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 six month
periods ended September 30, 2012. The operating results are
effective November 13, 2012. 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
The Company has made significant progress on its options for the
repayment of its convertible debentures that mature on December 30,
2012. Discussions are at an advanced stage and the Company expects
resolution well in advance of maturity.
Niko's strategy has been to acquire a large number of PSCs in
emerging exploration trends, use advanced technology to develop a
geologically and geographically diverse portfolio of high impact
wells, execute leveraged farm-outs, and target partners with
worldwide deep water experience. Seismic has been acquired over the
vast majority of Niko's exploration acreage and the Company has
been successful in farming out blocks and is continuing to work on
additional leveraged farm-outs to world-class partners.
It appears to management that the market has greatly overreacted
to the initial results of the Company's drilling campaign in
Indonesia. The Company has drilled the equivalent of one net well
out of a multi-year drilling program. By taking a portfolio
approach, Niko will benefit from economies of scale in drilling
operations as well as increase the statistical likelihood of
success. A number of changes made by Niko for the Ocean Monarch rig
being used in the deepwater drilling campaign in Indonesia have and
will result in significant time and cost savings for the Company.
These changes coupled with leveraged farm-outs, will provide
shareholders with exposure to significant exploration potential at
relatively low cost.
Niko also announces that Glen Valk, Niko's Corporate Treasurer,
will succeed Murray Hesje as Vice President, Finance and Chief
Financial Officer of the Company, upon Mr. Hesje's retirement
effective at year end. Mr. Valk has over 25 years of finance
experience with international E&P companies in Canada,
Indonesia and the United States. Mr. Valk joined the Company in
August 2012 and has been working with Mr. Hesje to ensure a smooth
transition takes place. Mr. Hesje joined Niko in July 2006 and has
been instrumental in the Company's growth into new regions such as
Indonesia and Trinidad. Importantly upon his retirement, Mr. Hesje
will continue with Niko as a special advisor to the Company and the
Board of Directors.
Edward S. Sampson - President and Chief Executive Officer, Niko
Resources Ltd.
REVIEW OF OPERATIONS AND GUIDANCE
Sales Volumes
----------------------------------------------------------------------------
Three months ended Sept 30, Six months ended Sept 30
2012 2011 2012 2011
----------------------------------------------------------------------------
(MMcfe/d) Actual Actual Actual Actual
----------------------------------------------------------------------------
D6 Block, India 106 169 113 175
Block 9, Bangladesh 59 61 60 59
Others(1) 7 10 7 10
----------------------------------------------------------------------------
Total production(2) 173 241 181 244
----------------------------------------------------------------------------
(1) Others includes Hazira and Surat in India, and Canada.
(2) Figures may not add up due to rounding.
Total sales volumes for the second quarter averaged 173 MMcfe/d
compared to 189 MMcfe/d for the first quarter, primarily due to
anticipated natural declines in the D6 Block in India without any
remedial work being done in the period.
As indicated in the Company's press release of October 19, 2012,
production for the full year ended March 31, 2013 is forecast to be
168 MMcfe/d, four percent lower than the Company's previous
guidance of 175 MMcfe/d, due to temporary mechanical constraints in
Block 9 in Bangladesh. This decrease is expected to reduce oil and
gas revenue by approximately $2 million for the full year ended
March 31, 2013.
Funds from Operations
----------------------------------------------------------------------------
Three months ended Sept 30, Six months ended Sept 30,
2012 2011 2012 2011
----------------------------------------------------------------------------
(millions of U.S.
dollars) Actual Actual Actual Actual
----------------------------------------------------------------------------
Funds from operations 34 61 75 121
----------------------------------------------------------------------------
As with sales volumes, the primary reason for the variances in
funds from operations relates to production from the D6 Block in
India.
