Contact Information: Niko Resources Ltd. Edward S. Sampson Chairman of the Board, President & CEO (403) 262-1020 or Niko Resources Ltd. Murray Hesje VP Finance & CFO (403) 262-1020 www.nikoresources.com
CALGARY, ALBERTA--(Marketwire - Feb. 9, 2011) - Niko Resources Ltd. (TSX:NKO) ("Niko" or "the Company") is pleased to report its financial and operating results, including consolidated financial statements and notes thereto, as well as its managements' discussion and analysis, for the quarter ended December 31, 2010, the third quarter of Niko's fiscal year. The operating results are effective February 8, 2011. All amounts are in U.S. dollars unless otherwise indicated.
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Three months ended Nine months ended
December 31, December 31,
2010 2009 2010 2009
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Oil production (bbls/d) 2,590 1,304 2,941 1,254
Gas production (mcf/d) 276,865 250,102 282,821 204,106
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Total production (mcfe/d) 292,402 257,929 300,469 211,630
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Operating netback ($/mcfe) 3.28 3.01 3.41 2.90
Funds from operations ($ thousands) 69,893 68,806 223,748 145,018
Net income ($ thousands) 38,294 14,637 119,091 80,121
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Production from the D6 Block has increased year-over-year and is the primary reason for total production increases of 13 percent and 42 percent in the quarter and year-to-date, respectively, compared to the prior year periods. The D6 Block is also the primary reason for improved operating netbacks as D6 has higher realized prices and lower profit petroleum than the average of the Company's other properties.
D6 gas sales volumes are currently approximately 177 MMcf/d versus a budget of 210 MMcf/d due to well performance. The timing of drilling and tie-in of additional wells will be determined in the next few months when the operator finalizes their budget for the upcoming fiscal year.
Funds from operations improvements result from improved volumes and operating netbacks partially offset by higher current income taxes, higher interest expense related to the Company's convertible debentures and lower other income as the prior year periods benefitted from a favorable arbitration ruling related to a pipeline dispute.
Net income year-over-year changes benefit from improved funds from operations but are adversely impacted by higher non-cash charges related primarily to depletion and a loss in the year-to-date period on short-term investments.
FINANCIAL HIGHLIGHTS
- In October 2010, Niko repaid all of its outstanding long-term debt.
EXPLORATION HIGHLIGHTS
- Niko has farmed out a 45 percent working interest in the Seram and East Bula blocks in Indonesia.
- Niko has entered an agreement to acquire a 25 percent working interest in Block 5(c), located 94 kilometres off the east coast of Trinidad.
- Drilling continues at the Company's Kurdistan property.
LOOKING FORWARD
The forecast activity for calendar 2011 and 2012 is forecast below and is subject to change as circumstances warrant.
http://media3.marketwire.com/docs/209niko.pdf
Forward-Looking Information and Material Assumptions
This report on results for the three and nine months ended December 31, 2010 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 three and nine months ended December 31, 2010 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 three and nine months ended December 31, 2010.
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 period ended December 31, 2010 should be read in conjunction with the unaudited consolidated financial statements for the period ended December 31, 2010 and the MD&A and the audited consolidated financial statements as at and for the year ended March 31, 2010. This MD&A is effective February 8, 2010. 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 October 1, 2010 through December 31, 2010. The term "prior year's quarter" is used throughout the MD&A for comparative purposes and refers to the period from October 1, 2009 through December 31, 2009.
The fiscal year for the Company is the 12-month period ended March 31. The terms "Fiscal 2010" and "prior year" is used throughout this MD&A and in all cases refers to the period from April 1, 2009 through March 31, 2010. The terms "Fiscal 2011", "current year" and "the year" are used throughout the MD&A and in all cases refer to the period from April 1, 2010 through March 31, 2011. The term "Fiscal 2012" is used throughout this MD&A and in all cases refers 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 1 percent of total corporate 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, 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 the 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-GAAP Measures
The selected financial information presented throughout the MD&A is prepared in accordance with Canadian generally accepted accounting principles (GAAP), 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, operating expenses, depletion, depreciation and accretion expense and current and future 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-GAAP measures do not have any standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other companies.
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OVERALL PERFORMANCE
Funds from Operations
Three months ended Nine months ended
December 31, December 31,
(thousands of U.S. dollars) 2010 2009 2010 2009
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Oil and natural gas revenues 111,912 91,757 347,628 223,489
Royalties (4,874) (3,971) (16,109) (10,243)
Profit petroleum (7,818) (7,945) (21,830) (22,928)
Operating expense (10,862) (8,566) (28,261) (21,678)
Interest income and other 540 9,658 (64) 12,532
Interest and financing expense (5,467) (3,914) (19,642) (11,369)
General and administrative expense (2,885) (2,147) (6,977) (6,123)
Realized foreign exchange (loss) gain (1,694) 267 1,218 (590)
Current income tax expense (8,959) (6,333) (32,215) (18,072)
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Funds from operations(1) 69,893 68,806 223,748 145,018
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(1) Funds from operations is a non-GAAP measure as defined under "Non-GAAP
measures" in this MD&A.
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Natural gas production from the D6 Block commenced in April 2009 and is the major reason for the increase in revenues in the quarter and year-to-date compared to the same periods in the prior year. Oil sales from the D6 Block have also increased in the quarter and year-to-date. Maintenance was conducted on a pipeline in Block 9 in June 2010 and natural declines are continuing at Hazira and Surat decreasing revenues from the blocks.
Royalties, operating expense and current income tax expense increased with the net increase in production described above.
In spite of a significant increase in oil and gas revenue, profit petroleum was relatively constant period-over-period primarily due to D6 revenues attracting a very low profit petroleum charge and also due to the positive impact of including the 36-inch pipeline for cost recovery at the Hazira field. See note 12(g) to the interim consolidated financial statements for the complete discussion of a contingency related to the award of the 36-inch pipeline.
Interest and other income in the prior year periods include a US$9.3 million adjustment related to the successful arbitration of a dispute over a 36-inch pipeline that is connected to the Hazira facilities.
Interest and financing expense relates to the lease of the Floating Production, Storage and Offloading vessel (FPSO) related to D6 oil production, interest expense on the long-term debt and interest expense on the convertible debentures, which were issued at the end of the prior year's quarter.
The Company's realized foreign exchange loss in the quarter and gain year-to-date arose primarily on the settlement of Indian-rupee denominated working capital at foreign exchange rates that differ from the rates when the accounts receivable or payable were initially established.
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Net Income
Three months ended Nine months ended
December 31, December 31,
(thousands of U.S. dollars) 2010 2009 2010 2009
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Funds from operations (non-GAAP
measure) 69,893 68,806 223,748 145,018
Unrealized foreign exchange (loss)
gain (199) (673) 533 (9,013)
Gain (loss) on short-term investments 166 (26,525) (13,504) 11,163
Interest and financing expense (1,252) (43) (3,526) (228)
Stock-based compensation expense (7,461) (5,754) (21,359) (14,841)
Depletion, depreciation and accretion (31,917) (27,387) (97,973) (67,021)
Future income tax reduction 9,064 6,213 31,172 15,043
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Net income 38,294 14,637 119,091 80,121
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Net income in the quarter and year-to-date were positively impacted by the increase in funds from operations described above. Other factors affecting net income are explained below.
The unrealized foreign exchange loss in the quarter and gain year-to-date were primarily a result of the translation of the Indian-rupee denominated income tax receivable and a future income tax asset.
The gain or loss on short-term investments also contributed to year-over-year variances.
The portion of interest and financing expense included above relates to accretion of the convertible debentures.
The increase in stock-based compensation expense in the year is primarily a result of the increased fair value expense per stock option and an increase in the number of stock options being granted.
Depletion expense increased primarily due to the increased production from the D6 Block.
The future income tax reduction is the result of a tax credit available for future years related to minimum alternative tax paid for the D6 Block in the current year.
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 has received an extension to the exploration period to March 2011 in order to evaluate the technical merit of 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 deepwater blocks. This and other extensions allow the Company until the end of 2012 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 79 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.
There have been several gas discoveries since Dhirubhai 1 and 3. A development plan for nine such discoveries was submitted to the Government of India in July 2008, however, based on the Government's advice, in December 2009 the plan was modified to first develop four rather than nine discoveries. Additional development plans will be considered for the remaining discoveries.
