CALGARY, ALBERTA — (Marketwire) — 02/14/13 — Niko Resources Ltd. (TSX: NKO) (“Niko” or the “Company”) is pleased to report its financial and operating results, including consolidated financial statements and notes thereto, as well as its managements– discussion and analysis, for the three and nine month periods ended December 31, 2012. The operating results are effective February 13, 2013. All amounts are in U.S. dollars unless otherwise indicated and all amounts are reported using International Financial Reporting Standards unless otherwise indicated.
PRESIDENT–S MESSAGE TO THE SHAREHOLDERS
In the third quarter of fiscal 2013, the Company launched its multi-year deepwater exploration drilling program in Indonesia and repaid its Cdn$310 million convertible debentures due December 2012, primarily using the net proceeds from successful offerings of common shares and convertible notes. The business environment in India appears to have improved significantly as evidenced by the release of a government-appointed committee–s report on domestic gas pricing and the restart of planned development and exploration activities for the D6 Block in India.
In December 2012, the Rangarajan Committee provided its report to the Government of India that included a recommendation on a pricing mechanism for natural gas produced in India and this recommendation is currently being reviewed by the Government for approval. Based on current inputs into the pricing formula, the price for natural gas sales from the Company–s assets in India would increase to approximately $8 – $8.50/MMBtu, compared to $4.20/MMBtu for current natural gas sales from the D6 Block. The field development plan for an additional development area in the D6 Block was submitted in January 2013 and the plan for a development in the NEC-25 Block is to be submitted by March 2013. With field development plans submitted and increased clarity on future gas prices for the developments, the Company expects to book a substantial portion of its approximately 600 bcf of estimated contingent resources as reserves, effective March 31, 2013.
The operational efficiency of Niko–s drilling team in Indonesia has continued to be outstanding, with the first two wells in the multi-year program drilled safely, significantly under budget and much faster than anticipated. Changes made by Niko for the Ocean Monarch rig have resulted in significant reductions in time and costs for wells drilled in this program. These improvements and the Company–s portfolio approach across its extensive portfolio of exploration prospects in its significant acreage position in Indonesia, will allow the Company to benefit from economies of scale, increased flexibility to move between drilling locations at lower cost, and increased statistical likelihood of success.
The Company–s planned capital spending is flexible and is focused on development activities in India and exploration activities in Indonesia and Trinidad. The Company is currently in negotiations with various third parties regarding farm-outs, non-core asset dispositions and other arrangements, and the Company is confident that the combination of ongoing funds from operations from its producing properties and the proceeds it expects to receive from some or all of the farm-outs, asset dispositions and other arrangements that the Company has been working on will provide appropriate funds for the Company–s capital spending plans.
Edward S. Sampson – President and Chief Executive Officer, Niko Resources Ltd.
REVIEW OF OPERATIONS AND GUIDANCE
Sales Volumes
Total sales volumes for the third quarter averaged 145 MMcfe/d compared to 173 MMcfe/d for the second quarter of fiscal 2013, primarily due to anticipated natural declines and scheduled maintenance in the D6 Block in India and temporary curtailment of production from one well in Block 9 in Bangladesh.
Sales volumes for the fourth quarter of fiscal 2013 are forecast to be approximately 130 MMcfe/d. For fiscal 2014, the Company is currently working with its partners to finalize workover and development plans for the Dhirubhai 1 and 3 and MA fields in the D6 Block in India and the Bangora field in Block 9 in Bangladesh, respectively, and will provide volume guidance once these plans have been finalized.
Funds from Operations
Funds from operations for the third quarter were $27 million compared to $34 million for the second quarter of fiscal 2013, primarily due to the variances in sales volumes described above.
For the fourth quarter of fiscal 2013, funds from operations are forecast to be approximately $25 million. Guidance for fiscal 2014 will be provided when workover and development plans for the Company–s producing assets have been finalized.
Capital Expenditures, net of Proceeds of Farm-outs and Other Arrangements
Capital expenditures, net of proceeds of farm-outs and other arrangements, totaled $78 million for the third quarter. Spending in the quarter related primarily to exploration activities in Indonesia and Trinidad and Tobago.
For the fourth quarter of fiscal 2013, capital expenditures, net of proceeds of farm-outs and other arrangements, are forecast to be approximately $25 million, with spending focused primarily on exploration activities in Indonesia. The level of capital spending for fiscal 2014 is flexible and decisions on spending will be made as the year progresses.
MANAGEMENT–S DISCUSSION AND ANALYSIS
The following discussion and analysis is a review of the Company–s financial condition and results of operations as at and for the three and nine months ended December 31, 2012. The Company–s financial statements are prepared in accordance with International Reporting Standards (“IFRS”) and all amounts are in thousands of United States dollars unless specified otherwise. This discussion should be read in conjunction with the audited consolidated financial statements for the year ended March 31, 2012. This MD&A is effective February 13, 2013. Additional information relating to the Company, including the Company–s Annual Information Form (AIF), is available on SEDAR at .
The term “the quarter” used throughout this Management–s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations and in all cases refers to the period from October 1, 2012 through December 31, 2012. The term “prior year–s quarter” used throughout this MD&A for comparative purposes and refers to the period from October 1, 2011 through December 31, 2011.
The term “the period” used throughout this Management–s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations and in all cases refers to the period from April 1, 2012 through December 31, 2012. The term “prior year–s period” used throughout this MD&A for comparative purposes and refers to the period from April 1, 2011 through December 31, 2011.
The Company–s fiscal year is the 12-month period ended March 31. The terms “Fiscal 2012” and “prior year” is used throughout this MD&A and in all cases refers to the period from April 1, 2011 through March 31, 2012. The terms “Fiscal 2013”, “current year” and “the year” are used throughout the MD&A and in all cases refer to the period from April 1, 2012 through March 31, 2013.
