Niko Reports Results for the Year Ended March 31, 2013
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 07/09/13 -- 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 months and year ended March 31, 2013. The operating results are effective July 8, 2013. All amounts are in U.S. dollars unless otherwise indicated and all amounts are reported using International Financial Reporting Standards unless otherwise indicated.
PRESIDENT'S MESSAGE TO THE SHAREHOLDERS
During fiscal 2013, the Company achieved significant growth in value. Substantial additions to reserves were booked related to development projects in India and in Trinidad and Tobago, contributing to a 166% increase in the Company's total proved reserves to 564 Bcfe and a 118% increase in the Company's total proved plus probable reserves to 821 Bcfe. Reflecting these significant additions, the estimated aggregate after-tax net present value of future net revenue attributable to the Company's estimated proved plus probable reserves (discounted at 10 percent and estimated using forecast prices and costs) increased by 93% to $1.3 Billion. On top of the reserve value, the Company's extensive exploration portfolio and discovered resources, including the significant MJ gas and condensate discovery in the D6 Block in India, provide substantial additional potential value for shareholders.
With a significant reserve write-down at the end of fiscal 2012 and associated production declines in the Company's main producing asset, fiscal 2013 was a very challenging year for Niko. This was coupled with the maturity of Cdn$310 million of convertible debt and a significant reduction in the availability under the Company's credit facility, all occurring in a very challenging illiquid capital market. Through it all, Niko's people launched the largest exploration program in the Company's history, achieving and exceeding many performance metrics and resulting in three potential discoveries in Indonesia. The ingenuity, planning and execution of Niko's drilling team in Indonesia consistently resulted in reduced drilling time and associated well costs, setting records for speed, cost and efficiency of deepwater drilling in Indonesia in recent times. Niko has also achieved a safety performance record second to none with no recordable injuries over the year, achieving a milestone of 8 million man-hours without a recordable incident in our operated properties in India! Development activities commenced in the producing fields in the D6 Block in India to bring on additional production, address the decline in reservoir pressure and increase water handling capacity. The Company addressed its maturing convertible debenture by issuing common shares and new unsecured convertible notes for combined gross proceeds of Cdn$273 million, and raised $113 million from the Company's program of asset sales, farm-outs and other arrangements ($70 million in fiscal 2013 and $43 million thus far in fiscal 2014), with substantial additional proceeds targeted for the remainder of fiscal 2014.
Looking forward, the long-awaited approval by the Government of India of a new pricing formula for domestic natural gas sales will double the price for gas sales from the D6 Block from its current level of $4.20/MMbtu to around $8.40/MMbtu, effective April 1, 2014. Prices are to be revised quarterly thereafter using the approved formula, with further increases expected in the future, and the impact of the increased prices will be reflected in the borrowing base of the Company's credit facility by the end of July, 2013.
The exploration program has been restarted in the D6 Block in India with the drilling of the exciting MJ-1 gas and condensate discovery, where initial evaluations of drilling results indicate significant resource potential. An initial appraisal program of up to three wells is expected to commence in the current fiscal year.
I would like to thank Niko's people and our shareholders who have supported Niko through this very difficult past year. With the continued high impact deepwater exploration program, recent discoveries and increased gas prices in India on the horizon, Niko looks forward to fiscal 2014 as a major turnaround year for the company. In the past year, the Company re-established itself as capable of achieving significant growth in value. The highlights included:
Edward S. Sampson - President and Chief Executive Officer, Niko Resources Ltd.
REVIEW OF OPERATIONS AND GUIDANCE
Sales Volumes
Total sales volumes for the fourth quarter averaged 126 MMcfe/d compared to 145 MMcfe/d for the third quarter of fiscal 2013, primarily due to anticipated natural declines and reservoir management activities in the D6 Block in India.
For fiscal 2014, an additional well in the MA field and workovers for the Dhirubhai 1 and 3 and MA fields in the D6 Block in India and the Bangora field in Block 9 in Bangladesh, respectively, will provide additional volumes starting in the second quarter of the year, contributing to an annual average sales volumes forecast between 112 and 116 MMcfe/d for the year. For fiscal 2015, the Company is targeting 133 MMcfe/d, benefiting from development activities in fiscal 2014 and 2015.
Funds from Operations
Funds from operations for the fourth quarter were $30 million compared to $27 million for the third quarter of fiscal 2013.
For fiscal 2014, funds from operations are forecast to be approximately $70 to $75 million. For fiscal 2015, funds from operations are forecast to increase by $100 million or more, reflecting higher sales volume and the Company's estimate of the projected benefit of improved pricing for natural gas sales in India.
Capital Expenditures, net of Proceeds of Farm-outs and Other Arrangements
Capital expenditures, net of proceeds of farm-outs and other arrangements, totaled $32 million for the fourth quarter. Spending in the quarter related primarily to exploration activities in Indonesia, Trinidad and Tobago, India and Brazil. The Company also received $25 million from a former partner in exchange for assuming the partner's obligation for future drilling commitments.
Exploration results for the year included potential discoveries of hydrocarbons at Lebah-1, Ajek-1 and Cikar-1 in Indonesia, and the Company is currently evaluating future plans for these three fields. Subsequent to year-end, the Company and its joint venture partners announced the significant MJ-1 gas condensate discovery in the D6 Block in India. These discoveries have the potential to increase the Company's resource base by 50% or more over the currently booked proved plus probable reserves.
For fiscal 2014, the Company's minimum level of capital expenditures, net of negotiated farm-outs and other arrangements, and workover expenditures, is forecast to total approximately $130 million. Decisions about additional capital spending during the year will be made as the year progresses, depending on the results of the Company's program of asset sales, farm-outs and other arrangements, and the Company's financing activities.
Estimated Reserves
The Company increased its proved reserves by 166%, a proved reserve replacement ratio of over 700%, and increased its proved plus probable reserves by 118%, a proved plus probable reserve replacement ratio of nearly 900%.