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 December 31, 2010, 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 4 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 kilometers in the Mahanadi Basin off the east coast of India. The Company has fulfilled its capital commitments for the block and is drilling additional wells. Once commerciality is concluded, the Company expects to submit a development plan to the Government of India.
Surat - The Company holds a development area of 24 square kilometres containing the Bheema and NSA shallow natural gas fields. The block has been producing natural gas since April 2004 and comprised 2 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, 2011.
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 15 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 December 31, 2010, 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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Working Area (Square
Block Name Offshore Area Award Date Interest Kilometres)
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Bone Bay Sulawesi SW Nov. 2008 45% 4,969
South East Ganal(1) Makassar Strait Nov. 2008 100% 4,868
Seram(1) Seram North Nov. 2008 55% 4,991
South Matindok(1) Sulawesi NE Nov. 2008 100% 5,182
West Sageri(1) Makassar Strait Nov. 2008 100% 4,977
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 80% 4,926
North Makassar Makassar Strait Nov. 2009 50% 1,787
West Papua IV(1) Papua SW Nov. 2009 80% 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.
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All of the blocks are in the first exploration period, which is a three-year period. Most of the blocks have a seismic commitment and 10 of the blocks have a single well commitment. The Company's share of the remaining work commitments during the first exploration period is estimated at $114 million.
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. 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. The first exploration phase is for three years expiring in May 2011 and the Company has commitments under this phase for seismic and drilling one exploratory well. Processing and interpretation of the seismic program is complete. The Company began drilling the exploratory well in May 2010. The Company's share of the estimated remaining costs under the first exploration phase is $5 million.
Trinidad
The Company holds interests in five PSCs for three 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)
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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
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(1) Operated by the Company.
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The Company has minimum work commitments for Block 2AB to acquire and process 864 square kilometres of 3D seismic and drill three exploration wells by July 2012. Seismic was acquired during the quarter.
The Company has minimum work commitments for the Guayaguayare area to acquire 130 square kilometres of 3D seismic onshore, acquire 200 square kilometres of 3D seismic offshore and two onshore wells and one offshore well by July 2013. Seismic is scheduled to commence in the coming quarter.
The Company has remaining minimum work commitments for the Central Range area to acquire 168 kilometres of 3D seismic and drill three wells by September 2012. Seismic and drilling of the first well are scheduled to commence in the second half of calendar 2011.
The Company's share of the work commitments under the first exploration periods for the blocks listed above is estimated at $90 million.
In September 2010, the Company was the successful bidder on three new exploration blocks offshore Trinidad. The award of these blocks is subject to approval of the bid terms by the Government of Trinidad and Tobago. The Company will have a 100 percent interest in Block 4(b), a 56 percent interest in NCMA 2 and an 80 percent interest in NCMA 3. Block 4(b) is located off the east coast of Trinidad and NCMA 2 and NCMA 3 are located off the north coast of Trinidad.
In December 2010, the Company reached an agreement with Sonde Resources Corp. ("Sonde"), under which Niko will acquire Sonde's 25 percent interest in Block 5(c), located 94 kilometres off the east coast of Trinidad. The transaction is to be satisfied at closing via $75.5 million in cash, which includes the $20 million deposit described below, and the assumption of Sonde's liability under the performance guarantee provided for their Block MG license. The agreement is subject to the satisfaction of certain conditions. Closing is expected to occur on February 28, 2011, subject to extension to facilitate obtaining all required approvals. Niko paid a secured refundable deposit of $20 million to Sonde upon receipt of a waiver of the rights of first refusal in respect of Block 5(c) in February 2011. Each of the three wells drilled to date on Block 5(c) have encountered hydrocarbons and have been successfully tested.
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. A well location is expected to be selected after seismic interpration with a projected drilling date in the first calendar quarter of 2012.
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 2 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 will be evaluating the seismic in order to select potential drilling locations.
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Capital Expenditures
For the nine months ended December 31, 2010 (millions of U.S. dollars)
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Exploration
India 29
Indonesia 36
Kurdistan 17
Madagascar 24
Pakistan 2
Trinidad 8
Development
Bangladesh -
India 9
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Total(1) 125
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(1) The amounts presented are the Company's share of expenditures.
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India
D6 Block exploration: There was drilling activity on three exploration wells during the year. The rig was released from two wells, AR1 and AK3, during July 2010. The AR1 well was the third well appraising the "R-complex", which is a previous gas discovery. The R-complex is located approximately 37 kilometres to the south of the Dhirubhai 1 and 3 producing gas fields. Both the AR1 and the AK3 wells were successful gas wells and are currently being evaluated. The AW1 well is also an appraisal well in the vicinity of the R1 complex. Exploration drilling is expected to recommence in the future.
D6 Block development: There was drilling activity on two development wells during the year, B16 and A21.
NEC-25: In May 2010, the Company drilled a fifth well of a drilling campaign near the AJ1 discovery in the southern part of the block. All of the wells in the campaign encountered gas bearing sands and confirmed significant hydrocarbon potential for NEC-25. A further three wells are planned in the AJ area and AJ9 is waiting for the return of the drilling rig.
Hazira: The remaining two wells of the three-well drilling program in the Hazira block were drilled during the year. All three wells encountered a new oil bearing interval that awaits further evaluation.
Indonesia
In the quarter, over 3,000 kilometres of 2D seismic was acquired, and by the end of December 2010, the program had accumulated over 26,000 kilometres of 2D seismic covering 12 PSCs and one joint study area. This was accomplished at an average cost of approximately $900 per kilometer and with zero hours lost due to injury during more than 393,000 man-hours of seismic operations.
In the quarter, an additional 1,916 square kilometers of 3D seismic was acquired resulting in a cumulative total of over 11,000 square kilometers of 3D seismic by the end of December 2010. The average cost of the 3D seismic, most of which was purchased through speculative surveys, was approximately $5,500 per square kilometre.
Kurdistan
Drilling of an exploratory well in the Kurdistan region of Iraq on the Qara Dagh anticline commenced in May 2010. The well had drilled to a depth of 2,522 metres at December 31st and is currently drilling at a depth of approximately 3,000 meters. Geologically, the well has penetrated an anomalously thick lower Tertiary interval containing potential light oil in sandstone reservoirs that displayed fluorescence and cut fluorescence. A significant increase in mudgas readings with free oil has also been observed in the drill mud while drilling through the lower Tertiary. Nine and five-eighths of an inch casing string has been set and drilling continues in a 8.5" hole. The plan is to continue drilling and evaluate the prospectively of the deeper Cretaceous Shiranish, Kometan and Qamchuqa formations and conduct further evaluation of the lower Tertiary sandstones. The Company expects to reach the planned total depth of between 3,500 and 4,000 meters at the end of February. Testing will commence after reaching the total depth. Drilling and related costs are expected to be incurred over the remainder of Fiscal 2011.
Madagascar
A 3,236-square-kilometre 3D survey began in April 2010 and was completed in July 2010 at a cost of approximately $6,400 per square kilometre. The 3D seismic will fulfill the Phase II work commitment. Drilling is expected to commence in the quarter beginning January 2012. There is no significant spending forecast for the remainder of Fiscal 2011.
Trinidad
Capital additions in Trinidad are for seismic on Block 2AB, the costs of payments under the PSC and carrying costs of the blocks. Forecast costs for the remainder of Fiscal 2011 include additional seismic costs for Block 2AB, signing bonuses for Block 4(b), NCMA2 and NCMA3 and the cost of the acquisition of Block 5(c).
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SEGMENT PROFIT
INDIA
Three months ended Nine months ended
December 31, December 31,
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(thousands of U.S. dollars, except as
indicated) 2010 2009 2010 2009
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Natural gas revenue 76,174 67,630 242,162 156,010
Oil and condensate revenue (1) 18,481 8,236 58,809 22,038
Royalties (4,856) (3,942) (16,058) (10,183)
Profit petroleum (2,031) (2,689) (6,245) (7,894)
Operating expenses (8,369) (6,656) (21,980) (16,989)
Depletion, depreciation and accretion (23,966) (20,239) (76,354) (46,357)
Current income tax expense (9,412) (6,369) (32,739) (17,633)
Future income tax recovery 9,064 6,213 31,172 15,043
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Segment profit (2) 55,085 42,184 178,767 94,035
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Daily natural gas sales (Mcf/d) 205,428 179,151 217,324 135,829
Daily oil and condensate sales
(bbls/d) (1) 2,331 1,192 2,721 1,147
Operating costs ($/Mcfe) 0.41 0.38 0.34 0.43
Depletion rate ($/Mcfe) 1.16 1.17 1.16 1.17
----------------------------------------------------------------------------
(1) Production that is in inventory has not been included in the revenue or
cost amounts indicated.