Mcfe (thousand cubic feet equivalent) is a measure used throughout the MD&A. Mcfe is derived by converting oil and condensate to natural gas in the ratio of 1 bbl: 6 Mcf. Mcfe may be misleading, particularly if used in isolation. A Mcfe conversion ratio of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. MMBtu (million British thermal units) is a measure used in the MD&A. It refers to the energy content of natural gas (as well as other fuels) and is used for pricing purposes. One MMBtu is equivalent to 1 Mcfe plus or minus up to 20 percent, depending on the composition and heating value of the natural gas in question.
Cautionary Statement Regarding Forward-Looking Statements and Information
Certain statements in this MD&A are “forward-looking statements” or “forward-looking information” within the meaning of applicable securities laws, herein “forward looking statements” or “forward looking information”. Forward-looking information is frequently characterized by words such as “plan,” “expect,” “project,” “intend,” “believe,” “anticipate,” “estimate,” “scheduled,” “potential” or other similar words, or statements that certain events or conditions “may,” “should” or “could” occur. Forward-looking information is based on the Company–s expectations regarding its future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities. Such forward-looking information reflects the Company–s current beliefs and assumptions and is based on information currently available to it. Forward-looking information involves significant known and unknown risks and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking information including risks associated with the impact of general economic conditions, industry conditions, governmental regulation, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and the Company–s ability to access sufficient capital from internal and external sources, the risks discussed under “Risk Factors” and elsewhere in this report and in the Company–s public disclosure documents, and other factors, many of which are beyond its control. Although the forward-looking information contained in this report is based upon assumptions which the Company believes to be reasonable, it cannot assure investors that actual results will be consistent with such forward-looking information. Such forward-looking information is presented as of the date of this MD&A, and the Company assumes no obligation to update or revise such information to reflect new events or circumstances, except as required by law. Because of the risks, uncertainties and assumptions inherent in forward-looking information, you should not place undue reliance on this forward-looking information. See also “Risk Factors.”
Specific forward-looking information contained in this MD&A may include, among others, statements regarding:
The forward-looking statements contained in this MD&A are based on certain key expectations and assumptions made by us, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities and the availability and cost of labor and services. Although the Company believes that the expectations reflected in the forward-looking statements in this MD&A are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and natural gas industry in general, such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation, as well as the other risk factors identified under “Risk Factors” herein. Statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. You are cautioned that the foregoing list of factors and risks is not exhaustive.
The Company prepares production forecasts taking into account historical and current production, and actual and planned events that are expected to increase or decrease production and production levels indicated in its reserve reports.
The Company prepares capital spending forecasts based on internal budgets for operated properties, budgets prepared by the Company–s joint venture partners, when available, for non-operated properties, field development plans and actual and planned events that are expected to affect the timing or amount of capital spending.
The Company prepares operating expense forecasts based on historical and current levels of expenses and actual and planned events that are expected to increase or decrease production and/or the associated expenses.
The Company discloses the nature and timing of expected future events based on budgets, plans, intentions and expected future events for operated properties. The nature and timing of expected future events for non-operated properties are based on budgets and other communications received from joint venture partners.
The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis when the change is material and update reserve estimates on an annual basis. See “Risk Factors” for discussion of uncertainties and risks that may cause actual events to differ from forward-looking information provided in this report. The information contained in this report, including the information provided under the heading “Risk Factors,” identifies additional factors that could affect the Company–s operating results and performance. The Company urges you to carefully consider those factors and the other information contained in this report.
The forward-looking statements contained in this report are made as of the date hereof and, unless so required by applicable law. The Company undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this report are expressly qualified by this cautionary statement.
Non-IFRS Measures
The selected financial information presented throughout this MD&A is prepared in accordance with IFRS, except for “funds from operations”, “operating netback”, “funds from operations netback”, “earnings netback”, “segment profit” and “working capital”. These non-IFRS financial measures, which have been derived from financial statements and applied on a consistent basis, are used by management as measures of performance of the Company. These non-IFRS measures should not be viewed as substitutes for measures of financial performance presented in accordance with IFRS or as a measure of a company–s profitability or liquidity. These non-IFRS measures do not have any standardized meaning prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other companies.
The Company examined funds from operations to assess past performance and to help determine its ability to fund future capital projects and investments. Funds from operations is calculated as cash flows from operating activities prior to the change in operating non-cash working capital, the change in long-term accounts receivable and exploration and evaluation costs expensed to the statement of comprehensive income.
The Company examined operating netback, funds from operations netback, earnings netback and segment profit to evaluate past performance by segment and overall.
OVERALL PERFORMANCE
Funds from Operations
Oil and natural gas revenue during the three months ended December 31, 2012 decreased $28 million compared to the prior year–s quarter. Oil and natural gas revenue during the nine months ended December 31, 2012 decreased $90 million compared to the prior year–s period. These decreases were primarily due to lower natural gas and crude oil sales from the D6 Block along with an adjustment to profit petroleum expense at the Hazira Field recorded in the first quarter of fiscal 2013.
Sales volumes from the D6 Block were 88 MMcfe/d and 104 MMcfe/d in the quarter and year-to-date period, respectively compared to 151 MMcfe/d and 167 MMcfe/d in the prior year–s quarter and year-to-date period, respectively. The Company expects decline in production from the D6 Block to continue unless incremental production volume is added from new fields in the D6 Block.
An additional $6 million of profit petroleum expense for the Hazira Field reduced oil and natural gas revenue in the first quarter of fiscal 2013. The adjustment to profit petroleum expense was the result of a court ruling finding that the 36-inch natural gas sales pipeline that Niko and GSPC constructed to connect the Hazira Field to the local industrial area was not eligible for cost recovery. There was a current income tax recovery of $2 million as a result of this adjustment to profit petroleum expense, which is deductible for tax purposes.
Other income in prior year–s quarter and period include proceeds from the farm outs in excess of the recorded cost.
