobangla withhold Petrobangla to withhold future payments
future payments to the Company to the Company related to production from
relating to production from the the Feni field until the lawsuit
Feni field ($27.9 million as at described in note (b) below is resolved
June 30, 2011). or both parties agree to a settlement.
----------------------------------------------------------------------------
That all bank accounts of the The ruling did not address this issue,
Company maintained in therefore the previous ruling stands.
Bangladesh be frozen. 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:
(i) taka 389,025,000 ($5.3 million) for 3 Bcf of free natural gas delivered from the Feni field as compensation for the burnt natural gas;
(ii) taka 763,786,000 ($10.3 million) for 5.89 Bcf of free natural gas delivered from the Feni field as compensation for the subsurface loss;
(iii) taka 845,560,000 ($11.4 million) for environmental damages, an amount subject to be increased upon further assessment;
(iv) taka 5,835,375,000 ($78.8 million) for 45 Bcf of natural gas as compensation for further subsurface loss; and
(v) 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 12(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 estimates the cash amount to settle the contingency at US$11 million. 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 is evaluating the options including force majeure and/or arbitration and is discussing the matter with the Company's joint venture partner in Hazira and the customer. The Company believes that the outcome is not determinable.
(d) The Company calculates and remits profit petroleum expense to the Government of India in accordance with the PSC. The profit petroleum expense calculation considers capital and other expenditures made by the joint interest, which reduce the profit petroleum expense. There are costs that the Company has included in the profit petroleum expense calculations that have been contested by the government. The Company believes that it is not determinable whether the above issue will result in additional profit petroleum expense. No amount has been recorded in these consolidated financial statements. Settlement costs, if any, will be recorded in the period of determination.
(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 unfavourable tax assessments related to taxation years 1999 through 2007. The assessments contend the 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.
In India, there are potentially four levels of appeal related to tax assessments: Commissioner Income Tax - Appeals ("CIT-A"); the Income Tax Appellate tribunal ("ITAT"); the High Court; and the Supreme Court. For taxation years 1999 to 2004, the Company has received favourable rulings at ITAT and the revenue Department has appealed to the High Court. For the 2005 taxation year, the Company has received a favourable ruling at CITA and for the 2006 and 2007 taxation years, the Company's CITA appeal is pending.
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 "explanation" is described in the amendment as having retrospective effect from April 1, 2000. Since tax holiday provisions became effective April 1, 1997, it is unclear as to why the "explanation" has effect from April 1, 2000. The Hazira production sharing contract (PSC) was signed in 1994 and commenced production prior to April 1, 2000. As a result, the Company is unable to apply the amended definition of "undertaking" to the Hazira PSC. The Company has previously filed and recorded its income taxes for the taxation years of 1999 to 2008 on the basis of multiple undertakings for the Hazira and Surat PSC.
The Company will continue to pursue both issues through the appeal process. The Company has challenged the retrospective amendments to the undertakings definition and the lack of clarification of whether natural gas is eligible for the tax holiday with the Gujarat High Court. The Company was granted an interim relief by the High Court on March 12, 2010 instructing the Revenue Department to not give effect to the "explanation" referred to above retrospectively until the matter is clarified in the courts. Even if the Company receives favourable outcomes with respect to both issues discussed above, the Revenue Department can challenge other aspects of the Company's tax filings.
For the taxation years ended March 31, 2009 and March 31, 2010, the Company has filed its tax return assuming natural gas is eligible for the tax holiday at Hazira and Surat but, unlike all previous years, has filed its tax return based on Hazira and Surat each having a single undertaking. The Company has reserved its right, under Indian tax law, to claim the tax holiday with multiple undertakings. While the Company still believes that it is eligible for the tax holiday on multiple undertakings, the change in method of filing is because the legislative changes, referred to above, lead to ambiguity in the Act. More specifically, if the Company had filed its return in a manner that is deemed to be in violation of the current legislation, the Company can be liable for interest and penalties. Further, at the time of filing the tax return, the Company had not appealed the amendments brought out in the tax holiday provisions and did not have the benefit of the interim relief by the High Court. As a result, the Company has filed in a more conservative manner than its interpretation of tax law as described previously. Despite filing in a conservative manner, the Company will continue to pursue the tax holiday changes through the appeals process.
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 $65 million (comprised of additional taxes of $39 million and write off of approximately $26 million of the net income tax receivable). In addition, the Company could be obligated to pay interest on taxes for the past periods.