Capital Expenditures, net of Proceeds of Farm-outs and Other Arrangements
----------------------------------------------------------------------------
Three months ended Six months ended
(millions of U.S. dollars) Sept 30, 2012 Sept 30, 2012
----------------------------------------------------------------------------
Indonesia 12 48
Trinidad 25 44
All other 1 4
----------------------------------------------------------------------------
Total 38 96
----------------------------------------------------------------------------
Capital additions and expensed exploration spending, net of
proceeds of farm-outs and other arrangements, totaled $38 million
for the second quarter. Spending related primarily to exploration
wells, seismic, other exploration projects, and branch office costs
in Indonesia and Trinidad and Tobago. In addition, the Company
recorded proceeds of farm-outs of an estimated $9 million, received
$36 million from a former partner in exchange for assuming the
partner's obligations for future drilling commitments and recorded
costs related to pre-drilling activities and drilling inventory to
prepare for the upcoming multi-year drilling campaign in Indonesia
using the Ocean Monarch drilling rig.
The Company's guidance on its capital program for the year ended
March 31, 2013, net of proceeds of negotiated farm-outs and other
arrangements, has been revised from $210 million to $170 million,
due primarily to deferrals of development spending. In addition,
Niko has funded and will continue to fund certain drilling
inventory and other costs related to its drilling program in future
years. Total spending for the year is expected to be approximately
$205 million.
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 six months ended September 30, 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 November 13, 2012. Additional
information relating to the Company, including the Company's Annual
Information Form (AIF), is available on SEDAR at www.sedar.com.
The term "the quarter" or "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 July 1, 2012 through September 30, 2012. The term
"prior year's quarter" or "prior year's period" used throughout
this MD&A for comparative purposes and refers to the period
from July 1, 2011 through September 30, 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 performance characteristics of the Company's oil, NGL and natural
gas properties;
-- oil, NGL and natural gas production levels, sales volumes and revenue;
-- the size of the Company's oil, NGL and natural gas reserves;
-- projections of market prices and costs;
-- supply and demand for oil, NGL and natural gas;
-- the Company's ability to raise capital and to continually add to
reserves through acquisitions and development;
-- future funds from operations;
-- debt and liquidity levels;
-- future royalty rates;
-- future depletion, depreciation and accretion rates;
-- treatment under governmental regulatory regimes and tax laws;
-- work commitments and capital expenditure programs;
-- the Company's future development and exploration activities and the
timing of these activities;
-- the Company's future ability to satisfy certain contractual obligations;
-- future economic conditions, including future interest rates;
-- the impact of governmental controls, regulations and applicable royalty
rates on the Company's operations;
-- the completion of the Offering and uses of proceeds to be received from
the Offering;
-- the Company's expectations regarding the development and production
potential of its properties;
-- the Company's expectations regarding the costs for development
activities;
-- the resolution of various legal claims raised against the Company;
-- the potential for asset impairment and recoverable amounts of such
assets; and
-- changes to accounting estimates and accounting policies.
The forward-looking statements contained in this MD&A are
based on certain key expectations and assumptions made by us,
including expectations and assumptions relating to prevailing
commodity prices and exchange rates, applicable royalty rates and
tax laws, future well production rates, the performance of existing
wells, the success of drilling new wells, the availability of
capital to undertake planned activities and the availability and
cost of labor and services. Although the Company believes that the
expectations reflected in the forward-looking statements in this
MD&A are reasonable, it can give no assurance that such
expectations will prove to be correct. Since forward-looking
statements address future events and conditions, by their very
nature they involve inherent risks and uncertainties. Actual
results may differ materially from those currently anticipated due
to a number of factors and risks. These include, but are not
limited to, the risks associated with the oil and natural gas
industry in general, such as operational risks in development,
exploration and production, delays or changes in plans with respect
to exploration or development projects or capital expenditures, the
uncertainty of estimates and projections relating to production
rates, costs and expenses, commodity price and exchange rate
fluctuations, marketing and transportation, environmental risks,
competition, the ability to access sufficient capital from internal
and external sources and changes in tax, royalty and environmental
legislation, as well as the other risk factors identified under
"Risk Factors" herein. Statements relating to "reserves" are deemed
to be forward-looking statements, as they involve the implied
assessment, based on certain estimates and assumptions, that the
reserves described exist in the quantities predicted or estimated,
and can be profitably produced in the future. You are cautioned
that the foregoing list of factors and risks is not exhaustive.