Net finance expense reflects the impacts of repayment of Cdn$310 million of 5% convertible debentures and issue of Cdn$115 million of 7% senior secured notes in December 2012, the impact of borrowings under the Company–s credit facility, and costs related to pursuing financing options.
The Indian rupee weakened against the US dollar during the quarter and year to date. As a result, there was a realized foreign exchange loss during the quarter due to revaluing Indian rupee based accounts receivables to US dollars, which were partly offset by gains arising due to revaluing Indian rupee based accounts payable to US dollars.
Minimum alternate tax expense is calculated on accounting income from the D6 Block. Higher depletion rates reduced accounting income and minimum alternate tax expense.
Net Income (Loss)
The decrease in funds from operations is described above. Other items affecting net loss are described below.
Depletion and depreciation expense for the three and nine months ended December 31, 2012 increased from the prior periods primarily as a result of higher depletion rates for the D6 Block in India resulting from the revision to the reserve volumes and future costs included in the March 31, 2012 reserve report, partially offset by the impact of lower production.
Exploration and evaluation expense for the nine months ended December 31, 2012 includes costs associated with unsuccessful exploration wells in Indonesia and Trinidad, including wells in the Lhokseumawe block in Indonesia and Block 2(ab) in Trinidad, and directly expensed costs of seismic and other exploration projects, payments that are specified in various production sharing contracts (“PSCs”), branch office costs for all exploration properties, and new venture activities.
In the current quarter, the Company recognized asset impairments for the Lhokseumawe block in Indonesia and Block 2(ab) in Trinidad. In the first quarter of fiscal 2013, the Company recognized an asset impairment of $39 million when it reassessed the recoverable amount of the Qara Dagh Block exploration and evaluation asset in Kurdistan. In November 2012, the company signed an agreement to relinquish its interest in the Qara Dagh block in exchange for proceeds equal to the carrying amount of the asset.
The loss on short term investments is a result of mark to market valuation of these investments.
Share-based compensation expense for the quarter and year-to-date decreased by $4 million and $24 million respectively, as a result of a decrease in the fair value per stock option granted as a result of lower stock price during the quarter as compared to the prior year–s quarter and period and the reversal of share-based compensation expense due to forfeitures of stock options.
The Indian rupee weakened against the US dollar during the quarter and year to date. As a result, there was a small unrealized foreign exchange loss during the quarter mainly because the loss arising due to revaluing Indian rupee based income tax receivable was offset by the gains arising due to revaluing Indian rupee based income tax payable.
There was a deferred tax recovery for the quarter of $6 million compared to a deferred tax expense in the prior year–s quarter of $7 million. The primary reason for the change is a deferred tax recovery relating to the issuance of convertible notes in December 2012. The year-to-date deferred tax recovery was also a result of a reduction in deferred tax liabilities resulting from a reduction in exploration and evaluation assets related to proceeds from a farm out and from a former partner in exchange for assuming the partner–s obligation for future drilling commitments.
In the prior year to date period, the change in accounting estimate is related to deferred income tax as a result of estimating the amount of taxable temporary differences reversing during the tax holiday period.
Capital Expenditures, net of Proceeds of Farm-outs and Other Arrangements
The following table sets forth the capital additions and exploration and evaluation costs expensed directly to income, net of proceeds of farm-outs and other arrangements, for the nine months ended December 31, 2012.
Indonesia
Additions to exploration and evaluation assets for Indonesia for the nine months ended December 31, 2012 include costs related to three wells in the Lhokseumawe block, one well in the North Ganal block and one well in the Kofiau block, along with acquisition costs of the Lhokseumawe block. The additions to future drilling in Indonesia relate to the costs of drilling inventory and other activities incurred to prepare for the current drilling campaign. These costs will be allocated when wells are drilled. Exploration and evaluation costs expensed directly to income include costs related to seismic and other exploration projects and branch office costs. In the second quarter of fiscal 2013, the Company recorded proceeds of a farm-out of $9 million and received $36 million from a former partner in exchange for assuming the partner–s obligation for future drilling commitments.
Trinidad and Tobago
Additions to exploration and evaluation assets for Trinidad and Tobago for the nine months ended December 31, 2012 include costs related to two wells drilled in Block 2(ab). Exploration and evaluation costs expensed directly to income include costs related to seismic and other exploration projects, payments that are specified in various PSCs, and branch office costs.
BACKGROUND ON PROPERTIES
The Company–s diversified portfolio of producing, development and exploration assets is described below.
Producing Assets
The Company–s principal producing natural gas and crude oil assets are in the D6 Block in India and in Block 9 in Bangladesh.
D6 Block, India
The Company entered into the PSC for the D6 Block in India in 2000 and has a 10 percent working interest, with Reliance Industries Limited (“Reliance”), the operator, holding a 60 percent interest and BP holding the remaining 30 percent interest. The D6 Block is 7,645 square kilometers lying approximately 20 kilometers offshore of the east coast of India.
Successful exploration programs in the D6 Block led to the discoveries of the Dhirubhai 1 and 3 natural gas fields in 2002 and the MA crude oil and natural gas field in 2006.
Production from the crude oil discovery in the MA field commenced in September 2008 and commercial production commenced in May 2009. Six wells are tied into a floating production storage offloading vessel (“FPSO”), which stores the crude oil until it is sold on the spot market at a price based on the Bonny Light reference price and adjusted for quality, and four of these wells are currently on production. The Company expects to drill an additional gas development well and convert the two suspended oil wells into gas producing wells to accelerate the production of the reservoir–s gas reserves.
Field development of the Dhirubhai 1 and 3 fields included the drilling and tie-in of 18 wells, construction of an offshore platform and onshore gas plant facilities. Production from the Dhirubhai 1 and 3 natural gas discoveries commenced in April 2009 and commercial production commenced in May 2009. The natural gas produced from offshore is being received at an onshore facility at Gadimoga and is sold at the inlet to the East-West Pipeline owned by Reliance Gas Transportation Infrastructure Limited.