(2) Segment profit is a non-GAAP measure as calculated above.
/T/
Segment profit from India includes the results from the Dhirubhai 1 and 3 gas field 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 quarter from the D6 block averaged 195 MMcf/d compared to 161 MMcf/d in the prior year's quarter. The increase in volumes contributed to a $12 million increase in revenues. The price received for gas sales from the D6 Block was consistent quarter-over-quarter at $3.95/Mcf. Year-to-date production averaged 204 MMcf/d compared to 115 MMcf/d in the prior year contributing to an $97 million increase in revenues.
Natural gas production from the Surat and Hazira fields decreased due to natural declines in these fields for a decrease of $4 million in revenues in the quarter compared to the prior year's quarter and a decrease of $10 million year-to-date.
Crude oil and condensate production from the MA field in the D6 Block increased with three additional wells that were put on production since the prior year's quarter. One of the wells is a gas well that has been producing approximately 260 bbls/d of condensate. The Company's crude oil and condensate sales from the D6 block for the quarter averaged 2,160 bbls/d compared to 1,000 bbls/d in the prior year's quarter. The Company's oil sales from the Hazira block for the quarter averaged 170 bbls/d compared to 192 bbls/d in the prior year's quarter. The Company received a price of $86.26/bbl in the quarter compared to $75.01/bbl in the prior year's quarter. The total net increase in sales volumes and the increase in sales price contributed to a $10 million increase in revenues in the quarter. Year-to-date production increased as a result of the additional wells on production contributing to a $37 million increase in revenues.
The increase in royalties is a result of the increase in revenues from the D6 Block since the prior year. Royalties applicable to production from the D6 Block are 5 percent for the first seven years of 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 net decrease in profit petroleum in the quarter was primarily a result of the inclusion of the 36-inch pipeline for cost recovery for the Hazira field. This was partially offset by profit petroleum payments on the increased revenues from the D6 block.
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 with respect to the D6 Block was $0.9 million and year-to-date was $2.7 million, which is one percent of revenues, and will continue at this level until the Company has recovered its costs.
For Hazira, in the quarter and the prior year's quarter, the government was entitled to 25 percent of the profits.
For Surat, the Company recovered its investment in the last quarter of the prior year and began sharing profits with the government at a rate of 20 percent.
Operating Expenses
Operating expenses increased during the quarter and year-to-date compared to the same periods in the prior year. On a unit-of-production basis, average operating expenses during the quarter are similar to the rate in the prior year's quarter. Year-to-date, the operating cost per Mcfe has decreased from the prior year's periods as a significant portion of the operating costs for the D6 Block are fixed.
Depletion, Depreciation and Accretion
The depletion rate for the quarter of $1.16/Mcfe is similar to the depletion rate in the prior year's quarter.
Income Taxes
The increase in current income tax expense is primarily a result of the current income tax expense related to minimum alternative tax on the profits from the D6 Block. Largely offsetting current taxes was a future income tax reduction for a tax credit available for future years related to minimum alternative tax paid for D6 in the current year.
The Company has a contingency related to income taxes as at December 31, 2010. Refer to the consolidated financial statements and notes for the period ended December 31, 2010 for a complete discussion of the contingency.
/T/
BANGLADESH
Three months ended Nine months ended
December 31, December 31,
----------------------------------------------------------------------------
(thousands of U.S. dollars, except as
indicated) 2010 2009 2010 2009
----------------------------------------------------------------------------
Natural gas and condensate revenue 17,124 15,717 46,193 44,992
Profit petroleum (5,787) (5,256) (15,584) (15,035)
Operating expenses (2,449) (1,865) (6,143) (4,573)
Depletion, depreciation and accretion (7,402) (6,710) (20,140) (19,214)
Current income tax expense - (13) (6) (33)
----------------------------------------------------------------------------
Segment profit (1) 1,486 1,873 4,320 6,137
----------------------------------------------------------------------------
Daily natural gas sales (Mcf/d) 71,437 70,951 65,497 68,278
Operating costs ($/Mcfe) 0.34 0.28 0.34 0.24
Depletion rate ($/Mcfe) 1.10 1.02 1.10 1.01
----------------------------------------------------------------------------
(1) Segment profit is a non-GAAP measure as calculated above. Segment profit
includes the results from Block 9 and Feni in Bangladesh. Production and
segment profit from Feni was not significant in the quarter or the prior
year's quarter.
/T/
Revenue, Profit Petroleum, Depletion and Operating Expenses
Natural gas revenue variance relates entirely to volumes. Volumes in the quarter of 71 MMcf/d were from Block 9, whereas volumes in the prior year's quarter also included production from the Feni field. Year-to-date, volumes were significantly impacted by pipeline maintenance that occurred in June 2010. Until November 2009, the Company received 66.67 percent of production from Block 9; however, the Government of Bangladesh's carried interest in the block has been repaid resulting in the Company's share of production now being 60 percent. Pursuant to the terms of the PSC for Block 9, the Government of Bangladesh was entitled to 61 percent of profit gas in the quarter and prior year's quarter. Profit petroleum expense decreased due to decreased revenues from Block 9.
Operating costs increased as a result of the pipeline maintenance costs incurred in the year and the start-up of the hydrocarbon dew-point control unit.
Depletion expense increased on a unit-of-production basis as a result of the change in estimate of future development costs.
NETBACKS
The following tables outline the Company's operating, funds from operations and earnings netbacks (all of which are non-GAAP measures) for the three and nine months ended December 31, 2010 and 2009:
/T/
Three months
ended December
31, 2010 2009
----------------------------------------------------------------------------
India Bangladesh Total India Bangladesh Total
(U.S. dollars) ($/Mcfe) ($/Mcfe) ($/Mcfe) ($/Mcfe) ($/Mcfe) ($/Mcfe)
----------------------------------------------------------------------------
Oil and natural
gas revenue 4.69 2.56 4.16 4.43 2.39 3.87
Royalties (0.24) - (0.18) (0.23) - (0.17)
Profit petroleum (0.10) (0.86) (0.30) (0.16) (0.75) (0.33)
Operating
expense (0.41) (0.34) (0.40) (0.38) (0.28) (0.36)
----------------------------------------------------------------------------
Operating
netback 3.94 1.36 3.28 3.66 1.36 3.01
----------------------------------------------------------------------------
Interest income
and other 0.02 0.40
Interest and
financing
expense (0.25) (0.16)
General and
administrative
expense (0.11) (0.09)
Realized foreign
exchange (loss)
gain (0.06) 0.01
Current income
tax expense (0.33) (0.27)
----------------------------------------------------------------------------
Funds from
operations
netback 2.55 2.90
----------------------------------------------------------------------------
Unrealized
foreign exchange
(loss) (0.01) (0.03)
Stock-based
compensation
expense (0.28) (0.24)
Gain (loss) on
short-term
investment 0.01 (1.12)
Future income
tax reduction 0.34 0.26
Depletion, depreciation
and accretion expense (1.19) (1.15)
----------------------------------------------------------------------------
Earnings netback 1.42 0.62
----------------------------------------------------------------------------
Nine months
ended December
31, 2010 2009
----------------------------------------------------------------------------
India Bangladesh Total India Bangladesh Total
(U.S. dollars) ($/Mcfe) ($/Mcfe) ($/Mcfe) ($/Mcfe) ($/Mcfe) ($/Mcfe)
----------------------------------------------------------------------------
Oil and natural
gas revenue 4.68 2.52 4.21 4.54 2.38 3.84
Royalties (0.25) - (0.19) (0.26) - (0.18)
Profit petroleum (0.10) (0.85) (0.27) (0.20) (0.81) (0.39)
Operating
expense (0.34) (0.34) (0.34) (0.43) (0.24) (0.37)
----------------------------------------------------------------------------
Operating
netback 3.99 1.33 3.41 3.65 1.33 2.90
----------------------------------------------------------------------------
Interest income
and other - 0.22
Interest and
financing
expense (0.28) (0.20)
General and
administrative
expense (0.08) (0.11)
Realized foreign
exchange gain
(loss) 0.01 (0.01)
Current income
tax expense (0.39) (0.31)
----------------------------------------------------------------------------
Funds from
operations
netback 2.67 2.49
----------------------------------------------------------------------------
Unrealized
foreign exchange
gain (loss) 0.01 (0.15)
Stock-based
compensation
expense (0.27) (0.26)
(Loss) gain on
short-term
investment (0.16) 0.19
Future income
tax reduction 0.38 0.26
Depletion, depreciation
and accretion expense (1.19) (1.15)
----------------------------------------------------------------------------
Earnings netback 1.44 1.38
----------------------------------------------------------------------------
/T/
The netback for India, Bangladesh and in total for the Company is a non-GAAP 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.