India
For the D1 D3 and MA producing fields in the D6 Block, virtually no revisions were reflected for combined proved reserves on a gas equivalent basis, with small positive revisions reflected for combined proved plus probable reserves. A combined total of 165 Bcf of proved and 270 Bcf of proved plus probable reserves additions were booked for the R-Series and Satellite Area development projects in the D6 Block and the J-Series development project in the NEC-25 Block.
Bangladesh
Positive revisions to proved reserves of 46 Bcfe were reflected for Block 9, increasing proved reserves to 101 Bcfe even after production of 20 Bcfe.
Trinidad and Tobago
Additions to proved reserves for the Endeavour/Bounty development project in Block 5(c) were 197 Bcf (235 Bcf on a proved plus probable basis).
Estimated After-tax Net Present Value of Future Net Revenue
The estimated aggregate after-tax net present value of future net revenue attributable to the Company's estimated proved plus probable reserves (discounted at 10 percent and estimated using forecast prices and costs) increased by 93% to $1.3 Billion, reflecting the significant increases in reserves, described above.
Complete details of the Company's reserves and future net revenues attributable thereto are contained in its Annual Information Form for the year ended March 31, 2013 which is available on SEDAR at .
MANAGEMENT'S DISCUSSION AND ANALYSIS
This Management's Discussion and Analysis (MD&A) of the financial condition, results of operations and cash flows of Niko Resources Ltd. ("Niko" or the "Company") for the year ended March 31, 2013 should be read in conjunction with the audited consolidated financial statements for the year ended March 31, 2013. This MD&A is effective July 08, 2013. Additional information relating to the Company, including the Company's Annual Information Form (AIF), is available on SEDAR at .
All financial information is presented in thousands of U.S. dollars unless otherwise indicated.
The term "the quarter" is used throughout the MD&A and in all cases refers to the period from January 1, 2013 through March 31, 2013. The term "prior year's quarter" is used throughout the MD&A for comparative purposes and refers to the period from January 1, 2012 through March 31, 2012.
The fiscal year for the Company is the 12-month period ended March 31. The terms "Fiscal 2012" and "prior year" is used throughout this MD&A and in all cases refers to the period from April 1, 2011 through March 31, 2012. The terms "Fiscal 2013", "current year" and "the year" are used throughout the MD&A and in all cases refer to the period from April 1, 2012 through March 31, 2013.
Mcfe (thousand cubic feet equivalent) is a measure used throughout the MD&A. Mcfe is derived by converting oil and condensate to natural gas in the ratio of 1 bbl:6 Mcf. Mcfe may be misleading, particularly if used in isolation. A Mcfe conversion ratio of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. MMBtu (million British thermal units) is a measure used in the MD&A. It refers to the energy content of natural gas (as well as other fuels) and is used for pricing purposes. One MMBtu is equivalent to 1 Mcfe plus or minus up to 20 percent, depending on the composition and heating value of the natural gas in question.
Cautionary Statement Regarding Forward-Looking Statements and Information
Certain statements in this MD&A are "forward-looking statements" or "forward-looking information" within the meaning of applicable securities laws, herein "forward looking statements" or "forward looking information". Forward-looking information is frequently characterized by words such as "plan," "expect," "project," "intend," "believe," "anticipate," "estimate," "scheduled," "potential" or other similar words, or statements that certain events or conditions "may," "should" or "could" occur. Forward-looking information is based on the Company's expectations regarding its future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities. Such forward-looking information reflects the Company's current beliefs and assumptions and is based on information currently available to it. Forward-looking information involves significant known and unknown risks and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking information including risks associated with the impact of general economic conditions, industry conditions, governmental regulation, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and the Company's ability to access sufficient capital from internal and external sources, the risks discussed under "Risk Factors" and elsewhere in this report and in the Company's public disclosure documents, and other factors, many of which are beyond its control. Although the forward-looking information contained in this report is based upon assumptions which the Company believes to be reasonable, it cannot assure investors that actual results will be consistent with such forward-looking information. Such forward-looking information is presented as of the date of this MD&A, and the Company assumes no obligation to update or revise such information to reflect new events or circumstances, except as required by law. Because of the risks, uncertainties and assumptions inherent in forward-looking information, you should not place undue reliance on this forward-looking information. See also "Risk Factors."
Specific forward-looking information contained in this MD&A may include, among others, statements regarding:
The forward-looking statements contained in this MD&A are based on certain key expectations and assumptions made by us, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities and the availability and cost of labor and services. Although the Company believes that the expectations reflected in the forward-looking statements in this MD&A are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and natural gas industry in general, such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation, as well as the other risk factors identified under "Risk Factors" herein. Statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. You are cautioned that the foregoing list of factors and risks is not exhaustive.
The Company prepares production forecasts taking into account historical and current production, and actual and planned events that are expected to increase or decrease production and production levels indicated in its reserve reports.
The Company prepares capital spending forecasts based on internal budgets for operated properties, budgets prepared by the Company's joint venture partners, when available, for non-operated properties, field development plans and actual and planned events that are expected to affect the timing or amount of capital spending.
The Company prepares operating expense forecasts based on historical and current levels of expenses and actual and planned events that are expected to increase or decrease production and/or the associated expenses.
The Company discloses the nature and timing of expected future events based on budgets, plans, intentions and expected future events for operated properties. The nature and timing of expected future events for non-operated properties are based on budgets and other communications received from joint venture partners.
The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis when the change is material and update reserve estimates on an annual basis. See "Risk Factors" for discussion of uncertainties and risks that may cause actual events to differ from forward-looking information provided in this report. The information contained in this report, including the information provided under the heading "Risk Factors," identifies additional factors that could affect the Company's operating results and performance. The Company urges you to carefully consider those factors and the other information contained in this report.
The forward-looking statements contained in this report are made as of the date hereof and, unless so required by applicable law. The Company undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this report are expressly qualified by this cautionary statement.