Production from the Dhirubhai 1 and 3 fields peaked in March 2010 and has decreased since then, primarily due to natural declines of the fields and greater than anticipated water production. Four additional wells have been drilled in the post-production phase of drilling. Based on the information obtained from three wells drilled within the main channel fairway, the Company has determined that it is not economic to tie-in any of these three wells at the present time. The fourth well was drilled outside of the main channel fairway and did not encounter economic quantities of natural gas. Eight of the original 18 wells are currently shut-in and several others are choked, primarily due to current constraints in water handling capacity. Reliance and the joint venture partners are evaluating workover scenarios to bring some of the shut-in wells back online during fiscal 2014. Increased water handling capacity and additional booster compression is expected to be installed over the next two years to address the decline in reservoir pressure.
The Company expects production to continue to decline until new field production is added from identified development opportunities. See “Background on Properties – Development Opportunities”.
The PSC for the D6 Block requires that natural gas be sold at arm–s length prices, with “arm–s length” defined as sales made freely in the open market between willing and unrelated sellers and buyers, and that the pricing formula be approved by the government of India (“GOI”). In May 2007, Reliance, on behalf of the joint venture partners, discovered an arm–s length price for the sale of gas on a transparent basis with a term of three years and, accordingly, proposed a gas price formula to the GOI. In September 2007, the GOI approved a pricing formula with some modification to the proposed formula. As a result of these modifications, the gas price is capped at $4.20/MMBtu and the formula was declared effective for a period of five years rather than the three years proposed by Reliance. The Company has signed numerous gas sales contracts with customers in the fertilizer, power, steel, city gas distribution, liquefied petroleum gas market and pipeline transportation industries, and all of these contracts expire on March 31, 2014. In June 2012, Reliance submitted to the GOI for approval a proposal for a new crude oil-linked pricing formula to be used in new sales contracts for the period commencing April 1, 2014. The proposed formula by Reliance was based on the pricing formula under a contract for long-term import of LNG into India and was universally accepted by arm–s length buyers who bid in large numbers in an open price discovery process. In December 2012, the Rangarajan committee, a special committee appointed by the GOI, submitted its report to the GOI which included a recommendation on a domestic natural gas pricing mechanism. The recommended pricing mechanism is based on the average of the import price for LNG into India and a volume-weighted average of the prices of gas in North America, Europe and Japan. Based on current inputs into the pricing formula, the price for natural gas sales would be approximately $8 – $8.50/MMBtu. The GOI is currently reviewing the recommended price formula.
The production and operating expenses for the D6 Block relate primarily to the offshore wells and facilities, the onshore gas plant facilities and the operating fee portion of the lease of the FPSO. The majority of these expenses are fixed in nature with repairs and maintenance expenditures incurred as required.
The Company calculates and remits profit petroleum expense to the GOI in accordance with the PSC for the D6 Block. The profit petroleum calculation considers capital, operating and other expenditures made by Reliance on behalf of the joint venture partners. Because there are unrecovered costs to date, the GOI–s share of profit petroleum has amounted to the minimum level of one percent of gross revenue. Profit petroleum expense will increase above the minimum level once past unrecovered costs have been fully recovered. The Company has included certain costs in the profit petroleum calculations that are being contested by the GOI and has received notice from the GOI making allegations in relation to the fulfillment of certain obligations under the PSC for the D6 Block. Refer to note 14 to the consolidated financial statements for nine months ended December 31, 2012 for a complete discussion of this contingency.
The Company currently pays royalty expense of five percent of gross revenue, increasing to ten percent of gross revenue in May 2016. Royalty payments are deductible in calculating profit petroleum.
The Company pays the greater of minimum alternate tax and regular income taxes for the D6 Block. In the calculation of regular income taxes, the Company believes it is entitled to a seven-year income tax holiday commencing from the first year of commercial production and has claimed the tax holiday in the filing of tax return for fiscal 2012. Minimum alternate tax is the amount of tax payable in respect of accounting profits. Minimum alternate tax paid can be carried forward for 10 years and deducted against regular income taxes in future years.
Block 9, Bangladesh
In September 2003, the Company acquired a 60 percent working interest in the PSC for Block 9. Tullow, the operator, holds a 30 percent interest and the remaining 10 percent interest is held by BAPEX. Block 9 covers approximately 1,770 square kilometers of land in the central area of Bangladesh surrounding the capital city of Dhaka. Natural gas and condensate production for the Bangora field in Block 9 commenced in May 2006 and gas is transported from four currently producing wells to a gas plant in the block.
The Company–s share of production from the Bangora field reached a sustained rate of production of 60 MMcf/d in 2009. The Company expects to add compression at the gas processing plant in the fourth quarter of Fiscal 2014 which will allow sustained production levels through 2015. The Company has signed a GPSA including a price of $2.34/MMBtu (or $2.32/Mcf), which expires at the earliest of the end of commercial production, at expiry of the PSC (March 31, 2026) and 25 years after approval of the field development plan (May 15, 2032). Petrobangla is the sole purchaser of the natural gas production from this field. The sales delivery point is at facility and thereafter is the responsibility of Petrobangla and is transported via Trunk Pipeline.
The production and operating expenses for Block 9 relate primarily to the onshore wells and facilities, including a gas plant and pipeline. The majority of these expenses are fixed in nature with repair and maintenance expenditures incurred as required.
The Company calculates and remits profit petroleum expense to the government of Bangladesh (“GOB”) in accordance with the PSC for Block 9. The profit petroleum calculation considers capital, operating and other expenditures made by the joint venture, which reduces the profit petroleum expense. To date, the GOB–s share of profit petroleum amounted to the minimum level of 34 percent of gross revenue based on the profit petroleum provisions of the PSC. The profit petroleum percentage of gross revenue will increase above the minimum level of 34 percent of gross revenue once past unrecovered allowable costs have been fully recovered.