The Company prepares production forecasts taking into account
historical and current production, and actual and planned events
that are expected to increase or decrease production and production
levels indicated in its reserve reports.
The Company prepares capital spending forecasts based on
internal budgets for operated properties, budgets prepared by the
Company's joint venture partners, when available, for non-operated
properties, field development plans and actual and planned events
that are expected to affect the timing or amount of capital
spending.
The Company prepares operating expense forecasts based on
historical and current levels of expenses and actual and planned
events that are expected to increase or decrease production and/or
the associated expenses.
The Company discloses the nature and timing of expected future
events based on budgets, plans, intentions and expected future
events for operated properties. The nature and timing of expected
future events for non-operated properties are based on budgets and
other communications received from joint venture partners.
The Company updates forward-looking information related to
operations, production and capital spending on a quarterly basis
when the change is material and update reserve estimates on an
annual basis. See "Risk Factors" for discussion of uncertainties
and risks that may cause actual events to differ from
forward-looking information provided in this report. The
information contained in this report, including the information
provided under the heading "Risk Factors," identifies additional
factors that could affect the Company's operating results and
performance. The Company urges you to carefully consider those
factors and the other information contained in this report.
The forward-looking statements contained in this report are made
as of the date hereof and, unless so required by applicable law.
The Company undertakes no obligation to update or revise any
forward-looking statements, whether as a result of new information,
future events or otherwise. The forward-looking statements
contained in this report are expressly qualified by this cautionary
statement.
Non-IFRS Measures
The selected financial information presented throughout this
MD&A is prepared in accordance with IFRS, except for "funds
from operations", "operating netback", "funds from operations
netback", "earnings netback", "segment profit" and "working
capital". These non-IFRS financial measures, which have been
derived from financial statements and applied on a consistent
basis, are used by management as measures of performance of the
Company. These non-IFRS measures should not be viewed as
substitutes for measures of financial performance presented in
accordance with IFRS or as a measure of a company's profitability
or liquidity. These non-IFRS measures do not have any standardized
meaning prescribed by IFRS and are therefore unlikely to be
comparable to similar measures presented by other companies.
The Company 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.
-- Operating netback is calculated as oil and natural gas revenues less
royalties, profit petroleum expenses and operating expenses for a given
reporting period, per thousand cubic feet equivalent (Mcfe) of
production for the same period, and is a measure of the before-tax cash
margin for every Mcfe sold.
-- Funds from operations netback is calculated as the funds from operations
per Mcfe and represents the cash margin for every Mcfe sold. Earnings
netback is calculated as net income per Mcfe and represents net income
for every Mcfe sold.
-- Segment profit is defined as oil and natural gas revenues less
royalties, profit petroleum expenses, production and operating expenses,
depletion expense, exploration and evaluation expense 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.
OVERALL PERFORMANCE
Funds from Operations
----------------------------------------------------------------------------
Three months ended Sept 30, Six months ended Sept 30,
(thousands of U.S.
dollars) 2012 2011 2012 2011
----------------------------------------------------------------------------
Oil and natural gas
revenue 58,080 86,810 113,179 175,088
Other income 311 - 311 -
Production and
operating expenses (9,696) (9,057) (17,574) (18,088)
General and
administrative
expenses (2,266) (1,857) (4,323) (4,015)
Net finance expense (6,081) (5,588) (12,165) (11,389)
Realized foreign
exchange loss (2,833) (3,217) (2,480) (3,368)
Current income tax
recovery / (expense) (285) (1,183) 2,091 (4,290)
Minimum alternate tax
expense (3,125) (4,917) (4,410) (12,797)
----------------------------------------------------------------------------
Funds from operations
(1) 34,105 60,991 74,629 121,141
----------------------------------------------------------------------------
(1) Funds from operations is a non-IFRS measure as defined under "Non-IFRS
measures" in this MD&A.