Non-IFRS Measures
The selected financial information presented throughout this MD&A is prepared in accordance with IFRS, except for "funds from operations", "operating netback", "funds from operations netback", "earnings netback", "segment profit" and "working capital". These non-IFRS financial measures, which have been derived from financial statements and applied on a consistent basis, are used by management as measures of performance of the Company. These non-IFRS measures should not be viewed as substitutes for measures of financial performance presented in accordance with IFRS or as a measure of a company's profitability or liquidity. These non-IFRS measures do not have any standardized meaning prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other companies.
The Company utilizes funds from operations to assess past performance and to help determine its ability to fund future capital projects and investments. Funds from operations is calculated as cash flows from operating activities prior to the change in operating non-cash working capital, the change in long-term accounts receivable and exploration and evaluation costs expensed to the statement of comprehensive income.
The Company utilizes operating netback, funds from operations netback, earnings netback and segment profit to evaluate past performance by segment and overall.
Operating netback is calculated as oil and natural gas revenues less royalties, the government share of profit petroleum and operating expenses for a given reporting period, per thousand cubic feet equivalent (Mcfe) of production for the same period, and represents the before-tax cash margin for every Mcfe sold.
Funds from operations netback is calculated as the funds from operations per Mcfe and represents the cash margin for every Mcfe sold. Earnings netback is calculated as net income per Mcfe and represents net income for every Mcfe sold.
Segment profit is defined as oil and natural gas revenues less royalties, the government share of profit petroleum, production and operating expenses, depletion expense, exploration and evaluation expense and current and deferred income taxes related to each business segment.
The Company defines working capital as current assets less current liabilities and uses working capital as a measure of the Company's ability to fulfill obligations with current assets.
These non-IFRS measures do not have any standardized meaning prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other companies.
OVERALL PERFORMANCE
Funds from Operations
(1) EBITDAX and Funds from operations are non-IFRS measures as defined under "Non-IFRS measures" in this MD&A.
Oil and natural gas revenue decreased in the year, primarily due to lower sales of natural gas, crude oil and condensate from the D6 Block in India along with an adjustment to the government share of profit petroleum for the Hazira Field recorded in the current year.
Production and operating expenses have reduced in D6 mainly because of reduction in logistics cost from last year due to reduced operations. However some of this reduction is offset by increase in operating expenses of Block 9 due to the well repair and workovers during the period.
Other income in the prior year includes proceeds from farm-outs in excess of the recorded cost of the Company's interests in certain properties in Indonesia.
General and administrative expenses decreased primarily due to reduced use of outside legal services.
Bank charges and other finance costs decreased primarily due to lower costs related to financing efforts.
There were realized foreign exchange losses in the current and prior years as a result of the weakening of the Indian-Rupee against the U.S. dollar.
Interest expense increased slightly primarily due to interest on credit facility borrowing and the convertible notes in the current year, offset by lower interest on the convertible debentures.
Current income tax decreased compared to the prior year due to reductions in income for Hazira (including the adjustment to the government share of profit petroleum recorded in the current year) and Surat. In the prior year, there was an adjustment related to previous year tax provisions for Hazira.
The Company currently pays minimum alternate tax based on Indian-GAAP accounting income for the D6 block. For the current year, the D6 Block did not generate positive accounting income under Indian GAAP, resulting in no minimum alternative tax expense.
Net Income (Loss)
The decrease in funds from operations is described above. Other items affecting net loss are described below.
Depletion and depreciation expense for the current year was consistent with the prior year as the impact of increased depletion rates for the D6 Block in India resulting from the revision to the reserve volumes and future costs included in the March 31, 2012 reserve report was virtually offset by the impact of lower production.
Exploration and evaluation expense for the current year includes costs associated with unsuccessful exploration wells, including wells in the Lhokseumawe Block in Indonesia and Block 2(ab) in Trinidad, and directly expensed costs of seismic and other exploration projects, payments specified in various production sharing contracts ("PSCs"), branch office costs for all exploration properties, and new venture activities.
In the current year, the Company recognized asset impairments for exploration and evaluation assets in the Lhokseumawe block in Indonesia, Block 2(ab) in Trinidad and Qara Dagh Block in Kurdistan.
The Company recognized reversal of asset impairment for the D6 Block in India.
The impairment of long term receivables in the prior year related to gas sales revenue receivables in Bangladesh.
Share-based compensation expense decreased in the current year, as a result of a decrease in the fair value per stock option granted as a result of lower stock price during the year as compared to the prior year and the reversal of share-based compensation expense due to forfeitures of stock options.
The Indian rupee weakened against the US dollar during the current and prior years. As a result, unrealized foreign exchange losses were recorded in the years.
The loss on short term investments is a result of mark to market valuation of these investments.
The deferred tax recovery for the current year relates mainly to the reversal of temporary differences during the tax holiday period which mainly depends on the accounting depletion rate and capital spending during the period. In the current year the amount of temporary differences reversing during the tax holiday period came down significantly resulting in deferred tax expenses which were partially offset by deferred tax recovery recognized on issuance of convertible notes in December 2012 and to a reduction in exploration and evaluation assets related to the receipt of proceeds from a farm out and from former partners in exchange for assuming the partners' obligations for future drilling commitments. For the prior year, the amounts of temporary differences reversing during the tax holiday period were significantly higher resulting in deferred tax recovery.
In the prior year, the change in accounting estimate is related to deferred income tax resulting from estimating the amount of taxable temporary differences reversing during the tax holiday period.
Capital Expenditures, net of Proceeds of Farm-outs and Other Arrangements
The following table sets forth the capital additions and exploration and evaluation costs expensed directly to income, net of proceeds of farm-outs and other arrangements, for the year ended March 31, 2013.
Indonesia
Additions to exploration and evaluation assets for Indonesia for the current year include costs related to three wells in the Lhokseumawe block, and one well in each of the North Ganal, Kofiau, and West Papua IV blocks, along with acquisition costs of the Lhokseumawe block. The additions to future drilling in Indonesia relate to the costs of drilling inventory and other activities incurred to prepare for the current drilling campaign. These costs will be allocated when future wells are drilled. Exploration and evaluation costs expensed directly to income include costs related to seismic and other exploration projects and branch office costs. In the current year, the Company also recorded proceeds of a farm-out of $9 million and received $61 million from former partners in exchange for assuming the partners' obligations for future drilling commitments.