Under the terms of the Block 9 PSC the Company does not make payment to the GOB with respect to income tax.
Development Opportunities
The Company has undeveloped discoveries in D6 and NEC 25 blocks in India and in Block 5(c) in Trinidad and Tobago. Based on development plan submissions, increased clarity on future gas prices and positive project economics for the developments, the Company expects to book significant proved and probable reserves for these projects, effective March 31, 2013. The developments will provide the opportunity for significant production growth for the Company in the next three to six years.
The following is a brief description of these opportunities and their development plans.
Additional Areas, D6 Block, India
The Company–s exploration program has identified three additional areas in the D6 Block for potential future development. In January 2013, the G2 well on the D19 discovery, one of four satellite discoveries approved for development by the GOI, was successfully drilled and the development plan for the R-Series area was submitted to the GOI for approval. The development of these areas is expected to be completed within four years after the approval of the development plans. The plans are likely to include the re-entry and completion of certain existing wells and the drilling of new wells, all connected with new flow-lines and other facilities into existing D6 Block infrastructure.
NEC-25 Block, India
The Company has a 10 percent working interest in the NEC-25 Block, with Reliance, the operator, holding a 60 percent interest and BP holding the remaining 30 percent interest. The remaining contract area comprises 9,461 square kilometres offshore adjacent to the east coast of India. Exploration and appraisal drilling has been conducted on the block and Reliance is working to finalize the development plan for discovered natural gas fields for submission by March 2013. Based on work done to date, the development is expected to include the re-entry and completion of certain existing wells and the drilling of new wells, all connected via new flow-lines and other facilities into a new offshore central processing platform. The produced natural gas is expected to be transported onshore via a new pipeline.
Block 5(c), Trinidad and Tobago
The Company has a 25 percent working interest in Block 5(c) with the BG Group plc (“BG Group”), the operator, holding the remaining 75 percent working interest in this offshore development area that covers 241 square kilometres. In October 2011, the BG Group submitted a development plan to the government of Trinidad and Tobago (“GTT”) for approval. Development of natural gas production from two discovered fields in the block is expected to require the drilling of new wells, construction of new flow-lines and other facilities, and expansion of an existing platform in the adjacent Block 6(b) operated by the BG Group.
Exploration Opportunities
The Company–s business strategy is to commit resources to finding, developing and producing exploration opportunities that have the potential for a “high impact”– on the Company. Exploration acreage is generally obtained by committing to acquire and process a specified amount of seismic and in most cases, drill one or more exploration wells. The Company generally uses advanced technology including high resolution multi-beam data collection and analysis, sub-sea coring and focused 3D seismic to reduce costs associated with selecting prospects to drill and increase the probability of success. The Company generally uses the information acquired to farm-out its blocks to world-class industry partners under terms where the partners fund their share of sunk costs and carry a disproportionate share of drilling costs.
The Company holds interests in contract areas covering 175,142 gross square kilometers of undeveloped land, primarily in Indonesia and Trinidad and Tobago.
Indonesia
The Company holds interests in 22 offshore exploration blocks in Indonesia, covering 119,145 square kilometers. The Company has successfully farmed out interests in several of its blocks and is working with various parties on additional farm-outs to reduce its share of future drilling costs. The table below indicates the operator, the location of, the award date, working interest and the size of the block, as at December 31, 2012.
The Company has signed various agreements that, subject to government approval, will change the working interests in several of its blocks in Indonesia.
All of the Indonesian blocks are in their initial three year exploration period with the exception of the Lhokseumawe block. The seismic work commitments on the majority of the blocks have been fulfilled and as at December 31, 2012, the Company had remaining minimum work commitments to drill a total of ten wells. As at December 31, 2012, the Company–s share of the remaining minimum work commitments as specified in the PSCs for the exploration period was $118 million to be spent at various dates through June 2015. The minimum work commitments are based on the Company–s share of the estimated cost included in the PSCs and represent the amounts the host government may claim if the Company does not perform the work commitments. The actual cost of fulfilling work commitments may materially exceed the amount estimated in the PSCs. The Company has applied or have plans to apply for extensions where drilling activity is planned. The Company is required to relinquish a portion of the exploration acreage after the first exploration period; however, the Company has received extensions in order to fulfill the well commitments on certain blocks.
Trinidad and Tobago
The Company holds interests in ten contract areas in Trinidad and Tobago, covering 9,862 square kilometers. The table below indicates the operator, the location of, the award date, the working interest and the size of the block.
The seismic work commitments on the majority of the blocks and the drilling work commitments on Block 2(ab) have been fulfilled, and as at December 31, 2012, the Company had remaining minimum work commitments to drill a total of ten wells. As at December 31, 2012, the minimum remaining work commitments under the PSCs were $167 million, to be spent at various dates through April 2016. The actual cost of fulfilling work commitments may materially exceed the amount estimated in the PSCs. The Company is working with various parties on farm-outs to reduce its share of future drilling costs.
Other Properties
India
Hazira Field
Niko is the operator of the Hazira Field and holds a 33.33 percent interest in this field. The field is located close to several large industries about 25 kilometers southwest of the city of Surat and covers an area of approximately 50 square kilometers on and offshore. In addition, Niko and GSPC have constructed a 36-inch gas sales pipeline to the local industrial area. The Company has constructed an offshore platform, an LBDP, a gas plant and an oil facility at the Hazira Field. The Company has one significant contract for the sale of natural gas from the Hazira Field at a price of $4.86/Mcf expiring April 30, 2016, which accounted for five percent of total revenues during the quarter. The commitment for future physical deliveries of natural gas under this contract exceeds the expected related future production from total proved reserves from the Hazira Field estimated using forecast prices and costs. Refer to note 14(c) to the consolidated financial statements for nine months ended December 31, 2012 for a complete discussion of this contingency.