(f) In December 2009, the arbitration of ownership of a 36-inch pipeline that is connected to the Hazira facilities in India was ruled in favor of the Company and its joint venture partner. The Government of India has filed a writ with the High Court in Delhi challenging the arbitration decision. The High Court has issued notice to the Company that the hearing has not yet commenced. If the appeal is heard and the court rules against the Company and its joint venture partner, the Company may challenge the decision in the Supreme Court of India. Adverse resolution would result in the write-off of long-term accounts receivable of $6 million.
(g) The Cauvery Block in India is under relinquishment. The Company believes it has fulfilled all commitments for the block while the Government of India contends that the Company has unfulfilled commitments of approximately $2 million. The Company believes the outcome is not determinable.
24. Reconciliations from Canadian GAAP to IFRS
The Company's accounting policies under IFRS, as outlined in note 2, differ from those followed under previous GAAP. These accounting policies have been applied for the three months ended June 30, 2011, as well as to the opening statement of financial position on the transition date, April 1, 2010, the comparative information for the three months ended June 30, 2010 and the comparative information for the year ended March 31, 2011.
The adjustments arising from the application of IFRS to amounts on the statement of financial position on the transition date and on transactions prior to that date, were recognized as an adjustment to the Company's opening deficit category on the statement of financial position when appropriate.
On transition to IFRS on April 1, 2010, the Company used certain exemptions allowed under IFRS 1 "First Time Adoption of International Reporting Standards". IFRS 1 indicates that a first-time adopter may elect not to apply IFRS 3 Business Combinations retrospectively to business combinations that occurred before the date of transition to IFRS. The Company has taken advantage of this exemption and has applied IFRS 3 only to business combinations that occurred on or after April 1, 2010.
There were no material adjustments to the Company's cash flows on transition from Canadian GAAP to IFRS.
Reconciliation of consolidated statement of financial position:
----------------------------------------------------------------------------
March 31, 2011
Canadian
Notes GAAP Adj. IFRS
----------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents 108,342 - 108,342
Restricted cash 7,704 - 7,704
Accounts receivable a, b, c,
d, l, m 72,422 2,738 75,160
Short-term investments 14,922 - 14,922
Inventory 363 6,849 7,212
Prepaid expenses/ deposits b 1,566 (1,566) -
----------------------------------------------------------------------------
205,319 8,021 213,340
----------------------------------------------------------------------------
Restricted cash 10,232 - 10,232
Long-term accounts receivable d, l 50,076 (3,527) 46,549
Long-term investment 2,830 - 2,830
Exploration and evaluation
assets - 762,221 762,221
Property, plant and equipment d, e, f,
g, h, i,
j, l, m 1,861,442 (1,098,423) 763,019
Income tax receivable a 34,637 110 34,747
Deferred tax assets a 42,977 13,826 56,803
----------------------------------------------------------------------------
2,207,513 (317,772) 1,889,741
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable a, d, l, m 90,340 (3,035) 87,305
Current tax payable a 2,277 74 2,351
Finance lease obligation h 5,848 (1,044) 4,804
Borrowings - - -
----------------------------------------------------------------------------
98,465 (4,005) 94,460
----------------------------------------------------------------------------
Decommissioning obligations i 37,703 (6,249) 31,454
Finance lease obligation h 52,624 (4,149) 48,475
Borrowings - - -
Deferred tax liabilities a 227,746 - 227,746
Convertible debentures 309,221 - 309,221
----------------------------------------------------------------------------
725,759 (14,403) 711,356
----------------------------------------------------------------------------
Shareholders' equity
Share capital j 1,157,889 4,430 1,162,319
Contributed surplus j 67,279 (4,242) 63,037
Equity component of convertible
debentures 14,765 - 14,765
Accumulated other comprehensive
income e, j 422 (8,766) (8,344)
Retained earnings (deficit) n 241,399 (294,791) (53,392)
----------------------------------------------------------------------------
1,481,754 (303,369) 1,178,385
----------------------------------------------------------------------------