Oil and natural gas revenue during the three months ended
September 30, 2012 decreased $29 million compared to the prior
year's quarter. Oil and natural gas revenue during the six months
ended September 30, 2012 decreased $62 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 106 MMcfe/d and 113 MMcfe/d
in the quarter and year-to-date period, respectively compared to
169 MMcfe/d and 175 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.
The Indian rupee strengthened 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 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)
------------------------------------------------------------------------
Three months ended Six months ended
Sept 30, Sept 30,
(thousands of U.S.
dollars) 2012 2011 2012 2011
------------------------------------------------------------------------
Funds from
operations (non-
IFRS measure) 34,105 60,991 74,629 121,141
Production and
operating expenses (330) (493) (637) (1,017)
Depletion and
depreciation
expense (39,204) (27,778) (81,616) (58,969)
Exploration and
evaluation expense (52,879) (45,117) (89,300) (59,270)
Loss on short-term
investments (32) (9,783) (276) (8,568)
Asset (impairment) /
recovery 181 - (38,919) 69
Share-based
compensation
expense (3,342) (6,511) (6,902) (12,698)
Finance expense (2,162) (1,951) (4,158) (3,750)
Unrealized foreign
exchange (loss) /
gain 6,657 (3,964) 1,512 (3,875)
Deferred income tax
(expense) /
recovery 28,433 4,603 24,971 (184)
------------------------------------------------------------------------
(28,573) (30,003) (120,696) (27,121)
------------------------------------------------------------------------
Change in accounting
estimate-deferred
taxes - - - (57,865)
Other expenses -
impact of option
cancellation - (13,913) - (13,913)
Net loss (28,573) (43,916) (120,696) (98,899)
------------------------------------------------------------------------
The decrease in funds from operations is described above. Other
items affecting net loss are described below.
Depletion and depreciation expense for the D6 Block for the
quarter increased by $10 million to $35 million as a result of the
revision to the reserve volumes and future costs included in the
March 31, 2012 reserve report. This amount was partially offset by
the effect of lower production.
Exploration and evaluation expense of $52 million for the
quarter is comprised of: $35 million for costs associated with
three unsuccessful exploration wells, $7 million for seismic and
other exploration projects, $1 million for payments that are
specified in the various PSC, $4 million for branch office costs
for all exploration properties and $2 million for new venture
activities. Exploration and evaluation expense of $36 million for
the first quarter of fiscal 2013 included: $12 million for costs
associated with one unsuccessful exploration well, $12 million for
seismic and other exploration projects, $5 million for payments
that are specified in the various PSC, $5 million for branch office
costs for all exploration properties and $2 million for new venture
activities.
The loss on short term investments is a result of mark to market
valuation of these investments.
The Company recognized an asset impairment of $39 million in the
first quarter of fiscal 2013 when it reassessed the recoverable
amount of the Qara Dagh Block exploration and evaluation asset in
Kurdistan.
Share-based compensation expense for the quarter and
year-to-date decreased by $3 million and $6 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.
The Indian Rupee strengthened against the U.S. dollar during the
quarter and year-to-date. As a result, there was an unrealized
foreign exchange gain during the quarter due to revaluing the
Indian-rupee based income tax receivable to U.S. dollars.
Deferred tax recovery for the quarter and year-to-date increased
by $24 million and $25 million, respectively, due to 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, 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 six months
ended September 30, 2012.
----------------------------------------------------------------------------
Six months ended September 30, 2012
----------------------------------------------------------------------------
Directly
Additions to Additions expensed
exploration related to exploration
and evaluation future and evaluation
(thousands of U.S. dollars) assets(1) (2) drilling costs(1)
----------------------------------------------------------------------------
Indonesia 46,490 27,799 18,428
Trinidad 26,482 1,516 15,122
All other 485 - 2,872
----------------------------------------------------------------------------
Total 73,457 29,315 36,422
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended September 30, 2012
----------------------------------------------------------------------------
Additions to Proceeds from
property, farm outs and
plant and other
(thousands of U.S. dollars) equipment(1) arrangements Total
----------------------------------------------------------------------------
Indonesia 129 (45,203) 47,643
Trinidad 404 - 43,524
All other 924 - 4,281
----------------------------------------------------------------------------
Total 1,457 (45,203) 95,448
----------------------------------------------------------------------------
(1) Share-based compensation and other non-cash items are excluded. Includes
additions in the year that were subsequently written off.