Surat Block
The Company holds and is the operator of a development area in the 24 square kilometer Surat Block located onshore adjacent to the Hazira Field in Gujarat State, India. The natural gas production from the Surat Block commenced in April 2004 and is transferred to the customer via 6-inch pipeline to the customer–s facility. The Company has a gas plant at Surat Block and all the production from the Surat Block was sold to one customer with a price of $6.00/Mcf. Sales of natural gas to this customer accounted for one percent of the Company–s total revenues during the quarter. Production from the block ceased in November 2012 as the cap on cumulative production in the approved field development plan was reached. The Company plans to relinquish the block.
Madagascar
In October 2008, the Company farmed in on a PSC for a property located off the west coast of Madagascar covering an area of approximately 16,845 square kilometers. The Company will earn a 75 percent participating interest in the Madagascar block and any extension or renewal thereof or amendment thereto and are the operator of this block. The Company has completed a multi-beam sea bed coring and 3,200 square kilometers of 3D seismic on the block. The Company has work commitments for an exploration well and its share of the remaining costs pursuant to the PSC is $10 million prior to September 2015. The actual cost of fulfilling work commitments may exceed the amount estimated in the PSC.
Pakistan
The Company holds and operates the four blocks comprising the Pakistan Blocks, which are located in the Arabian Sea near the city of Karachi and cover an area of 9,921 square kilometers. The Company has acquired 2,142 square kilometers of 3D seismic data on the blocks. The Company has received a one-year extension to the Phase I exploration period through seismic exploration activity.
Kurdistan
The Company held a 49% working interest in the Qara Dagh Block in Kurdistan and in November 2012, the Company and its consortium partners entered into an agreement with the Kurdistan Regional Government to surrender their collective interests in the block. Pursuant to the agreement, none of the consortium partners will have any future obligations or liabilities with regard to the original production sharing agreement, and the Company expects to recover a net amount of approximately $15 million.
SEGMENT PROFIT
India
Segment profit from India includes the results from the Dhirubhai 1 and 3 natural gas fields and the MA crude oil and natural gas field in the D6 Block, the Hazira crude oil and natural gas field and the Surat gas field.
Revenue and Royalties
The Company–s oil and gas revenues for the quarter and year-to-date decreased from the prior year–s periods, primarily due to natural production declines and greater than anticipated water production at the D6 Block along with the impact of a six day scheduled maintenance shutdown in November 2012 of the FPSO servicing the MA field. Declines are expected to continue unless production volumes are added from new fields in the D6 Block.
The decrease in royalties is a result of the decreased revenues described above. Royalties applicable to production from the D6 Block are five percent for the first seven years of commercial production and gas royalties applicable to the Hazira Field and Surat Block are currently 10 percent of the sales price.
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. An additional $6 million of profit petroleum expense for the Hazira Field was recognized and reduced crude oil and natural gas revenue in the period. The adjustment, related to crude oil and natural gas revenues earned in prior years, was the result of a court ruling finding that the 36-inch natural gas pipeline that Niko and GSPC constructed to connect the Hazira Field to the local industrial area was not eligible for cost recovery.
For the D6 Block, the Company is able to use up to 90 percent of revenue to recover costs. The Government of India was entitled to 10 percent of the profits not used to recover costs during the year. Profit petroleum expense will continue at this level until the Company has recovered its costs.
The Government of India was entitled to 25 percent and 20 percent of the profits from the Hazira Field and the Surat Block, respectively.
Production and Operating Expenses
Operating costs at the D6 Block decreased as less maintenance was conducted during the period compared to the prior year–s period.
Depletion Expense
The depletion rate for the D6 Block increased compared to prior periods as a result of the revision to the reserve volumes and future costs included in the March 31, 2012 reserve report. The effect of the increased depletion rate on the depletion expense was partially offset by decreased production.
Income Taxes
There was a current income tax recovery on year to date basis as a result of the adjustment to profit petroleum described above, which is deductible for tax purposes.
Minimum alternate tax expense is calculated on accounting income from the D6 Block. Higher depletion rates reduced accounting income and minimum alternate tax expense.
Contingencies
The Company has contingencies related to natural gas sales contracts and the profit petroleum calculation for the Hazira Field and related to income taxes for the Hazira Field and the Surat Block as at December 31, 2012. Refer to note 14 to the consolidated financial statements for nine months ended December 31, 2012 for a complete discussion of these contingencies.
Bangladesh
Revenue, Profit Petroleum, Depletion and Operating Expenses
The Company–s oil and gas revenues for the quarter decreased from the prior year–s quarter, primarily due to the curtailment of production from one of the three wells in the Bangora field due to operational issues. Production from this well is expected to be restored in the first quarter of fiscal 2014.
Pursuant to the terms of the PSC for Block 9, the Government of Bangladesh was entitled to 61 percent of profit gas in the year and prior year, which equates to 34 percent of revenues while the Company is recovering historical capital costs. Overall, profit petroleum expense decreased due to decreased revenues from Block 9.
Production and operating expense increased due to the higher level of maintenance activity during the period.
Depletion expense increased on a unit-of-production basis as a result of the addition of a dew-point control unit.
Contingencies
The Company has contingencies related to various claims filed against it with respect to the Feni property in Bangladesh as at December 31, 2012. Refer to note 14 to the consolidated financial statements for the nine months ended December 31, 2012 for a complete discussion of these contingencies.
Indonesia, Kurdistan and Trinidad and Tobago
Indonesia
Costs of $58 million related to unsuccessful wells, costs $13 million relating to seismic and other exploration projects totaling were incurred for various blocks, $3 million was spent on new ventures, $5 million was incurred to operate the branch office and $3 million for share based compensation expense. The prior year expense relates primarily to seismic exploration programs. In the current quarter the Company recognized an asset impairment of $16 million for the Lhokseumawe block. In January 2013, the Company gave notice to the operator to surrender its interest in Lhokseumawe block.