2,207,513 (317,772) 1,889,741
----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, 2010
Canadian GAAP Adj. IFRS
----------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents 168,169 - 168,169
Restricted cash 25,096 - 25,096
Accounts receivable 48,923 1,774 50,697
Short-term investments 25,705 - 25,705
Inventory 541 14,079 14,620
Prepaid expenses/ deposits 1,685 (1,685) -
----------------------------------------------------------------------------
270,119 14,168 284,287
----------------------------------------------------------------------------
Restricted cash 47,549 - 47,549
Long-term accounts receivable
42,027 (13,304) 28,723
Long-term investment - - -
Exploration and evaluation
assets - 724,454 724,454
Property, plant and equipment 1,864,699 (1,030,351) 834,348
Income tax receivable 23,246 145 23,391
Deferred tax assets 31,410 (327) 31,083
----------------------------------------------------------------------------
2,279,050 (305,215) 1,973,835
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable 127,214 (12,509) 114,705
Current tax payable 4,645 221 4,866
Finance lease obligation 10,757 (6,746) 4,011
Borrowings 128,322 - 128,322
----------------------------------------------------------------------------
270,938 (19,034) 251,904
----------------------------------------------------------------------------
Decommissioning obligations 31,478 (3,859) 27,619
Finance lease obligation 51,784 746 52,530
Borrowings 38,003 - 38,003
Deferred tax liabilities 227,746 - 227,746
Convertible debentures 279,855 - 279,855
----------------------------------------------------------------------------
899,804 (22,147) 877,657
----------------------------------------------------------------------------
Shareholders' equity
Share capital 1,118,783 4,430 1,123,213
Contributed surplus 53,806 (3,750) 50,056
Equity component of convertible
debentures 14,765 - 14,765
Accumulated other comprehensive
income 21,215 (13,116) 8,099
Retained earnings (deficit) 170,677 (270,632) (99,955)
----------------------------------------------------------------------------
1,379,246 (283,068) 1,096,178
----------------------------------------------------------------------------
2,279,050 (305,215) 1,973,835
----------------------------------------------------------------------------
----------------------------------------------------------------------------
April 1, 2010
Canadian GAAP Adj. IFRS
----------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents 196,813 - 196,813
Restricted cash 28,245 - 28,245
Accounts receivable 47,706 (3,408) 44,298
Short-term investments 32,081 - 32,081
Inventory 256 6,999 7,255
Prepaid expenses/ deposits 724 (724) -
----------------------------------------------------------------------------
305,825 2,867 308,692
----------------------------------------------------------------------------
Restricted cash 21,026 - 21,026
Long-term accounts receivable 31,128 (1,208) 29,920
Long-term investment - - -
Exploration and evaluation
assets - 708,478 708,478
Property, plant and equipment 1,844,826 (980,382) 864,444
Income tax receivable 23,240 4,059 27,299
Deferred tax assets 20,410 - 20,410
----------------------------------------------------------------------------
2,246,455 (266,186) 1,980,269
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable 123,547 (1,737) 121,810
Current tax payable 1,971 101 2,072
Finance lease obligation 5,357 (1,079) 4,278
Borrowings 154,811 - 154,811
----------------------------------------------------------------------------
285,686 (2,715) 282,971
----------------------------------------------------------------------------
Decommissioning obligations 30,520 (3,403) 27,117
Finance lease obligation 58,472 (5,194) 53,278
Borrowings 38,003 - 38,003
Deferred tax liabilities 227,746 - 227,746
Convertible debentures 291,063 - 291,063
----------------------------------------------------------------------------
931,490 (11,312) 920,178
----------------------------------------------------------------------------
Shareholders' equity
Share capital 1,107,163 4,430 1,111,593
Contributed surplus 48,397 (3,320) 45,077
Equity component of convertible
debentures 14,765 - 14,765
Accumulated other comprehensive
income 12,220 (11,036) 1,184
Retained earnings 132,420 (244,948) (112,528)
----------------------------------------------------------------------------
1,314,965 (254,874) 1,060,091
----------------------------------------------------------------------------
2,246,455 (266,186) 1,980,269
----------------------------------------------------------------------------
Reconciliation of consolidated statement of comprehensive income:
----------------------------------------------------------------------------
Year ended March 31, 2011
Canadian
Years ended Notes GAAP Adj. IFRS
----------------------------------------------------------------------------
Oil and natural gas revenue 453,824 - 453,824
Royalties (20,707) - (20,707)
Profit petroleum d (29,261) - (29,261)
Production and operating
expenses h, j, k, l (38,360) (75) (38,435)
Depletion expense g (134,694) 25,510 (109,184)
----------------------------------------------------------------------------
Exploration and evaluation e, j, k - (97,081) (97,081)
(Loss) / gain on short-term
investments (12,720) - (12,720)
Other expenses (9,861) 385 (9,476)
General and administrative
expenses e, k (11,972) 1,163 (10,809)
Share-based payment expense j (28,998) 6,967 (22,031)
Depreciation g (2,410) (771) (3,181)
----------------------------------------------------------------------------
Operating profit 164,841 (63,902) 100,939
Finance income d, k 912 1,468 2,380
Finance expense
Interest expense h (24,928) (1,003) (25,931)
Accretion expense i (6,904) 57 (6,847)
Foreign exchange gain /
(loss) a, m 875 90 965
Other - (379) (379)
----------------------------------------------------------------------------
Net finance expense (30,045) 233 (29,812)
----------------------------------------------------------------------------
Income before income taxes 134,796 (63,669) 71,127
----------------------------------------------------------------------------
Income tax expense
Current tax (expense) a (36,900) - (36,900)
Deferred tax reduction /
(expense) a 21,844 13,826 35,670
----------------------------------------------------------------------------
(15,056) 13,826 (1,230)
----------------------------------------------------------------------------
Net income 119,740 (49,843) 69,897
----------------------------------------------------------------------------
Foreign currency translation
(loss) / gain (11,798) 2,270 (9,528)
----------------------------------------------------------------------------
Comprehensive income 107,942 (47,573) 60,369
----------------------------------------------------------------------------
Reconciliation of consolidated statement of comprehensive income:
----------------------------------------------------------------------------
Three months ended June 30, 2010
Years ended Canadian GAAP Adj. IFRS
----------------------------------------------------------------------------
Oil and natural gas revenue 116,501 - 116,501
Royalties (5,219) - (5,219)
Profit petroleum (6,863) 269 (6,594)
Production and operating
expenses (7,375) (79) (7,454)
Depletion expense (31,524) 6,004 (25,520)
----------------------------------------------------------------------------
Exploration and evaluation - (32,839) (32,839)
(Loss) / gain on short-term
investments (7,826) - (7,826)
Other expenses - - -
General and administrative
expenses (1,428) (311) (1,739)
Share-based payment expense (7,368) 1,629 (5,739)
Depreciation (362) (170) (532)
----------------------------------------------------------------------------
Operating profit 48,536 (25,497) 23,039
Finance income - 418 418
Finance expense
Interest expense (7,322) (265) (7,587)
Accretion expense (1,583) 8 (1,575)
Foreign exchange gain /
(loss) 1,141 (323) 818
Other (372) 302 (70)
----------------------------------------------------------------------------
Net finance expense (8,136) 140 (7,996)
----------------------------------------------------------------------------
Income before income taxes 40,400 (25,357) 15,043
----------------------------------------------------------------------------
Income tax expense
Current tax (expense) (11,644) - (11,644)
Deferred tax reduction /
(expense) 11,000 (327) 10,673
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(644) (327) (971)
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Net income 39,756 (25,684) 14,072
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Foreign currency translation
(loss) / gain 8,995 (2,080) 6,915
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Comprehensive income 48,751 (27,764) 20,987
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Notes to reconciliations:
(a) Income taxes
The book value of property, plant and equipment related to the D6 Block is less under IFRS than under Canadian GAAP. This results in an increase in the deferred tax asset.
Under Canadian GAAP, the Company classified excess tax instalments as accounts receivable and have classified the same as income tax receivable under IFRS. This resulted in a $4.4 million adjustment as at April 1, 2010.