/T/
CORPORATE
Three months ended Nine months ended
December 31, December 31,
----------------------------------------------------------------------------
(thousands of U.S. dollars) 2010 2009 2010 2009
----------------------------------------------------------------------------
Revenues
Interest income and other 540 9,658 (64) 12,352
Expenses
Interest and financing 6,719 3,914 23,168 11,460
General and administrative 2,885 2,147 6,977 6,123
Foreign exchange loss (gain) 1,893 406 (1,751) 9,603
Stock based-compensation 7,461 5,754 21,359 14,841
(Gain) loss on short-term investments (166) 26,525 13,504 (11,163)
----------------------------------------------------------------------------
/T/
Interest Income and Other
Interest and other income of $0.9 million year-to-date is more than offset by an adjustment related to recording the award of the 36-inch pipeline. The results of the pipeline from inception to December 31, 2009 were audited and adjusted accordingly in the prior year periods.
Interest and Financing
Interest and financing expense in the quarter includes the interest portion of payments for the lease of the FPSO of $1.3 million (prior year's quarter - $1.5 million); interest expense on the long-term debt of $0.3 million (prior year's quarter - $2.5 million); and interest and accretion expense on the convertible debentures of $5.1 million (prior year's quarter - nil). Interest expense on the long-term debt decreased primarily as a result of the decrease in the debt balance.
The convertible debentures were issued at the end of December 2009 and there is no corresponding expense in the prior year.
/T/
Foreign Exchange
Three months ended Nine months ended
December 31, December 31,
----------------------------------------------------------------------------
(thousands of U.S. dollars) 2010 2009 2010 2009
----------------------------------------------------------------------------
Realized foreign exchange loss (gain) 1,694 (267) (1,218) 590
Unrealized foreign exchange loss
(gain) 199 673 (533) 9,013
----------------------------------------------------------------------------
Total foreign exchange loss (gain) 1,893 406 (1,751) 9,603
----------------------------------------------------------------------------
/T/
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 loss in the quarter and gain year-to-date arose primarily on the translation of the Indian-rupee denominated income tax receivable and future income tax asset to U.S. dollars.
There were additional foreign exchange losses in the quarter and year-to-date 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.
Stock-based Compensation
There was a net increase in stock-based compensation expense in the year. Stock-based compensation expense increased as a result of an increased number of options being granted primarily due to the Company's expansion in Indonesia and the increased fair value expense per stock option due to the fluctuations in the Company's stock price.
Short-term Investments
The gain on short-term investments during the quarter and the loss year-to-date were a result of marking the short-term investments to market value. In the prior year, there was an unrealized loss in the quarter and an unrealized gain in the year-to-date period as a result of the changes in market value during the periods.
The Company sold investments during the quarter and year-to-date resulting in realized losses of $2.7 million and $3.0 million respectively. The majority of these 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
The Company is generating funds from operations in excess of its capital expenditures. The decrease in the Company's cash position is a result of repayments of the Company's long-term debt. At December 31, 2010, the Company had total restricted and unrestricted cash of $96 million (March 31, 2010 - $246 million). Current restricted cash $18 million will be available for use prior to December 31, 2011 and $9 million will be available thereafter. The Company had a working capital surplus of $97 million at December 31, 2010 (March 31, 2010 - working capital surplus of $20 million), calculated as current assets less current liabilities.
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. After December 30, 2010, the Company may elect to convert all of the debentures into common shares at the conversion price in effect on that date, provided that the weighted average trading price for the prior 21 trading days exceeds Cdn$143.65 per share.
During the quarter, the Company advanced $27 million for a new venture that is awaiting government approval. The Company will disclose details once government approval is obtained. Should such approval not be obtained, Niko will be refunded any payments made. The advance has been included in accounts receivable and the cash outflow as a change in non-cash working capital from investing activities in the Company's financial statements for the quarter ended December 31, 2010.
During the quarter and year-to-date, the Company made principal repayments on the long-term debt of $99 million and $193 million, respectively. Since March 31, 2010, the Company's work commitments have been reduced by $21 million for capital spending for Indonesian blocks, $27 million for capital spending and a revision to a previous estimate for Madagascar, $7 million for capital spending in Kurdistan and by $3 million for capital spending in Trinidad. The Company was the successful bidder for interests in three additional blocks in Trinidad, subject to approval by the Government of Trinidad and Tobago, and if approved, the Company will have work commitments for these blocks. Subject to closing of the Company's purchase of Block 5(c) in Trinidad from Sonde Resources Corp., the Company will assume Sonde's liability under the performance guarantee provided for their Block MG license. Finally, the Company has entered into an agreement for a new venture, which is subject to government approval, and if approved, will have work commitments for the new venture. There were no other significant changes to the contractual obligations reported as at March 31, 2010.
The Company expects that cash on hand plus cash from operations will be sufficient to handle current capital obligations. 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 $3.95/Mcf until March 2014.
SUMMARY OF QUARTERLY RESULTS
The following tables set forth selected financial information of the Company for the eight most recently completed quarters to December 31, 2010:
/T/
Mar. 31, June 30, Sept. 30, Dec. 31,
Three months ended 2010 2010 2010 2010
----------------------------------------------------------------------------
Oil and natural gas revenue 110,622 116,501 119,215 111,912
Gain (loss) on short-term
investments 3,391 (7,826) (5,844) 166
Net income 38,667 39,756 41,041 38,294
Per share
Basic ($) 0.77 0.78 0.80 0.75
Diluted ($) 0.76 0.77 0.80 0.74
----------------------------------------------------------------------------
Mar. 31, June 30, Sept. 30, Dec. 31,
Three months ended 2009 2009 2009 2009
----------------------------------------------------------------------------
Oil and natural gas revenue 28,503 53,853 77,879 91,757
(Loss) gain on short-term
investment (311) 18,003 19,685 (26,525)
Net (loss) income (3,153) 20,441 45,043 14,637
Per share
Basic ($) (0.06) 0.41 0.91 0.29
Diluted ($) (0.06) 0.41 0.90 0.29
----------------------------------------------------------------------------
/T/
Net income has fluctuated over the quarters, due in part to changes in revenue, other income, operating expenses, depletion expense, interest expense, the value of investments and income taxes.
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 June 30, 2010.
Operating expense increased in the quarter ended June 30, 2009 with the commencement of gas production from the D6 block and increased in subsequent quarters as additional wells came on-stream and when gas production commenced from the MA oil field.
There were increases in depletion expense and current income taxes as a result of the increase in production described above. Future income tax recoveries were recorded from the quarter ended June 30, 2010 as a result of minimum alternative tax paid in India for the D6 Block, which are expected to be deductible against current income tax in the future.
Interest and other income in the quarter ended December 31, 2009 includes a $9.3 million adjustment related to a 36- inch pipeline that is connected to the Hazira facilities. Due to a dispute that was in arbitration, the Company had been assuming that it could not include the costs of the 36-inch pipeline for cost recovery, specifically, as a deduction in the calculation of profit petroleum. During the quarter, the Company was successful in arbitration and, as a result, pipeline costs will be eligible for cost recovery and the Company recognized the adjustment in the quarter. See note 12(g) to the interim consolidated financial statements for the complete discussion of a contingency related to the award of the 36-inch pipeline.
Interest expense on the long-term debt was capitalized until the commencement of gas production from the D6 Block. In the quarter ended June 30, 2009, interest expense on the long-term debt was expensed, decreasing net income. The interest expense on the long-term debt decreased with quarterly repayments commencing in June 2010. In the quarter ended March 31, 2010, interest and financing expense increased with interest paid and accretion on the convertible debentures. The expense will continue until December 30, 2012 when the debentures mature.