Trinidad and Tobago
Costs of $34 million related to unsuccessful wells in Block 2(ab) were expensed during the nine month period ended December 31, 2012 and the Company recognized an asset impairment of $13 million for Block 2(ab) in the current quarter. Exploration and evaluation costs expensed directly to income include $9 million of seismic costs, $8 million payments that are specified in various PSCs, and $3 million was incurred to operate the branch office.
Kurdistan
In the first quarter of fiscal 2013, the Company recognized an asset impairment of $39 million when it reassessed the recoverable amount of the Qara Dagh Block exploration and evaluation asset.
Corporate
Share-based compensation
The fair value per stock option granted decreased in the periods due to decreased stock price in the period. Share-based compensation expense also decreased during the period due to the reversal of share-based compensation expense resulting from the forfeiture of stock options.
Finance expense
Interest expense includes interest on the Company–s finance lease obligation, interest on borrowings on the Company–s credit facility since March 2012, interest on the 5% Cdn$310 million of convertible debentures repaid in December 2012, and interest on the 7% Cdn$115 million of convertible notes issued in December 2012. Accretion expense is on convertible notes, convertible debentures and decommissioning obligations. The recorded liability for the convertible notes and formerly for the convertible debenture increases as time progresses to the maturity date resulting in a higher accretion expense than in the prior period. Other finance expenses include costs related to pursuing financing options.
Foreign Exchange
The realized foreign exchange losses arise primarily because of the difference between the Indian rupee and U.S. dollar exchange rate at the time of recording individual accounts receivable and accounts payable compared to the exchange rate at the time of receipt of funds to settle recorded accounts receivable and payment to settle recorded accounts payable.
The unrealized foreign exchange gain in the year to date period arose primarily on the revaluing of the Indian-rupee denominated income tax receivable and site restoration deposit to U.S. dollars and the weakening of the Indian-rupee versus the U.S. dollar. There was an unrealized foreign exchange loss during the current quarter as the Indian-Rupee strengthened slightly versus the U.S. dollar when comparing the quarterly average for the current quarter to the quarter ended September 30, 2012.
There were additional foreign exchange gains in the period on U.S. dollar cash held by the parent whose functional currency is the Canadian dollar. An offsetting entry increases the accumulated other comprehensive income but does not flow through the income statement.
Short-Term Investments
The loss on short-term investments for the year was a result of marking the short-term investments to market value.
Deferred Tax Recovery
As a result of the issuance of convertible notes in December 2012, the Company recognized a deferred tax recovery as an unrecognized deferred tax asset was recognized to offset the deferred tax liability associated with the convertible notes.
Netbacks
The following tables outline operating, funds from operations and earnings netbacks (all of which are non-IFRS measures):
Netbacks for India, Bangladesh and in total are calculated by dividing the revenue and costs for each country and in total by the total sales volume for each country and in total measured in Mcfe.
Netbacks for India, Bangladesh and in total are calculated by dividing the revenue and costs for each country and in total by the total sales volume for each country and in total measured in Mcfe.
RELATED PARTIES
The Company has a 45 percent interest in a Canadian property that is operated by a related party, a Company owned by the President and CEO of the Company. This joint interest originated as a result of the related party buying the interest of the third-party operator of the property in 2002. The transactions with the related party are not significant to operations or consolidated financial statements. The transactions with the related party are measured at fair value.
FINANCIAL INSTRUMENTS
The Company–s financial instruments consist of short and long-term investments, accounts receivable, long-term accounts receivable, accounts payable and accrued liabilities, borrowings, convertible notes and convertible debentures.
The Company is exposed to fluctuations in the value of cash, accounts receivable, short-term investments, accounts payable and accrued liabilities due to changes in foreign exchange rates as these financial instruments are partially or wholly denominated in Canadian dollars and the local currencies of the countries in which it operate. The Company manages the risk by converting cash held in foreign currencies to U.S. dollars as required to fund forecasted expenditures. The Company is exposed to changes in foreign exchange rates as the future interest and principal amounts on the convertible notes are in Canadian dollars.
The Company is exposed to changes in the market value of the short-term investments.
The Company is exposed to credit risk with respect to all of its financial instruments if a customer or counterparty fails to meet its contractual obligations. The Company has deposited cash and restricted cash with reputable financial institutions, for which management believes the risk of loss to be remote. The Company takes measures in order to mitigate any risk of loss with respect to the accounts receivable, which may include obtaining guarantees.
The Company is exposed to the risk of changes in market prices of commodities. The Company enters into physical commodity contracts for the sale of natural gas, which partially mitigates this risk. The Company does so in the normal course of business by entering into contracts with fixed natural gas prices. The contracts are not classified as financial instruments because the Company expects to deliver all required volumes under the contracts. No amounts are recognized in the consolidated financial statements related to the contracts until such time as the associated volumes are delivered. The Company is exposed to the changes in the Brent crude price as the average Brent crude price from the preceding year (to a defined maximum) is a variable in the natural gas price for the current year, calculated annually, for the D6 Block natural gas contracts.
The fair values of accounts receivable, accounts payable and accrued liabilities approximate their carrying values due to their short periods to maturity. The fair value of the short-term investments is based on publicly quoted market values. The fair value of the long-term investments is based on their historical cost as they are not traded on publicly quoted markets.
The fair value of the borrowings approximates its carrying value due to the nature of the borrowings. Interest expense on the borrowings of $1 million and $3 million was recorded for the three and nine months ended December 31, 2012.
The debt component of the convertible notes has been recorded net of the fair value of the conversion feature. The fair value of the conversion feature of the notes included in shareholders– equity at the date of issue was $31 million ($24 million net of a deferred tax recovery). The fair value of the conversion feature of the debentures was determined based on the discounted future payments using a discount rate of a similar financial instrument without a conversion feature compared to the fixed rate of interest on the notes. Interest and financing expense of $5 million and $16 million for the three and nine months ended December 31, 2012 were recorded for interest expense and accretion of the discount on the convertible notes and debentures.