---------------------------------------------------------------------------- Consolidated statement of financial position March 31, 2011 June 30, 2010 April 1, 2010 ---------------------------------------------------------------------------- Decrease in accounts receivable - - (4,429) Increase in income tax receivable 110 145 4,059 Increase / (decrease) in deferred tax asset 13,826 (327) - (Increase) / decrease in accounts payable (48) - 414 (Increase) in current tax payable (74) (221) (101) ---------------------------------------------------------------------------- (Increase) / decrease in deficit 13,814 (403) (57) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Consolidated statement of comprehensive income March 31, 2011 June 30, 2010 ---------------------------------------------------------------------------- Increase in foreign exchange (gain)/loss 45 (19) Decrease / (increase) in deferred tax expense 13,826 (327) ---------------------------------------------------------------------------- (Decrease) / increase in comprehensive income 13,871 (346) ---------------------------------------------------------------------------- (b) Prepaid Expenses / Deposits Prepaid expenses and deposits have been reclassified to accounts receivable. ---------------------------------------------------------------------------- Consolidated statement of financial position March 31, 2011 June 30, 2010 April 1, 2010 ---------------------------------------------------------------------------- Increase in accounts receivable 1,566 1,685 724 Decrease in prepaid expenses/deposits (1,566) 1,685 (724) ---------------------------------------------------------------------------- (Increase) / decrease in deficit - - - ---------------------------------------------------------------------------- (c) Cash calls receivable Cash calls receivable from joint venture partners are classified as current assets as they are due in the current period. Under Canadian GAAP, these were misclassified as long-term accounts receivable. ---------------------------------------------------------------------------- Consolidated statement of financial position March 31, 2011 June 30, 2010 ---------------------------------------------------------------------------- Increase in accounts receivable 638 3,550 Decrease in long-term accounts receivable (638) (3,550) ---------------------------------------------------------------------------- (Increase) / decrease in deficit - - ----------------------------------------------------------------------------
(d) 36" Pipeline
Accounts receivable and payable related to the 36" pipeline in Hazira reported under Canadian GAAP were net under IFRS as the amounts are expected to be settled net with the Company's joint venture partner. In addition, there were adjustments related to the audit of the results from the 36" pipeline.
---------------------------------------------------------------------------- Consolidated statement of financial position March 31, 2011 June 30, 2010 April 1, 2010 ---------------------------------------------------------------------------- Increase in accounts receivable - - 1,441 Decrease in long-term accounts receivable (2,889) (9,754) (1,208) Decrease in property, plant and equipment - (215) - Decrease / (increase) in accounts payable 2,889 9,748 (233) ---------------------------------------------------------------------------- (Increase) / decrease in deficit - (221) - ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Consolidated statement of comprehensive income March 31, 2011 June 30, 2010 ---------------------------------------------------------------------------- Decrease in profit petroleum expense - 269 Decrease in finance income - (490) ---------------------------------------------------------------------------- (Decrease) / increase in comprehensive income - (221) ----------------------------------------------------------------------------
(e) Property, plant and equipment
Under Canadian GAAP, the Company followed the full-cost method of accounting capitalizing costs incurred for exploration, development and producing properties. Under the Company's selected IFRS policies, pre-license costs, geological and geophysical costs (G&G), the costs of unsuccessful exploration drilling and associated general and administrative costs (G&A) are expensed. The remaining capital assets previously categorized as property, plant and equipment have considered under the IFRS categories including inventory and exploration and evaluation assets.
Under Canadian GAAP, cumulative translation differences arose on the revaluation of assets and liabilities to the reporting currency. The cumulative translation change under IFRS is a result of the adjustment of historical differences associated with assets that were written off, impaired or adjusted in property, plant and equipment.
---------------------------------------------------------------------------- Consolidated statement of financial position March 31, 2011 June 30, 2010 April 1, 2010 ---------------------------------------------------------------------------- Increase in inventory 6,849 14,079 6,981 Increase in exploration and evaluation assets 762,221 724,454 708,478 Decrease in property, plant and equipment (1,158,580) (1,075,144) (1,018,428) Decrease in accumulated other comprehensive income 8,920 13,184 11,036 ---------------------------------------------------------------------------- (Increase) / decrease in deficit (380,590) (323,427) (291,933) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Consolidated statement of comprehensive income March 31, 2011 June 30, 2010 ---------------------------------------------------------------------------- Decrease in exploration and evaluation expense (88,657) (31,111) Increase in general & administrative expense - (383) ---------------------------------------------------------------------------- (Decrease) / increase in comprehensive income (88,657) (31,494) ----------------------------------------------------------------------------
(f) Impairment
Impairment tests were calculated on transition to IFRS for each cash-generating unit. The cash-generating unit comprised of Feni and Chattak properties in Bangladesh and the cash-generating unit comprised of the Cauvery property in India were impaired. These properties were included in property, plant and equipment under Canadian GAAP. Under Canadian GAAP, the impairment test was considered on a country-by-country basis. Under IFRS, the impairment test is considered at the cost-generating-unit level, which is the PSC for Cauvery and the JVA for Feni and Chattak and does not include the Company's other properties in India or Bangladesh. The fair value of the properties used in the assessment of the impairment was the value in use and neither property had reserves attributable to it.