Trinidad and Tobago
Additions to exploration and evaluation assets for Trinidad and Tobago for the current year include costs related to two wells drilled in Block 2(ab). Exploration and evaluation costs expensed directly to income include costs related to seismic and other exploration projects, payments that are specified in various PSCs, and branch office costs.
All Other
Exploration and evaluation costs expensed directly to income included costs related to the acquisition of multi-beam data over various blocks in Brazil. Additions of property, plant and equipment in the year relate to development projects in India.
BACKGROUND ON PROPERTIES
The Company's diversified portfolio of producing, development and exploration assets is described below.
Producing Assets
The Company's principal producing natural gas and crude oil assets are in the D6 Block in India and in Block 9 in Bangladesh.
D6 Block, India
The Company entered into the PSC for the D6 Block in India in 2000 and has a 10 percent working interest, with Reliance Industries Limited ("Reliance"), the operator, holding a 60 percent interest and BP holding the remaining 30 percent interest. The D6 Block is 7,645 square kilometers lying approximately 20 kilometers offshore of the east coast of India.
Successful exploration programs in the D6 Block led to the discoveries of the Dhirubhai 1 and 3 natural gas fields in 2002 and the MA crude oil and natural gas field in 2006.
Production from the crude oil discovery in the MA field commenced in September 2008 and commercial production commenced in May 2009. Six wells are tied into a floating production storage offloading vessel ("FPSO"), which stores the crude oil until it is sold on the spot market at a price based on the Bonny Light reference price and adjusted for quality, and four of these wells are currently on production. In fiscal 2014, the joint venture plans to drill an additional gas development well and convert of one of the two suspended oil wells into a gas producing well to accelerate the production of the reservoir's gas reserves.
Field development of the Dhirubhai 1 and 3 fields included the drilling and tie-in of 18 wells, construction of an offshore platform and onshore gas plant facilities. Production from the Dhirubhai 1 and 3 natural gas discoveries commenced in April 2009 and commercial production commenced in May 2009. The natural gas produced from offshore is being received at an onshore facility at Gadimoga and is sold at the inlet to the East-West Pipeline owned by Reliance Gas Transportation Infrastructure Limited.
Production from the Dhirubhai 1 and 3 fields peaked in March 2010 and has decreased since then, primarily due to natural declines of the fields and greater than anticipated water production. Four additional wells have been drilled in the post-production phase of drilling. Based on the information obtained from three wells drilled within the main channel fairway, the Company has determined that it is not economic to tie-in any of these three wells at the present time. The fourth well was drilled outside of the main channel fairway and did not encounter economic quantities of natural gas. Nine of the original 18 wells are currently shut-in and several others are choked, primarily due to current constraints in water handling capacity. Workovers are planned to bring some of the shut-in wells back online during fiscal 2014. Increased water handling capacity and additional booster compression is expected to be installed over the next two years to address the decline in reservoir pressure.
The PSC for the D6 Block states that natural gas must be sold at arm's length prices, with "arm's length" defined as sales made freely in the open market between willing and unrelated sellers and buyers, and that the pricing formula be approved by the GOI taking into account the prevailing policy on natural gas. In May 2007, Reliance, on behalf of the joint venture partners, discovered an arm's length price for the sale of gas on a transparent basis with a term of three years and accordingly, proposed a gas price formula to the GOI. In September 2007, the GOI approved a pricing formula with some modification to the proposed formula. As a result of these modifications, the gas price is capped at $4.20/MMBtu and the formula was declared effective for a period of five years rather than the three years proposed by Reliance. The Company has signed numerous gas sales contracts with customers in the fertilizer, power, steel, city gas distribution, liquefied petroleum gas market and pipeline transportation industries, and all of these contracts expire on March 31, 2014. In June 2013, the Cabinet Committee of Economic Affairs of the GOI approved a new pricing formula for domestic gas sales in India, based on the recommendations of the Rangarajan Committee. The pricing formula is based on the average of the prices of imported LNG into India and the weighted average of gas prices in North America, Europe and Japan, as follows:
The pricing formula will be effective on April 1, 2014 for a period of five years, with the price to be revised quarterly using the approved formula. The price for each quarter will be calculated based on the 12 month trailing average price with a lag of one quarter (i.e., the price for April to June 2014 will be calculated based on the averages for the 12 months ended December 31, 2013). At the present time, the Indian LNG term imports relate primarily to the Petronet contract with RasGas of Qatar. Per the Rangarajan Committee Report, the pricing terms of this contract are as follows:
In the future, the Indian LNG term imports are expected to include imports related to the Petronet contract with ExxonMobil for import of LNG from the Gorgon venture in Australia. Per the Rangarajan Committee Report, the terms of this contract are as follows:
Estimated liquefaction and transportation costs of $3.00/MMbtu for older LNG facilities (pre-2010) or $4.00/MMbtu for newer LNG facilities are to be deducted to arrive at the netback price for Indian LNG term imports.
Using the approved price formula, the price effective for April 1, 2014 is estimated at around $8.40/MMbtu, double the price of $4.20/MMbtu for current gas sales from the D6 Block. The pricing terms of the Petronet contracts are expected to result in further increases in the gas prices in future quarters, assuming current pricing levels of JCC, U.S. Henry Hub, U.K. National Balancing Point and Japan LNG imports.
The production and operating expenses for the D6 Block relate primarily to the offshore wells and facilities, the onshore gas plant facilities and the operating fee portion of the lease of the FPSO. The majority of these expenses are fixed in nature with repairs and maintenance expenditures incurred as required.