The Company made purchases of securities throughout the quarters. The short-term investments are recognized at fair value, which is the publicly quoted market value, and the Company recognizes gains and losses based on the changing market prices. The magnitude of the gains and losses compared to net income by quarter is displayed in the table above.
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 in 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 $0.2 million in the quarter and a loss of $13.5 million year-to-date was recognized in income. The Company realized previously recorded mark to market losses on the sale of investments of $2.7 million during the quarter and $3 million year-to-date. 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 interest and financing 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 ($15 million year-to-date). Interest expense of $0.3 million was recorded on the long-term debt during the quarter ($4 million year-to-date).
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, asset retirement obligation, 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, asset retirement provisions, 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, the asset retirement 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, 2010, available at www.sedar.com.
NEW ACCOUNTING STANDARDS
Effective April 1, 2011, the Company will adopt new accounting standards issued by the Canadian Institute of Chartered Accountants including sections 1582 "Business Combinations", 1601 "Consolidated Financial Statements" and 1602 "Non-controlling interests". These standards replace the existing business combination guidance and section 1600 "Consolidated Financial Statements". Earlier adoption is permitted, provided all three standards are adopted simultaneously.
Section 1582 requires equity instruments issued as part of the purchase consideration to be measured at the fair value of the shares at the acquisition date. In addition, the guidance generally requires all acquisition costs to be expensed whereas they could be capitalized as part of the purchase price under the previous standard. The new standard also requires non-controlling interests to be measured at fair value instead of carrying amounts as was the case under the previous standard. Section 1601 establishes the standards for the preparation of Consolidated Financial Statements.
Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination.
The adoption of these recommendations is not expected to have a material impact on the Company's consolidated financial statements.
FUTURE ACCOUNTING CHANGES
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. IFRS will replace Canadian generally accepted accounting principles. The first interim consolidated financial statements reported under IFRS for the Company will be for the quarter ending June 30, 2011.
The Company has developed a changeover plan to complete the transition to IFRS by April 1, 2011, which is the date of changeover for the Company. The conversion plan includes the following phases:
- Phase I Scoping and diagnostic - designating resources to the project, raising awareness and performing high level diagnostic assessments of accounting differences between IFRS and Canadian GAAP;
- Phase II Detailed Assessment - based on items identified in Phase I, performance of systematic and detailed analysis of gaps between the application of current accounting policies and IFRS and consider transitional policy choices. Assessment of impacts on the Company's debt agreements, management reporting systems and business activities;
- Phase III Design and implementation - implementation of all changes approved in the assessment phase. Parallel running of Fiscal 2011 financial results and the preparation of IFRS financial statements and disclosures; and
- Phase V Evaluation - review of processes and controls to make any required changes.
The Company has completed the scoping and diagnostic phase and has completed the analysis under Phase II. The Company has selected a number of accounting policies as described below. The audit committee has approved the Company's IFRS accounting policy selections that are discussed below. In some areas, the impacts of identified differences are still being determined. The Company's external auditors are in the process of completing the audit of the draft transitional balance sheet at April 1, 2010.
IFRS 1, "First-Time Adoption of International Financial Reporting Standards" (IFRS1), provides entities adopting IFRS for the first time with a number of optional exemptions to the general requirement for full retrospective application of IFRS. The potentially relevant exemptions that are available to the Company and the Company's expected use of the exemptions are as follows:
- an exemption from retroactively recognizing stock-based compensation expense in accordance with IFRS2 Share-based Payment on stock options that were granted on or before November 7, 2002 or those vesting prior to the date of transition to IFRSs. The Company has not determined if it will use this exemption.
- an exemption from retroactively restating the value of property, plant and equipment. An entity may elect to measure an item of property, plant and equipment at the date of transition at the value under its previous GAAP. The Company does not plan to make use of this exemption.
- an exemption from applying IFRIC1 Changes in Existing Decommissioning, Restoration and Similar Liabilities for changes that occurred before the date of transition to IFRSs. Instead, the Company may measure the liability at the date of transition to IFRSs, discount the liability to date of inception and calculate the accumulated depreciation on that amount.
The Company expects to make use of this exemption for its legal entities that are first time adopters of IFRS.
The following major differences between Canadian GAAP and IFRS could be significant to the Company:
- IFRS 2 Share-based Payment: Similar to Canadian GAAP, under IFRS2 the fair value of the compensation expense associated with the Company's stock option plan will be recognized as an expense with a corresponding increase in equity. The Company's stock options are equity settled. The Company currently estimates a forfeiture rate of nil percent and subsequently adjusts the expense as forfeitures occur. Under IFRS2, the Company will estimate a forfeiture rate that will be considered in the fair value of the stock options. The Company has not calculated the effect of the inclusion of a forfeiture rate pending a decision on whether or not it will use the IFRS1 exemption related to share-based payments.
- IFRS 6 Exploration for and Evaluation of Mineral Resources applies to the Company's exploration expenditures. The Company currently capitalizes expenditures prior to obtaining the legal right to explore under its Canadian GAAP policy while these costs will be expensed under IFRSs. In addition, there are options to capitalize or expense and amortize or not amortize exploration and evaluation costs. The Company plans to expense exploration and evaluation costs including geological and geophysical costs and the costs of unsuccessful wells in the exploration and evaluation phase. Successful wells in the exploration and evaluation phase will be capitalized pending evaluation and if determined commercially viable, will be transferred to development assets.
- IAS16 Property, Plant and Equipment applies to the Company's development and production assets. The Company currently capitalizes costs of oil and gas development and production assets that meet the definition of an asset under Canadian GAAP and depletes these costs by cost centre, which is a country, based on total proved reserves.
Under IFRS, the depletion rate will be calculated at the component level.
- IAS 36 Impairment of Assets requires the Company to assess whether there is any indication that an asset may be impaired at the end of each reporting period and on transition to IFRS. If any such indication exists, the Company will estimate the recoverable amount of the asset. Under Canadian GAAP, the impairment test is applied to the cost centre level, whereas it will be applied to cash generating units (CGUs) under IFRS. A CGU is the smallest group of assets capable of independently generating cash inflows. The Company has identified its CGUs and in general, an asset under one production sharing contract (PSC) will form a CGU. In addition, the Company plans to deplete the assets in a CGU based on total proved reserves.
- IAS 37 Provisions, Contingent Liabilities & Contingent Assets indicates how to identify and calculate these items, including asset retirement obligations (ARO). The discount rates applied to estimate future cashflows may be different under Canadian GAAP and IFRSs.
- IAS 12 Income Taxes differs from Canadian GAAP for purposes of recognizing deferred taxes, specifically in relation to intercompany transfers, asset acquisitions, foreign currency and other minor items.
Other areas that the Company has determined may have different results in the financial statements under IFRSs than under Canadian GAAP include leases and employee benefits. This list of areas impacted by IFRS should not be regarded as a comprehensive list of changes that will result from the transition to IFRS. The Company continues to monitor the development of standards.
In addition to accounting policy differences, the Company's transition to IFRS will impact information technology and data systems; internal control over financial reporting, disclosure controls and procedures, financial reporting expertise, and business activities as follows:
- IT systems - The Company's accounting software does not support the conversion to IFRS. The Company is maintaining the accounts under both Canadian GAAP and IFRS during the conversion process.
- Internal control over financial reporting (ICOFR) - The Company plans to assess the impact on internal control over financial reporting (ICOFR) in the last quarter of fiscal 2011. Some of the controls previously performed in Canada are expected to be performed in the branch offices and additional controls are expected to be implemented over the conversion process.
- Disclosure controls and procedures (DCP) - The Company anticipates providing information to stakeholders as per the requirements and recommendations of the security regulators through regulatory documents including this and future MD&As.
- Financial reporting expertise - The Company's staff responsible for financial reporting have been attending outside courses, seminars and updates on IFRS. The Company has completed in-house IFRS training for 2010 to update and augment the knowledge of key accounting and finance personnel. In addition, the Company attends an IFRS group with its peers to discuss accounting policy choices and implementation issues. Finally, the Company monitors exposure drafts and updates to IFRS on an ongoing basis.
- Business activities - The Company has convertible debentures with financial covenants. The agreement provides for the conversion to IFRS as acceptable accounting principles upon which to base the financial information used in the covenants and the financial information to be provided as per the agreements.