---------------------------------------------------------------------------- Consolidated statement of financial position March 31, 2011 June 30, 2010 April 1, 2010 ---------------------------------------------------------------------------- Decrease in property, plant and equipment (73,407) (73,407) (73,407) ---------------------------------------------------------------------------- (Increase) / decrease in deficit (73,407) (73,407) (73,407) ----------------------------------------------------------------------------
(g) Accumulated depletion
Under Canadian GAAP, depletion related to producing properties was calculated for each cost centre, which was defined as a country. IFRS requires depletion to be calculated based on individual components, which the Company has determined to be a production sharing contract (PSC). An adjustment was made for the change in the cost base as a result of the accounting policies for exploration and evaluation costs selected by the Company.
---------------------------------------------------------------------------- Consolidated statement of financial position March 31, 2011 June 30, 2010 April 1, 2010 ---------------------------------------------------------------------------- Increase in property, plant and equipment 150,318 131,028 125,194 ---------------------------------------------------------------------------- (Increase) / decrease in deficit 150,318 131,028 125,194 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Consolidated statement of comprehensive income March 31, 2011 June 30, 2010 ---------------------------------------------------------------------------- (Increase) / decrease in depletion expense 25,510 6,004 (Increase) in depreciation expense (771) (170) Decrease in other expense 385 - ---------------------------------------------------------------------------- (Decrease) / increase in comprehensive income 25,124 5,834 ----------------------------------------------------------------------------
(h) Lease
Under Canadian GAAP and IFRS, the finance lease obligation is recorded at inception of the lease for an amount that is the lesser of the present value of the minimum lease payments and the fair value of the asset. Under Canadian GAAP, the present value of the minimum lease payments is calculated using the lesser of the rate implicit of 11.7% in the lease and the Company's incremental cost of borrowing at the time of 6% while the rate implicit in the lease is always used under IFRS. As a result, the lease obligation was recorded at the fair value under Canadian GAAP and is recorded at the present value of the minimum lease payments under IFRS.
---------------------------------------------------------------------------- Consolidated statement of financial position March 31, 2011 June 30, 2010 April 1, 2010 ---------------------------------------------------------------------------- Decrease in property, plant and equipment (6,217) (6,065) (6,104) Decrease in current portion of finance lease obligation 1,044 6,746 1,079 Decrease in non-current portion of finance lease obligation 4,149 (746) 5,194 ---------------------------------------------------------------------------- (Increase) / decrease in deficit (1,024) (65) 169 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Consolidated statement of comprehensive income March 31, 2011 June 30, 2010 ---------------------------------------------------------------------------- Decrease in production and operating expense - 30 Increase in interest expense (1,193) (264) ---------------------------------------------------------------------------- (Decrease) / increase in comprehensive income (1,193) (234) ----------------------------------------------------------------------------
(i) Decommissioning obligations
Under Canadian GAAP asset retirement obligations were discounted at the corporate credit adjusted risk free rate of 5 to 7 percent over time. Under IFRS the estimated cash flow to abandon and remediate the wells and facilities has been risk adjusted and applied by country therefore the provision is discounted at an average risk free rate of 7 percent resulting in a decrease in the decommissioning obligations and property, plant and equipment.
---------------------------------------------------------------------------- Consolidated statement of financial position March 31, 2011 June 30, 2010 April 1, 2010 ---------------------------------------------------------------------------- Decrease in property, plant and equipment (5,924) (3,583) (3,135) Decrease in decommissioning obligations 6,249 3,859 3,403 ---------------------------------------------------------------------------- (Increase) / decrease in deficit 325 276 268 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Consolidated statement of comprehensive income March 31, 2011 June 30, 2010 ---------------------------------------------------------------------------- Decrease in accretion expense 57 8 ---------------------------------------------------------------------------- (Decrease) / increase in comprehensive income 57 8 ----------------------------------------------------------------------------
(j) Share-based payments
Under Canadian GAAP, the Company recognized an expense related to the share-based payments (SBP) for options granted after March 31, 2003. On transition to IFRS, the Company applied IFRS2 retrospectively and recognized the cost for share-based payments vesting after April 1, 2005 as an expense. This resulted in an additional share-based payment expense increasing the deficit and increasing share capital as these stock options have been exercised and the associated expense has been moved to share capital.