The Company calculates and remits the government share of profit petroleum to the GOI in accordance with the PSC for the D6 Block. The profit petroleum calculation considers capital, operating and other expenditures made by the joint venture. Because there are unrecovered costs to date, the GOI's share of profit petroleum has amounted to the minimum level of one percent of gross revenue. The government share of profit petroleum will increase above the minimum level once past unrecovered costs have been fully recovered. The Company has included certain costs in the profit petroleum calculations that are being contested by the GOI and has received notice from the GOI making allegations in relation to the fulfillment of certain obligations under the PSC for the D6 Block. Refer to note 30 to the consolidated financial statements for nine months ended March 31, 2013 for a complete discussion of this contingency.
The Company currently pays royalty expense of five percent of gross revenue, increasing to ten percent of gross revenue in May 2016. Royalty payments are deductible in calculating profit petroleum.
The Company pays the greater of minimum alternate tax and regular income taxes for the D6 Block. In the calculation of regular income taxes, the Company believes it is entitled to a seven-year income tax holiday commencing from the first year of commercial production and has claimed the tax holiday in the filing of tax return for fiscal 2012. Minimum alternate tax is the amount of tax payable in respect of accounting profits. Minimum alternate tax paid can be carried forward for 10 years and deducted against regular income taxes in future years.
Block 9, Bangladesh
In September 2003, the Company acquired a 60 percent working interest in the PSC for Block 9. Tullow, the operator, holds a 30 percent interest and the remaining 10 percent interest is held by BAPEX. Block 9 covers approximately 1,770 square kilometers of land in the central area of Bangladesh surrounding the capital city of Dhaka. Natural gas and condensate production for the Bangora field in Block 9 commenced in May 2006 and gas is transported from four currently producing wells to a gas plant in the block.
The Company's share of production from the Bangora field reached a sustained rate of production of 60 MMcf/d in 2009. The Company expects to add compression at the gas processing plant in the fourth quarter of Fiscal 2014 which will allow sustained production levels through 2015. The Company has signed a GPSA including a price of $2.34/MMBtu (or $2.32/Mcf), which expires at the earliest of the end of commercial production, at expiry of the PSC (March 31, 2026) and 25 years after approval of the field development plan (May 15, 2032). Petrobangla is the sole purchaser of the natural gas production from this field. The sales delivery point is at the outlet of the gas plant and thereafter is the responsibility of Petrobangla and is transported via Trunk Pipeline.
The production and operating expenses for Block 9 relate primarily to the onshore wells and facilities, including a gas plant and pipeline. The majority of these expenses are fixed in nature with repair and maintenance expenditures incurred as required.
The Company calculates and remits the government share of profit petroleum to the government of Bangladesh ("GOB") in accordance with the PSC for Block 9. The profit petroleum calculation considers capital, operating and other expenditures made by the joint venture. To date, the GOB's share of profit petroleum amounted to the minimum level of 34 percent of gross revenue based on the profit petroleum provisions of the PSC. The profit petroleum percentage of gross revenue will increase above the minimum level of 34 percent of gross revenue once past unrecovered allowable costs have been fully recovered.
Under the terms of the Block 9 PSC the Company does not make payment to the GOB with respect to income tax.
Planned Developments
The Company has undeveloped discoveries in D6 and NEC 25 blocks in India and in Block 5(c) in Trinidad and Tobago. Based on development plan submissions, increased clarity on future gas prices and positive project economics for the developments, the Company booked significant proved and probable reserves for these projects, effective March 31, 2013. The developments will provide the opportunity for significant production growth for the Company in the next four to six years.
The following is a brief description of these development plans.
Additional Areas, D6 Block, India
The Company's exploration program has identified three additional areas in the D6 Block for potential future development. In January 2013, the G2 well on the D19 discovery, one of four satellite discoveries approved for development by the GOI, was successfully drilled and the development plan for the R-Series area was submitted to the GOI for approval. The development of these areas is expected to be completed within four years after the approval of the development plans. The plans include the re-entry and completion of certain existing wells and the drilling of new wells, all connected with new flow-lines and other facilities into existing D6 Block infrastructure.
NEC-25 Block, India
The Company has a 10 percent working interest in the NEC-25 Block, with Reliance, the operator, holding a 60 percent interest and BP holding the remaining 30 percent interest. The remaining contract area comprises 9,461 square kilometres offshore adjacent to the east coast of India. Exploration and appraisal drilling has been conducted on the block and the development plan for certain discovered natural gas fields was submitted in March 2013. The development plans include the re-entry and completion of certain existing wells and the drilling of new wells, all connected via new flow-lines and other facilities into a new offshore central processing platform. The produced natural gas is expected to be transported onshore via a new pipeline.
Block 5(c), Trinidad and Tobago
The Company has a 25 percent working interest in Block 5(c) with the BG Group plc ("BG Group"), the operator, holding the remaining 75 percent working interest in this offshore development area that covers 241 square kilometres. In October 2011, the BG Group submitted a development plan to the government of Trinidad and Tobago ("GTT") for approval. Development of natural gas production from two discovered fields in the block is expected to require the drilling of new wells, construction of new flow-lines and other facilities, and expansion of an existing platform in the adjacent Block 6(b) operated by the BG Group.
Exploration Discoveries
Discovery: MJ-1, D6 Block, India
In March 2013, after a multi-year hiatus, exploration drilling recommenced in the D6 Block in India with the drilling of the MJ-1 exploration well. In May 2013, the joint venture partners announced a significant gas and condensate discovery. The MJ-1 well was drilled in a water depth of 1,024 metres - and to a total depth of 4,509 metres - to explore the prospectivity of a Mesozoic Synrift Clastic reservoir lying over 2,000 metres below the already producing reservoirs in the Dhirubhai 1 and 3 gas fields. Formation evaluation indicates a gross gas and condensate column in the well of about 155 metres in the Mesozoic reservoirs. In the drill stem test, the well flowed 30.6 MMcf/d of natural gas and 2,121 b/d of liquids though a choke of 36/64", with a flowing bottom hole pressure of 8461 psia suggesting good flow potential. Well flow rates during such tests are limited by the rig and well test equipment configuration. The discovery, named 'D-55', has been notified to the GOI and the Management Committee of the block.