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 Canadian GAAP.
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 the internal controls over financial reporting during the quarter ended December 31, 2010 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
Due to a material weakness determined in preparation of the consolidated financial statements for the year ended March 31, 2010, the Company will consider additional controls required in the coming year.
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 December 31, 2010. 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.
/T/
OUTSTANDING SHARE DATA
At February 8, 2011, the Company had the following outstanding shares:
Number Cdn$
Amount (1)
----------------------------------------------------------------------------
Common shares 51,505,096 $1,340,022,000
Preferred shares nil nil
Stock options 4,284,202 -
----------------------------------------------------------------------------
(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 February 8, 2011 is $1,183,617,000.
INTERIM CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------------
(THOUSANDS OF U.S. DOLLARS) (UNAUDITED)
As at As at
December 31, 2010 March 31, 2010
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 69,935 $ 196,813
Restricted cash (note 2) 17,538 28,245
Short-term investments 18,541 32,081
Accounts receivable 80,232 47,706
Inventory 261 256
Prepaid expenses and deposits 1,640 724
----------------------------------------------------------------------------
188,147 305,825
Restricted cash (note 2) 8,616 21,026
Long-term investment 2,704 -
Long-term accounts receivable 29,436 31,128
Income tax receivable (note 12e) 25,400 23,240
Future income tax asset (note 3) 52,170 20,410
Property, plant and equipment 1,874,361 1,844,826
----------------------------------------------------------------------------
$ 2,180,834 $ 2,246,455
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 83,404 $ 123,547
Current tax payable 2,276 1,971
Current portion of capital lease obligation 5,721 5,357
Current portion of long-term debt (note 4) - 154,811
----------------------------------------------------------------------------
91,401 285,686
Asset retirement obligation 33,103 30,520
Capital lease obligation 54,098 58,472
Long-term debt (note 4) - 38,003
Convertible debentures 300,901 291,063
Future income tax liability 227,746 227,746
----------------------------------------------------------------------------
707,249 931,490
Shareholders' equity
Share capital (note 5) 1,145,751 1,107,163
Contributed surplus (note 6) 62,631 48,397
Equity component of convertible debentures 14,765 14,765
Accumulated other comprehensive income
(note 7) 6,480 12,220
Retained earnings 243,958 132,420
----------------------------------------------------------------------------
1,473,585 1,314,965
----------------------------------------------------------------------------
$ 2,180,834 $ 2,246,455
----------------------------------------------------------------------------
Segmented information (note 10)
Guarantees (note 11)
Contingencies (note 12)
See accompanying Notes to Interim Consolidated Financial Statements.
INTERIM CONSOLIDATED STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME (LOSS)
AND RETAINED EARNINGS
----------------------------------------------------------------------------
(THOUSANDS OF U.S. DOLLARS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
Three months ended Nine months ended
December 31, December 31,
2010 2009 2010 2009
----------------------------------------------------------------------------
Revenue
Oil and natural gas $ 111,912 $ 91,757 $ 347,628 $ 223,489
Royalties (4,874) (3,971) (16,109) (10,243)
Profit petroleum (7,818) (7,945) (21,830) (22,928)
Interest income and other 540 9,658 (64) 12,532
----------------------------------------------------------------------------
99,760 89,499 309,625 202,850
Expenses
Operating 10,862 8,566 28,261 21,678
Interest and financing (note 8) 6,719 3,957 23,168 11,597
General and administrative 2,885 2,147 6,977 6,123
Foreign exchange loss (gain) 1,893 406 (1,751) 9,603
Stock-based compensation 7,461 5,754 21,359 14,841
(Gain) loss on short-term
investment (166) 26,525 13,504 (11,163)
Depletion, depreciation and
accretion 31,917 27,387 97,973 67,021
----------------------------------------------------------------------------
61,571 74,742 189,491 119,700
----------------------------------------------------------------------------
Income before income taxes 38,189 14,757 120,134 83,150
----------------------------------------------------------------------------
Income taxes
Current income tax expense 8,959 6,333 32,215 18,072
Future income tax reduction
(note 3) (9,064) (6,213) (31,172) (15,043)
----------------------------------------------------------------------------
(105) 120 1,043 3,029
Net income $ 38,294 $ 14,637 $ 119,091 $ 80,121
----------------------------------------------------------------------------
Net income per share (note 9)
Basic $ 0.75 $ 0.29 $ 2.33 $ 1.62
Diluted $ 0.74 $ 0.29 $ 2.32 $ 1.60
----------------------------------------------------------------------------
Comprehensive income:
Net Income $ 38,294 $ 14,637 $ 119,091 $ 80,121
Foreign currency translation
(loss) gain (8,324) 4,321 (5,740) 20,728
----------------------------------------------------------------------------
Comprehensive income $ 29,970 $ 18,958 $ 113,351 $ 100,849
----------------------------------------------------------------------------
Retained earnings, beginning
of period $ 208,763 $ 68,479 $ 132,420 $ 5,845
Net income 38,294 14,637 119,091 80,121
Dividends paid (3,099) (1,459) (7,553) (4,309)
----------------------------------------------------------------------------
Retained earnings, end
of period $ 243,958 $ 81,657 $ 243,958 $ 81,657
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements.
INTERIM CONSOLIDATED STATEMENTS OF CASH FLOWS
----------------------------------------------------------------------------
(THOUSANDS OF U.S. DOLLARS) (UNAUDITED)
Three months ended Nine months ended
December 31, December 31,
2010 2009 2010 2009
----------------------------------------------------------------------------
Cash provided by (used in):
Operating activities
Net income $ 38,294 $ 14,637 $ 119,091 $ 80,121
Add items not involving cash
from operations:
Unrealized foreign exchange
loss (gain) 199 673 (533) 9,013
(Gain) loss on short-term
investments (166) 26,525 13,504 (11,163)
Accretion of convertible
debentures 1,252 - 3,512 -
Stock-based compensation 7,461 5,754 21,359 14,841
Depletion, depreciation and
accretion 31,917 27,387 97,973 67,021
Future income tax reduction (9,064) (6,213) (31,172) (15,043)
Other - 43 14 228
Change in non-cash working
capital (15,012) (13,223) (9,665) (24,612)
Change in long-term accounts
receivable (652) (2,802) (787) (4,693)
----------------------------------------------------------------------------
54,229 52,781 213,296 115,713
----------------------------------------------------------------------------
Financing activities
Proceeds from issuance of
shares (note 5) 15,129 20,417 29,673 36,204
Convertible debentures - 297,590 - 297,590
Dividends paid (3,099) (1,459) (7,553) (4,309)
Repayment of long-term debt (99,089) - (192,814) -
Reduction in capital lease
obligations (1,375) (1,263) (3,962) (3,300)
----------------------------------------------------------------------------
(88,434) 315,285 (174,656) 326,185
----------------------------------------------------------------------------
Investing activities
Addition of property, plant
and equipment (26,288) (24,053) (122,882) (185,367)
Corporate acquisition - (281,637) - (281,637)
Restricted cash contributions (500) (6,640) (36,589) (13,059)
Restricted cash released 45,153 7,006 59,705 178,309
Addition to short-term
investment - - (6,135) -
Addition to long-term investment (1,984) - (2,704) -
Disposition of short-term
Investment 888 - 6,306 1,054
Change in non-cash working
capital (46,894) (37,243) (63,112) (34,702)
----------------------------------------------------------------------------
(29,625) (342,567) (165,411) (335,402)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Change in cash and cash
equivalents (63,830) 25,499 (126,771) 106,496
----------------------------------------------------------------------------
Effect of foreign currency
translation on cash and cash
equivalents 595 337 (107) 2,383
Cash and cash equivalents,
beginning of period 133,170 114,232 196,813 31,189
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 69,935 $ 140,068 $ 69,935 $ 140,068
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements.
/T/
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the nine months ended December 31, 2010 (unaudited). All tabular amounts are in thousands of U.S. dollars except per share amounts, numbers of shares and stock options, stock option and share prices, and certain other figures as indicated.
1. BASIS OF PRESENTATION
The interim consolidated financial statements include the accounts of Niko Resources Ltd. ("the Company") and all of its subsidiaries. The majority of the exploration, development and production activities of the Company are conducted jointly with others and, accordingly, these consolidated financial statements reflect only the Company's proportionate interest in such activities. The interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles. The interim consolidated financial statements have been prepared following the same accounting policies and methods of application as the audited consolidated financial statements for the fiscal year ended March 31, 2010. The disclosures provided herein are incremental to those included with the annual consolidated financial statements and the notes thereto for the year ended March 31, 2010. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto for the year ended March 31, 2010.