LIQUIDITY AND CAPITAL RESOURCES
In January 2012, the Company entered into a three-year facility agreement for a $225 million revolving credit facility and a $25 million operating facility for general corporate purposes. The maximum available credit under this agreement is subject to review based on, among other things, updates to the Company–s reserves. In September, 2012, the syndicate of lenders confirmed a revised borrowing base amount under the facility to an aggregate of $100 million. The Company understands that the revised borrowing base was determined assuming that the price for gas sales from the D6 Block in India would remain unchanged at $4.20 per MMBtu for the life of the gas reserves. The Government of India is currently reviewing a new pricing mechanism for domestic gas produced in India that, if approved, would result in a significant increase in the price for the D6 Block natural gas sales contracts that expire on March 31, 2014. When a new price formula is approved, the Company will exercise its contractual right to have the borrowing base of the facility reviewed. Further, if contingent resources are converted to reserves, the Company will exercise its right to request a further borrowing base review. The Company has borrowed $90 million against this facility as of December 31, 2012.
In September 2012, Niko–s board of directors decided to suspend the Company–s quarterly dividend in connection with the commencement of the Company–s significant exploration drilling program. The timing and level of future dividends, if any, will be reviewed periodically by the board of directors.
In December 2012, the Company repaid its Cdn$310 million convertible debentures due December 30, 2012 at par plus accrued interest, using the net proceeds of $273 million of offerings of common shares and convertible notes, along with cash on hand and advances under the Company–s credit facility. The Cdn$115 million principal amount of convertible senior unsecured notes issued in December 2012 mature on December 31, 2017 and bear interest at a rate of seven percent, with interest payable semi-annually in arrears on June 30 and December 31 of each year, commencing June 30, 2013. The notes are convertible at the option of each holder into common shares at a conversion price of Cdn$11.30 per share. After December 31, 2015, the notes are redeemable by the Company, in whole or in part from time to time, provided that the market price of the Company–s common shares (defined as the weighted average trading price of the common shares for the twenty consecutive trading days ending five trading days prior to the issue of the notice of redemption) is at least 130% of the conversion price. The Company has the right to use common shares to satisfy some or all of its obligations for the notes.
At December 31, 2012, the Company had unrestricted cash of $44 million and working capital deficit (current assets less current liabilities) of $19 million.
For the quarter ended March 31, 2013, funds from operations are forecast to be approximately $25 million and capital expenditures, net of proceeds of farm-outs and other arrangements, are forecast to be approximately $25 million.
For fiscal 2014, the Company–s planned capital spending will be focused on development activities in India and exploration activities in Indonesia and Trinidad. The level of capital spending is flexible with decisions about capital spending to be made throughout the year. The Company is currently in negotiations with various third parties regarding farm-outs, non-core asset dispositions and other arrangements and the Company is confident that the combination of ongoing funds from operations from its producing properties and the proceeds it expects to receive from some or all of the farm-outs, asset dispositions and other arrangements that the Company has been working on will provide appropriate funds for the Company–s capital spending plans.
The Company has a number of contingencies as at December 31, 2012 that could significantly impact liquidity. Refer to note 14 to the consolidated financial statements for the nine months ended December 31, 2012 for a complete discussion of these contingencies.
SUMMARY OF QUARTERLY RESULTS
The following tables set forth selected financial information, in thousands of U.S. dollars unless otherwise indicated, for the eight most recently completed quarters to December 31, 2012:
Net income in the quarters was affected by:
CRITICAL ACCOUNTING ESTIMATES
The Company makes assumptions in applying certain critical accounting estimates that are uncertain at the time the accounting estimate is made and may have a significant effect on the consolidated financial statements of the Company.
The critical accounting estimates include oil and natural gas reserves, depletion, depreciation and amortization expense, asset impairment, decommissioning obligations, the amount and likelihood of contingent liabilities and income taxes. The critical accounting estimates are based on variable inputs including:
A change in a critical accounting estimate can have a significant effect on net earnings as a result of their impact on the depletion rate, decommissioning obligations, asset impairments, losses and income taxes. A change in a critical accounting estimate can have a significant effect on the value of property, plant and equipment, decommissioning obligations and accounts payable.
For a complete discussion of the critical accounting estimates, please refer to the MD&A for the Company–s fiscal year ended March 31, 2012, available at .
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
The International Accounting Standards Board (IASB) has issued IFRS 9 “Financial Instruments” to replace IAS 39 “Financial Instruments: Recognition and Measurement”. The new standard reduces the classification and measurement categories for financial assets and liabilities to two categories: amortized cost and fair value through profit and loss. Under IFRS 9, fair value changes due to credit risk for liabilities designated at fair value through profit and loss would generally be recorded in other comprehensive income. The Company is assessing the impact of the new standard on its consolidated financial statements.
In May 2011, the IASB issued or amended a number of standards that will be effective for annual periods beginning on or after January 1, 2013.
Three new standards are IFRS 10 “Consolidated Financial Statements”, IFRS 11 “Joint Arrangements” and IFRS 12 “Disclosure of Interests in Other Entities”. IFRS 10 establishes a single control model that applies to all entities and will require management to exercise judgment to determine which entities are controlled and need to be consolidated by the parent. The Company will continue to consolidate all of its wholly-owned subsidiaries and are currently assessing the accounting impact of its investments in other companies. IFRS 11 replaces IAS 31 “Interest in Joint Ventures” and SIC-13 “Jointly-controlled Entities – Non-monetary Contributions by Venturers”. IFRS 11 identifies two forms of joint ventures when there is joint control: joint operations and joint ventures. Joint operations are accounted for using proportionate consolidation and joint ventures are accounted for using the equity method. IFRS 11 focuses on the nature of the rights and obligations associated with the joint arrangements and the Company is currently evaluating the effect of this standard on its joint arrangements. IFRS 12 introduces a number of new disclosures related to conso