Subsequent to the completion of drilling operations, a preliminary technical evaluation has been conducted that has incorporated all seismic and new well data. Principal findings demonstrate that most parameters for the MJ reservoir exceed the high end pre-drill estimates. In particular, MJ-1 has considerable thicker reservoir pay than the best case pre-drill assessment. The fully cored MJ-1 pay interval was found to be 95% sand bearing with net pay averaging 125 metres. In addition, the MJ-1 gas water contact, as confirmed by wireline log and MDT data, is at the equivalent depth of a mapped seismic flat spot and a northern structural spill point. This validates that MJ is filled fully to structural spill and accordingly aligns the MJ field nearer the maximum case pre-drill field size estimates of 65 square kilometres. In comparison, the producing MA field covers a reservoir area of 11 square kilometres.
The MJ field discovery is well positioned to take advantage of the existing D6 Block infrastructure. Conceptual planning has been initiated to maximize MJ gas and condensate recovery which has a measured compositional ratio of approximately 62 bbls/MMcf.
An initial appraisal program of up to three wells should commence within 6 to 8 months pending government approvals and equipment availability.
Potential Discoveries: Lebah-1, Ajek-1 and Cikar-1 wells, various blocks, Indonesia
The Lebah-1 well, drilled by the operator, ENI, in the North Ganal block, located offshore Kalimantan in the Makassar Strait of Indonesia, penetrated 12 feet of net pay at the top of a 41 foot gross sand Upper Miocene sand interval, a secondary target zone of the well. The joint venture partners have evaluated the potential of this zone and are finalizing plans to drill the Lebah-2 appraisal well in an area of the structure where the zone is believed to be thicker.
The Ajek-1 well, drilled in the Kofiau block, located offshore Papua province in eastern Indonesia, encountered 23 feet of pay over two target Pliocene clastic intervals, with additional thin bedded pay potential. Drilling confirmed the presence of reservoir and hydrocarbon charge, the primary pre-drill concerns in this previously undrilled sub-basin. All sands encountered were hydrocarbon filled with no water leg and C5+ gas composition indicated liquid hydrocarbons. The well has been assessed as a sub-commercial oil and gas discovery. The Company is evaluating the potential of drilling of an appraisal well or one of the other prospects on the block that it believes could contain thicker Pliocene clastic sands.
The Cikar-1 well, drilled in the West Papua IV block, located offshore Papua province in eastern Indonesia, encountered a 700 foot thick section of the targeted New Guinea Limestone primary objective and was still in the porous zone when well conditions forced suspension of drilling operations. The well encountered gas in the drilling of the deeper section and the temporary suspension of the well will allow Niko to return to the well for future deepening and testing. The Company is also evaluating the potential of drilling of an appraisal well or one of the other prospects on the block that it believes could also contain thick sections of New Guinea Limestone.
Exploration Opportunities
The Company's business strategy is to commit resources to finding, developing and producing exploration opportunities that have the potential for a "high impact"' on the Company. Exploration acreage is generally obtained by committing to acquire and process a specified amount of seismic and in most cases, drill one or more exploration wells. The Company generally uses advanced technology including high resolution multi-beam data collection and analysis, sub-sea coring and focused 3D seismic to reduce costs associated with selecting prospects to drill and increase the probability of success. The Company generally uses the information acquired to farm-out its blocks to world-class industry partners under terms where the partners fund their share of sunk costs and carry a disproportionate share of drilling costs.
The Company holds interests in contract areas covering 173,922 gross square kilometers of undeveloped land, primarily in Indonesia and Trinidad and Tobago.
Indonesia
As at March 31, 2013, the Company held interests in 22 offshore exploration blocks in Indonesia, covering 117,925 square kilometers. The Company has successfully farmed out interests in several of its blocks and is working with various parties on additional farm-outs to reduce its share of future drilling costs. The table below indicates the operator, the location of, the award date, working interest and the size of the block, as at March 31, 2013.
All of the Indonesian blocks are in their initial three year exploration period, with the exception of the Lhokseumawe block. The seismic work commitments on the majority of the blocks have been fulfilled and as at March 31, 2013, the Company had remaining minimum work commitments to drill a total of ten wells. As at March 31, 2013, the Company's share of the remaining minimum work commitments as specified in the PSCs for the exploration period was $112 million to be spent at various dates through June 2015. The minimum work commitments are based on the Company's share of the estimated cost included in the PSCs and represent the amounts the host government may claim if the Company does not perform the work commitments. The actual cost of fulfilling work commitments may materially exceed the amount estimated in the PSCs. The Company has applied for or has plans to apply for extensions where drilling activity is planned. The Company is required to relinquish a portion of the exploration acreage after the first exploration period; however, the Company has received extensions in order to fulfill the well commitments on certain blocks.
Trinidad
As at March 31, 2013, the Company held interests in ten contract areas in Trinidad and Tobago, covering 9,862 square kilometers. The table below indicates the operator, the location of, the award date, the working interest and the size of the block.
The seismic work commitments on the majority of the blocks and the drilling work commitments on Block 2(ab) have been fulfilled, and as at March 31, 2013, the Company had remaining minimum work commitments to drill a total of ten wells. As at March 31, 2013, the minimum remaining work commitments under the PSCs were $167 million, to be spent at various dates through April 2016 and represent the amounts the host government may claim if the Company does not perform the work commitments. The actual cost of fulfilling work commitments may materially exceed the amount estimated in the PSCs . The Company is working with various parties on farm-outs to reduce its share of future drilling costs.
Other Properties
India
Hazira Field
Niko is the operator of and holds a 33.33 percent interest in the Hazira Field, located about 25 kilometers southwest of the city of Surat and covering an area of 50 square kilometers on and offshore. Niko and GSPC have constructed a 36-inch gas sales pipeline to the local industrial area. The Company has constructed an offshore platform, an LBDP, a gas plant and an oil facility at the Hazira Field. The Company has one significant contract for the sale of natural gas at a price of $4.86/Mcf, expiring April 30, 2016, and the commitment for future physical deliveries under this contract exceeds the expected future production from the Hazira Field. Refer to note 30 to the consolidated financial statements for year ended March 31, 2013 for a complete discussion of this contingency.