Certain comparative figures have been reclassified to conform to the current year presentation.
/T/
2. RESTRICTED CASH
----------------------------------------------------------------------------
As at As at
December 31, March 31,
2010 2010
----------------------------------------------------------------------------
Current portion of restricted cash
Guarantees (1) $ 17,538 $ 21,838
Funds restricted under the facility agreement (2) - 6,407
----------------------------------------------------------------------------
Total $ 17,538 $ 28,245
----------------------------------------------------------------------------
Non-current portion of restricted cash
Guarantees (1) $ 3,545 $ 1,500
Funds restricted under the facility agreement (2) - 14,489
Site restoration fund (3) 5,071 5,037
----------------------------------------------------------------------------
Total $ 8,616 $ 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
11 for details of the guarantees.
(2) The cash that was restricted under the facility agreement was released
upon repayment of the balance of 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 asset retirement 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.
3. FUTURE INCOME TAX ASSET
----------------------------------------------------------------------------
Nine months ended Year ended
December 31, 2010 March 31, 2010
----------------------------------------------------------------------------
Future income tax asset, beginning of period $ 20,410 $ -
Future income tax reduction (1) 31,172 20,410
Foreign exchange 588 -
----------------------------------------------------------------------------
Future income tax asset, end of period $ 52,170 $ 20,410
----------------------------------------------------------------------------
(1) The future income tax reduction is tax credit available for future years
related to minimum alternative tax paid for D6 in the current period.
/T/
4. LONG-TERM DEBT
The Company repaid the outstanding balance of its long-term debt during the quarter of $99 million. Restricted cash of $45 million that was restricted in accordance with the facility agreement was released during the quarter.
5. SHARE CAPITAL
(a) Authorized
Unlimited number of common shares
Unlimited number of preferred shares
/T/
(b) Issued
Nine months ended Year ended
December 31, 2010 March 31, 2010
Number Amount Number Amount
----------------------------------------------------------------------------
Common shares
Balance, beginning of
period 50,818,110 $1,107,163 49,298,133 $ 997,189
Shares issued for property
acquisition - - 397,379 39,691
Stock options exercised 552,689 29,673 1,122,598 54,997
Transferred from contributed
surplus on exercise of stock
options - 8,915 - 15,286
----------------------------------------------------------------------------
Balance, end of period 51,370,799 $1,145,751 50,818,110 $ 1,107,163
----------------------------------------------------------------------------
/T/
(c) Stock Options
The Company has reserved for issue 5,137,080 common shares for granting under stock options to directors, officers, and employees. The options become 100 percent 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:
/T/
Nine months ended Year ended
December 31, 2010 March 31, 2010
----------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price (Cdn$) Options Price (Cdn$)
----------------------------------------------------------------------------
Outstanding, beginning of
period 4,056,714 75.88 4,030,750 64.69
Granted 671,750 101.48 1,530,312 92.18
Forfeited (110,188) 87.74 (282,375) 90.25
Expired (73,025) 93.05 (99,375) 92.72
Exercised (552,689) 54.76 (1,122,598) 52.80
----------------------------------------------------------------------------
Outstanding, end of period 3,992,562 82.47 4,056,714 75.88
----------------------------------------------------------------------------
Exercisable, end of period 712,621 69.45 730,399 58.21
----------------------------------------------------------------------------
/T/
The following table summarizes stock options outstanding and exercisable under the plan at December 31, 2010:
/T/
Outstanding Options Exercisable Options
----------------------------------------------------------------------------
Weighted Weighted
Remaining Average Average
Life Exercise Exercise
Exercise Price Options (Years) Price (Cdn$) Options Price (Cdn$)
----------------------------------------------------------------------------
$ 47.11 - $ 49.99 798,565 2.4 49.61 156,249 49.62
$ 50.00 - $ 59.99 132,000 0.4 53.67 116,875 53.76
$ 60.00 - $ 69.99 258,625 1.3 62.89 145,250 63.14
$ 70.00 - $ 79.99 58,250 2.8 74.91 500 75.75
$ 80.00 - $ 89.99 685,185 2.3 85.82 96,747 81.24
$ 90.00 - $ 99.99 1,422,000 2.5 95.87 196,750 93.31
$ 100.00 - $109.99 608,812 3.7 104.40 250 105.47
$ 110.00 - $112.64 29,125 3.5 111.12 - -
----------------------------------------------------------------------------
3,992,562 2.5 82.47 712,621 69.45
----------------------------------------------------------------------------
6. CONTRIBUTED SURPLUS
Nine months ended Year ended
December 31, 2010 March 31, 2010
----------------------------------------------------------------------------
Contributed surplus, beginning of
period $ 48,397 $ 41,494
Stock-based compensation 23,149 22,189
Stock options exercised (8,915) (15,286)
----------------------------------------------------------------------------
Contributed surplus, end of period $ 62,631 $ 48,397
----------------------------------------------------------------------------
7. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Nine months ended Year ended
December 31, 2010 March 31, 2010
----------------------------------------------------------------------------
Accumulated other comprehensive income
(loss), beginning of period $ 12,220 $ (2,406)
Foreign currency translation (loss) gain (5,740) 14,626
----------------------------------------------------------------------------
Accumulated other comprehensive income,
end of period $ 6,480 $ 12,220
----------------------------------------------------------------------------
8. INTEREST AND FINANCING EXPENSE
Three months ended Nine months ended
December 31, December 31,
2010 2009 2010 2009
----------------------------------------------------------------------------
Interest expense related to capital
lease $ 1,335 $ 1,449 $ 4,045 $ 3,938
Interest expense on long-term debt 277 2,465 4,135 7,431
Interest expense on convertible
debentures 3,855 - 11,462 -
Accretion expense on convertible
debentures 1,252 - 3,512 -
Other - 43 14 228
----------------------------------------------------------------------------
Interest and financing expense $ 6,719 $ 3,957 $ 23,168 $ 11,597
----------------------------------------------------------------------------
9. EARNINGS PER SHARE
The following table summarizes the weighted average number of common shares
used in calculating basic and diluted earnings per share:
Three months ended Nine months ended
December 31, December 31,
2010 2009 2010 2009
----------------------------------------------------------------------------
Weighted average number of
common shares outstanding
- basic 51,136,407 49,740,300 51,010,008 49,594,939
- diluted 51,513,241 50,309,059 51,399,451 50,016,765
----------------------------------------------------------------------------
/T/
Options totaling 1,224,187 for the quarter ended and 582,437 for the nine months ended December 31, 2010 (1,160,188 for the quarter and 1,661,688 for the nine months ended December 31, 2009) were considered anti-dilutive as they were out-of-the money and were therefore excluded from the calculation of diluted per share amounts.
The convertible debentures were anti-dilutive for the period ended December 31, 2010 and have been excluded from the calculation of diluted earnings per share above. The convertible debentures were issued during the year ended March 31, 2010.
10. SEGMENTED INFORMATION
The Company's operations are conducted in one business sector, the oil and natural gas industry. 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 used in the preparation of the information of the reportable segments are the same as those described in the summary of significant accounting policies. Revenues, segment profits and capital additions by reportable segments are as follows:
/T/
Three months ended December 31, 2010
----------------------------------------------------------------------------
Segment Capital
Segment Revenue Profit (Loss) Additions
----------------------------------------------------------------------------
Bangladesh $ 17,124 $ 1,486 $ 1,005
India 94,655 55,085 3,452
Indonesia - - 9,401
Kurdistan - - 6,160
Madagascar - - 1,326
Pakistan - - 708
Trinidad - - 4,521
All other (1) 133 (25) 671
----------------------------------------------------------------------------
Total $ 111,912 $ 56,546 $ 27,244
----------------------------------------------------------------------------
Three months ended December 31, 2009
----------------------------------------------------------------------------
Segment Capital
Segment Revenue Profit (Loss) Additions
----------------------------------------------------------------------------
Bangladesh $ 15,717 $ 1,873 $ 557
India 75,866 42,184 10,026
Indonesia - - 487,444
Kurdistan - - 1,591
Madagascar - - 1,594
Pakistan - - 1,024
Trinidad - - 3,923
All other (1) 174 (289) 182
----------------------------------------------------------------------------
Total $ 91,757 $ 43,768 $ 506,341
----------------------------------------------------------------------------
(1) Revenues included in All other are from Canadian oil sales.