Under Canadian GAAP, the Company recognized an expense related to share-based payments, however, did not incorporate a forfeiture multiple. Under IFRS, the Company is required to estimate a forfeiture rate. The share-based payments recognized under Canadian GAAP were adjusted to incorporate a forfeiture rate resulting in a decrease in the deficit and a decrease in contributed surplus.
Under Canadian GAAP, the Company capitalized the portion of share-based payments attributable to exploration activities. Under IFRS, the Company expensed the majority of share-based payments. This resulted in a decrease in property, plant and equipment and an increase in the deficit.
---------------------------------------------------------------------------- Consolidated statement of financial position March 31, 2011 June 30, 2010 April 1, 2010 ---------------------------------------------------------------------------- Decrease in property, plant and equipment for capitalized share-based payments (5,913) (5,072) (4,502) Increase in share capital (4,430) (4,430) (4,430) Decrease in contributed surplus 4,242 3,750 3,320 Increase in accumulated other comprehensive income (154) (68) - ---------------------------------------------------------------------------- (Increase) / decrease in deficit (6,255) (5,820) (5,612) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Consolidated statement of comprehensive income March 31, 2011 June 30, 2010 ---------------------------------------------------------------------------- Increase in production and operating expense (1,776) (459) Increase in exploration and evaluation expense (5,834) (1,378) Decrease in share-based payment expense 6,967 1,629 ---------------------------------------------------------------------------- Decrease / (increase) in comprehensive income (643) (208) ----------------------------------------------------------------------------
(k) Reclassification of the income statement according to function
The Company classifies the statement of comprehensive income according to the function of the costs. The costs incurred are booked into the categories of production and operating expense, exploration and evaluation expense and general and administrative expense dependant on the activities to which they relate. As a result, a number of the costs recorded in one category under Canadian GAAP were reclassified to another category under IFRS.
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Consolidated statement of comprehensive
income March 31, 2011 June 30, 2010
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Decrease in production and operating expense 1,431 350
Increase in exploration and evaluation
expense (2,590) (350)
Decrease in general and administrative
expense 1,160 58
Decrease / (increase) net finance income 189 -
Decrease / (increase) in net finance expense (190) (58)
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Decrease / (increase) in comprehensive income - -
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(l) Other
The Company had other individually insignificant adjustments from Canadian
GAAP to IFRS as follows:
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Consolidated statement of
financial position March 31, 2011 June 30, 2010 April 1, 2010
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Increase / (decrease) in
accounts receivable 534 (3,461) (1,144)
Increase / (decrease) in
inventory - - 18
Increase in property, plant
and equipment 1,300 2,105 -
Decrease in accounts payable 193 2,761 1,556
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(Increase) / decrease in
deficit 2,028 1,407 430
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Consolidated statement of comprehensive
income March 31, 2011 June 30, 2010
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Decrease in production and operating expenses 270 -
Decrease / (increase) net finance income - 1,280
Decrease / (increase) in net finance expense 1,328 (305)
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Decrease / (increase) in comprehensive income 1,598 978
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(m) Deficit
The following is a summary of adjustments to the deficit:
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March 31, June 30, April 1,
Notes Description 2011 2010 2010
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a Reclassification of tax amounts 13,814 (403) (57)
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d 36" pipeline adjustments 0 (221) 0
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e Write-off of exploration and
evaluation costs and associated
general and administrative
costs (380,590) (323,427) (291,933)
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f Impairment of property, plant
and equipment (73,407) (73,407) (73,407)
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g Decrease in accumulated
depletion as a result of
calculating depletion expense
on a cash-generating unit basis
as opposed to a cost centre 150,318 131,028 125,194
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h Adjustment related to initial
value recorded for the lease of
the floating, production,
storage and offloading vessel (1,024) (65) 169
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i Adjustment to rate used to
discount decommissioning
obligations 325 276 268
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j Adjustment for commencement of
share-based payments, expensing
all share-based payments and
including a forfeiture rate in
the calculation of share-based
payments (6,255) (5,820) (5,612)
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l Other miscellaneous adjustments 2,028 1,407 430
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(Increase) / decrease in
deficit (294,791) (270,632) (244,948)
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Contact Information:
Edward Sampson
Chairman of the Board, President & Chief Executive Officer
(403) 262-1020
Niko Resources Ltd.
Murray Hesje
Vice President Finance
(403) 262-1020