Surat Block
The Company holds and is the operator of the 24 square kilometer Surat Block located onshore adjacent to the Hazira Field. The natural gas production from the Surat Block commenced in April 2004 and ceased in November 2012 as the cap on cumulative production in the approved field development plan was reached. The Company plans to relinquish the block.
Madagascar
In October 2008, the Company farmed into a PSC for a property located off the west coast of Madagascar covering approximately 16,845 square kilometers. The Company will earn a 75 percent participating interest in the Madagascar block and is the operator of this block. The Company has completed a multi-beam sea bed coring and 3,200 square kilometers of 3D seismic on the block. The Company has work commitments for an exploration well to be drilled prior to September 2015 and its share of the costs of the remaining commitments pursuant to the PSC is $10 million. The actual cost of fulfilling work commitments may exceed the amount estimated in the PSC. The Company is working with various parties on farm-outs to reduce its share of future drilling costs.
Pakistan
The Company holds and operates the four blocks comprising the Pakistan Blocks, located in the Arabian Sea near the city of Karachi and covering an area of 9,921 square kilometers. The Company has applied for relinquishment of all of the Pakistan Blocks.
Kurdistan
The Company held a 49% working interest in the Qara Dagh Block in Kurdistan and in November 2012, the Company and its consortium partners entered into an agreement with the Kurdistan Regional Government to surrender their collective interests in the block. Pursuant to the agreement, none of the consortium partners will have any future obligations or liabilities with regard to the original production sharing agreement, and the Company recovered a net amount of approximately $15 million in June 2013.
SEGMENT PROFIT
INDIA
Segment profit from India includes the results from the Dhirubhai 1 and 3 natural gas fields and the MA crude oil and natural gas field in the D6 Block, the Hazira crude oil and natural gas field and the Surat gas field.
The Company's oil and gas revenues for the year-to-date decreased from the prior year's periods, primarily due to natural production declines and reservoir management activities in the D6 Block. Production from the Surat block ceased in November 2012 as the cap on cumulative production in the approved field development plan was reached.
The decrease in royalties is a result of the decreased revenues described above. Royalties applicable to production from the D6 Block are five percent for the first seven years of commercial production and gas royalties applicable to the Hazira Field and Surat Block are currently 10 percent of the sales price.
Pursuant to the terms of the Indian PSCs, the Government of India is entitled to a sliding scale share in the profits once the Company has recovered its investment. Profits are defined as revenue less royalties, operating expenses and capital expenditures. An additional $6 million of the government share of profit petroleum for the Hazira Field was recognized and reduced crude oil and natural gas revenue in the period. The adjustment, related to crude oil and natural gas revenues earned in prior years, was the result of a court ruling finding that the 36-inch natural gas pipeline that Niko and GSPC constructed to connect the Hazira Field to the local industrial area was not eligible for cost recovery.
For the D6 Block, the Company is able to use up to 90 percent of revenue to recover costs. The Government of India was entitled to 10 percent of the profits not used to recover costs during the year. The government share of profit petroleum will continue at this level until the Company has recovered its costs. The Government of India was entitled to 25 percent and 20 percent of the profits from the Hazira Field and the Surat Block, respectively.
Operating costs at the D6 Block decreased mainly because of significant reduction in logistics costs due to reduced movement of material and inventory as compared to the prior year.
Depletion and depreciation expense for the current year was consistent with the prior year as the impact of increased depletion rates for the D6 Block in India resulting from the revision to the reserve volumes and future costs included in the March 31, 2012 reserve report was virtually offset by the impact of lower production.
In the current year, as a result of increased reserves volumes assigned to the D6 Block in the March 31, 2013 reserve report, the Company recognized a $102 million reversal of the asset impairment recorded in the prior year related to the D6 Block in India. In the prior year, as a result of reduced reserves volumes assigned to the D6 Block in the March 31, 2012 reserve report, the Company had recognized a $133 million impairment related to the Company's producing assets in the D6 Block.
There was a current income tax recovery in the current year, primarily as a result of the adjustment to the government share of profit petroleum described above, which is deductible for tax purposes.
The Company currently pays minimum alternate tax based on Indian-GAAP accounting income for the D6 block. For the current year, the D6 Block did not generate positive accounting income under Indian GAAP, resulting in a no minimum alternative tax expense in the current year.
The deferred tax expense for the current year relates mainly to the reversal of temporary differences during the tax holiday period which mainly depends on the accounting depletion rate and capital spending during the period. In the current year the amount of temporary differences reversing during the tax holiday period came down significantly resulting in deferred tax expenses. For the prior year, the amounts of temporary differences reversing during the tax holiday period were significantly higher resulting in deferred tax recovery.
In the prior year, the change in accounting estimate is related to deferred income taxes as a result of estimating the amount of taxable temporary differences reversing during the tax holiday period.
Contingencies
The Company has contingencies related to natural gas sales contracts for the Hazira Field, the profit petroleum calculations for the Hazira Field and the D6 Block, and income taxes for the Hazira Field and the Surat Block. Refer to note 30 to the consolidated financial statements for year ended March 31, 2013 for a complete discussion of these contingencies.
BANGLADESH
The Company's oil and gas revenues for the year decreased from the prior year, primarily due to the curtailment of production from one of the four wells in the Bangora field due to operational issues. Repairs to this well should be completed by the end of the second quarter and production restored to previous levels in the third quarter.
Pursuant to the terms of the PSC for Block 9, the Government of Bangladesh was entitled to 61 percent of profit gas in the current and prior years, which equates to 34 percent of revenues while the Company is recovering historical capital costs. Overall, the government share of profit petroleum decreased due to decreased revenues from Block 9.
Production and operating expense increased due to the well repair and commencement of facilities expansion work during the period.