Nine months ended December 31, 2010
----------------------------------------------------------------------------
Segment Capital
Segment Revenue Profit (Loss) Additions
----------------------------------------------------------------------------
Bangladesh $ 46,193 $ 4,320 $ 429
India 300,971 178,766 38,009
Indonesia - - 36,206
Kurdistan - - 16,806
Madagascar - - 23,516
Pakistan - - 1,843
Trinidad - - 7,602
All other (1) 464 (674) 1,419
----------------------------------------------------------------------------
Total $ 347,628 $ 182,412 $ 125,830
----------------------------------------------------------------------------
Nine months ended December 31, 2009
----------------------------------------------------------------------------
Segment Capital
Segment Revenue Profit (Loss) Additions
----------------------------------------------------------------------------
Bangladesh $ 44,992 $ 6,137 $ 9,335
India 178,048 94,035 105,028
Indonesia - - 504,744
Kurdistan - - 40,420
Madagascar - - 2,309
Pakistan - - 1,336
Trinidad - - 3,923
All other (1) 449 (1,582) 560
----------------------------------------------------------------------------
Total $ 223,489 $ 98,590 $ 667,655
----------------------------------------------------------------------------
(1) Revenues included in All other are from Canadian oil sales.
As at December 31, 2010 As at March 31, 2010
----------------------------------------------------------------------------
Property, Property,
Plant and Plant and
Segment Equipment Total Assets Equipment Total Assets
----------------------------------------------------------------------------
Bangladesh $ 102,869 $ 137,400 $ 122,536 $ 159,433
India 975,225 1,100,342 1,013,691 1,147,703
Indonesia 573,439 597,167 537,233 562,071
Kurdistan 84,398 84,983 67,592 68,433
Madagascar 33,006 33,197 9,490 9,584
Pakistan 26,490 26,540 24,647 24,665
Trinidad 72,745 74,904 65,143 67,706
All other 6,189 126,301 4,494 206,860
----------------------------------------------------------------------------
Total $ 1,874,361 $ 2,180,834 $ 1,844,826 $ 2,246,455
----------------------------------------------------------------------------
/T/
The reconciliation of the segment profit to net income as reported in the consolidated financial statements is as follows:
/T/
Three months ended Nine months ended
December 31, December 31,
----------------------------------------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Segment profit $ 56,546 $ 43,768 $ 182,412 $ 98,590
Interest income and other 540 9,658 (64) 12,532
Interest and financing expense (6,719) (3,957) (23,168) (11,597)
General and administrative expenses (2,885) (2,147) (6,977) (6,123)
Foreign exchange (loss) gain (1,893) (406) 1,751 (9,603)
Stock-based compensation expense (7,461) (5,754) (21,359) (14,841)
Gain (loss) on short-term
investments 166 (26,525) (13,504) 11,163
----------------------------------------------------------------------------
Net income $ 38,294 $ 14,637 $ 119,091 $ 80,121
----------------------------------------------------------------------------
11. GUARANTEES
As at As at
December 31, 2010 March 31, 2010
----------------------------------------------------------------------------
Performance security guarantees
included in restricted cash (1)
Cauvery - India $ 804 $ 804
D4 - India 3,234 984
Indonesia 17,045 21,550
Performance security guarantees not
included in restricted cash (2)
Indonesia 2,454 2,454
Madagascar - 1,178
----------------------------------------------------------------------------
Total guarantees $ 23,537 $ 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.
/T/
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.
12. CONTINGENCIES
(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:
/T/
Petitioner Request High Court Ruling
----------------------------------------------------------------------------
That the Joint Venture Agreement for The Joint Venture Agreement for Feni
the Feni and Chattak fields be and Chattak fields is valid.
declared null and illegal.
----------------------------------------------------------------------------
That the government realize from the The compensation claims should be
Company compensation for the natural decided by the lawsuit described in
gas lost as a result of the note (b) below or by mutual
uncontrolled flow problems as well agreement.
as for damage to the surrounding
area.
----------------------------------------------------------------------------
That Petrobangla withhold future Petrobangla to withhold future
payments to the Company relating to payments to the Company related to
production from the Feni field production from the Feni field until
($27.9 million as at December 31, the lawsuit described in note (b)
2010). below is resolved or both parties
agree to a settlement.
----------------------------------------------------------------------------
That all bank accounts of the Company The ruling did not address this
maintained in Bangladesh be frozen. issue, therefore the previous ruling
stands. Funds in the Company's bank
accounts maintained in Bangladesh
cannot be repatriated pending
resolution of the lawsuit described
in note (b) below.
----------------------------------------------------------------------------
/T/
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 363,185,000 ($5.3 million) for 3 Bcf of free natural gas delivered from the Feni field as compensation for the burnt natural gas;
(ii) taka 713,052,000 ($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 ($12.2 million) for environmental damages, an amount subject to be increased upon further assessment;
(iv) taka 5,447,768,000 ($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.
(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 2006. 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. The assessment for the 2007 taxation year is in progress.
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 taxation year, 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 record a tax expense of approximately $65 million, pay additional taxes of $40 million and write off approximately $25 million of the net income tax receivable. In addition, the Company could be obligated to pay interest on taxes for the past periods related to the periods assessed up to and including fiscal 2006.
(f) In January 2009, the Company received confirmation from Canadian authorities that they are engaged in a formal investigation into allegations of improper payments in Bangladesh by either the Company or its subsidiary in Bangladesh. No charges have been laid against either the Company or its subsidiary in Bangladesh. The Company believes that the outcome of the investigation and associated costs, if any, to the Company are not determinable and no amounts have been recorded in these consolidated financial statements. Costs, if any, will be recorded in the period of determination.
(g) 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 accounts receivable of $6 million.
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CORPORATE INFORMATION
OFFICERS AND DIRECTORS
Edward S. Sampson
Chairman of the Board, President and
Chief Executive Officer
Murray Hesje
VP Finance and Chief Financial Officer
William T. Hornaday, B.Sc., P.ENG.
Chief Operating Officer, Director
C.J. (Jim) Cummings, LLB
Director
Walter DeBoni, B.Sc., MBA, P.ENG.
Director
Conrad P. Kathol, B.Sc., P.ENG.
Director
Wendell W. Robinson, BBA, MA, CFA
Director
SOLICITORS
Gowling LaFleur Henderson, LLP
Calgary, Alberta
REGISTRAR AND TRANSFER AGENT
Computershare
Calgary, Alberta
Toronto, Canada
INVESTOR RELATIONS
Edward S. Sampson
Chairman of the Board, President and
Chief Executive Officer
Suite 4600, 400 - 3rd Avenue S.W.
Calgary, Alberta
Canada T2P 4H2
Tel: 403-262-1020
Fax: 403-263-2686
Email: niko@nikoresources.com
Website: www.nikoresources.com
PRIMARY BANKING INSTITUTION
Royal Bank of Canada
Calgary, Alberta
London, United Kingdom
EVALUATION ENGINEERS
Ryder Scott Company
Calgary, Alberta
AUDITORS
KPMG LLP
Calgary, Alberta
LISTING AND TRADING SYMBOL
Toronto Stock Exchange
Symbol: NKO
www.nikoresources.com
Suite 4600, 400 - 3rd Avenue SW
Calgary, Alberta T2P 4H2
Tel: 403-262-1020
Fax: 403-263-2686
ABBREVIATIONS
Bcf billion cubic feet
Bbl barrel
CICA Canadian Institute of Chartered Accountants
FPSO floating production, storage and off-loading vessel
GAAP generally accepted accounting principles
GPSA gas purchase and sale agreement
IM investment multiple
JVA joint venture agreement
LIBOR London interbank offered rate
Mcf thousand cubic feet
Mcfe thousand cubic feet equivalent
MD&A management's discussion and analysis
MMBtu million British thermal units
MMcf million cubic feet
PSA production sharing agreement
PSC production sharing contract
/d per day
All amounts are in thousands of U.S. dollars unless otherwise stated.
All thousand cubic feet equivalent (Mcfe) figures are based on the ratio of
1bbl:6Mcf.
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