The impairment of long term receivables in the prior year related to a receivable for natural gas sales to the Bangladesh Oil, Gas and Mineral Corporation (Petrobangla) from the Feni field in Bangladesh. The Company has filed for arbitration to settle this receivable. Due to the uncertainty with respect to the timing of resolution of this claim and various claims against the Company (as described below), a provision has recorded against the full amount of the receivable.
Contingencies
The Company has contingencies related to various claims filed against it with respect to the Feni property in Bangladesh as at March 31, 2013. Refer to note 30 to the consolidated financial statements for the year ended March 31, 2013 for a complete discussion of these contingencies.
Indonesia, Trinidad and Tobago, Kurdistan and Brazil
Indonesia
During the current year, the Company expensed exploration and evaluation costs of $60 million related to unsuccessful wells drilled in Indonesia in the year, including three wells in the Lhokseumawe block, and recognized an asset impairment of $16 million related to the Lhokseumawe block as the Company had given notice to surrender its interest to the operator of the block. In addition, exploration and evaluation costs expensed directly to income in the current year included $17 million for seismic and other exploration projects, $8 million for branch office costs, $4 million for share-based compensation costs, and $3 million for new ventures costs. For the prior year, the exploration and evaluation expenses related primarily to costs expensed directly to income in the year.
Trinidad and Tobago
During the current year, the Company expensed exploration and evaluation costs of $34 million related to unsuccessful wells drilled in Block 2(ab) and recognized an asset impairment of $13 million for Block 2(ab). In addition, exploration and evaluation costs expensed directly to income in the current year included $10 million for seismic and other exploration projects, $9 million for payments specified in various PSCs, and $5 million for branch office costs. For the prior year, the exploration and evaluation expenses included costs of $24 million related to unsuccessful wells and costs of $88 million expensed directly to income in the year.
Kurdistan
In the current year, the Company recognized an asset impairment of $39 million when it wrote down the carrying value of the Qara Dagh Block exploration and evaluation asset to the expected net proceeds to be received after relinquishment of the block.
Brazil
In the current year, the Company incurred $14 million of costs related to the acquisition of multi beam data over various blocks in Brazil. In May 2013, the Company and its joint venture partner were awarded two blocks offshore the north eastern coast of Brazil. The Company plans to market the multi-beam data to other successful bidders of blocks in the Brazil bid round.
Corporate
Share-based compensation expense
The fair value per stock option granted decreased in the year due to decreased stock price in the period. Share-based compensation expense also decreased during the year due to the reversal of share-based compensation expense resulting from the forfeiture of stock options.
Finance expense
Interest expense includes interest on the Company's finance lease obligation, interest on borrowings on the Company's credit facility since March 2012, interest on the 5% Cdn$310 million of convertible debentures repaid in December 2012, and interest on the 7% Cdn$115 million of convertible notes issued in December 2012. Accretion expense relates to the recorded liabilities for the convertible notes, the convertible debentures and decommissioning obligations. The recorded liabilities increase as time progresses to the final settlement date, resulting in increased accretion expenses each year. Other finance expenses include costs related to pursuing financing options.
Foreign Exchange
Due to the weakening of the Indian rupee versus the U.S. dollar in the current and prior years, the Company has realized foreign exchange losses primarily related to the differences in the Indian rupee to U.S. dollar exchange rate at the time of recording versus the time of settlement of individual accounts receivable and accounts payable. Unrealized foreign exchange losses have arisen on the translation of the Indian-rupee denominated income tax receivable and site restoration deposits.
Foreign exchange gains in the year on U.S. dollar cash held by a company whose functional currency is the Canadian dollar have increased accumulated other comprehensive income but do not flow through the income statement.
Short-Term Investments
The loss on short-term investments for the year was a result of marking the short-term investments to market value.
Deferred Tax Recovery
As a result of the issuance of convertible notes in December 2012, the Company recognized a deferred tax recovery as an unrecognized deferred tax asset was recognized to offset the deferred tax liability associated with the convertible notes.
NETBACKS
The following tables outline the Company's operating, funds from operations and earnings netbacks (all of which are non-IFRS measures):
Netbacks for India, Bangladesh and in total are calculated by dividing the revenue and costs for each country and in total by the total sales volume for each country and in total measured in Mcfe.
LIQUIDITY AND CAPITAL RESOURCES
The Company's funding strategy is to use funds from operations from its producing properties, proceeds from non-core asset dispositions, farm-outs and other arrangements, and equity financing to fund its exploration programs and use funds from operations from its producing properties, and debt and equity financing to fund its development programs. Due to the timing and availability of the funding from various sources, the Company may, on occasion, utilize debt financing to fund its exploration programs and repay the debt with funds from operations, proceeds from non-core asset dispositions, farm-outs and other arrangements, and/or equity financing. If excess funds are available after funding the Company's planned capital programs for the foreseeable future, then the Company's Board of Directors would evaluate the option of paying dividends to its shareholders.
Credit Facility
In January 2012, the Company entered into a three-year facility agreement for a $225 million revolving credit facility and a $25 million operating facility for general corporate purposes.
As at March 31, 2013, the Senior Debt to EBITDAX ratio was 0.9:1, the Debt to EBITDAX ratio was 1.0:1, the EDITDAX to Interest Expense ratio was 7.0:1, and the Debt to Capitalization ratio was 14%, well within the specified financial covenants. Based on the Company's financial forecasts for fiscal 2014 and fiscal 2015, the Company expects to remain in compliance with the financial covenants of the credit facility throughout fiscal 2014 and fiscal 2015.
The maximum available credit under the credit agreement is subject to review based on, among other things, updates to the Company's reserves. In September, 2012, the syndicate of lenders confirmed a revised borrowing base amount under the facility to an aggregate of $100 million, based on the evaluation of the Company's reserves as at March 31, 2012 and based on an assumption that t
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Datum: 09.07.2013 - 04:57 Uhr
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News-ID 276426
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"Niko Reports Results for the Year Ended March 31, 2013"
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