(2) Includes additions in the year that were subsequently written off.
Indonesia
Additions to exploration and evaluation assets for Indonesia for
the six months ended September 30, 2012 relate to two wells in the
Lhokseumawe block and one well in the North Ganal block. The first
well in the Lhokseumawe block, with a cost of $12 million, did not
reach target depth due to mechanical problems and was expensed in
the first quarter of fiscal 2013. The second well in the
Lhokseumawe block, with a cost of $12 million and one well in North
Ganal block, with a cost of $3 million, did not encounter
commercial quantities of hydrocarbons and were expensed in the
current quarter. The remaining additions in Indonesia relate to the
costs of drilling inventory and activities to prepare for the
upcoming drilling campaign. Subsequent to the end of the current
quarter, drilling of the Jayarani-1 well in the Lhokseumawe block
was completed and no commercial reservoir was encountered. Costs
incurred to September 30, 2012 of $6 million along with costs
incurred subsequent to end of the quarter related to this well will
be expensed in the third quarter of fiscal 2013. Exploration and
evaluation costs expensed directly to income include $13 million
for seismic and other exploration projects and $5 million for
branch office costs. In addition, 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 six months ended September 30, 2012 relate to the
Shadow-1 and Maestro-1 wells drilled in Block 2AB. The Shadow-1
well with a cost of $20 million did not encounter significant
hydrocarbon-bearing sandstone and was expensed in the current
quarter. Subsequent to the end of the current quarter, hydrocarbons
were encountered in the Maestro-1 well at the Lower Cretaceous
level, however, no significant reservoir intervals that could be
deemed commercial were encountered and costs incurred to September
30, 2012 of $5 million along with costs incurred subsequent to end
of the quarter will be expensed in the third quarter of fiscal
2013. Exploration and evaluation costs expensed directly to income
include $5 million of costs related to seismic exploration for the
Guayaguayare area and $1 million of payments that are specified in
the various PSCs.
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, 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 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. Six of the original 18 wells are
currently shut-in and several others are choked, primarily due to
current constraints in water handling capacity. 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 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 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.
Using JCC crude oil pricing for July 2012, the proposed pricing
formula would result in a gas price that is approximately
$13/MMBtu, three times the current gas price. The GOI is currently
reviewing the proposed 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 six
months ended September 30, 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. There is currently uncertainty in
India regarding the applicability of this tax holiday to natural
gas. 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 drill two probable undeveloped locations in Fiscal 2014
which, if successful could offset the natural decline expected in
the Bangora field 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 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. For each of the
proposed developments of these discoveries, the Company shall make
final investment decisions if and when development plans are
approved by the respective governments with pricing terms for the
natural gas sales acceptable to the respective joint venture
partners. The Company expects that approval of any or all of these
developments will significantly increase the Company's booked
reserves and provide the opportunity for significant production
growth in the next three to six years.
The following is a brief description of these opportunities and
proposed 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.
An integrated development strategy for the D6 Block, including
these undeveloped areas, is currently being prepared by Reliance
with input from the joint venture partners and under this strategy,
the Company expects development plan for the three areas to be
submitted for approval in late 2012 or early 2013. The development
of these areas is expected to be completed within three to 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 seven discovered natural gas fields to be
submitted for approval in early 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, the operator, holding the remaining 75 percent
working interest in this offshore development area that covers 324
square kilometres. In October 2011, the BG Group submitted a
development plan to the 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 176,071
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.
----------------------------------------------------------------------------
Area
Offshore Working (Square
Block Name Operator Area Award Date Interest Kilometres)
----------------------------------------------------------------------------
Lhokseumawe (1) Zaratex Aceh Oct. 2005 30% 4,431
Bone Bay Niko Sulawesi S Nov. 2008 100% 4,969
Makassar
South East Ganal Niko Strait Nov. 2008 100% 4,868
Seram Niko Seram NE Nov. 2008 55% 4,991
South Matindok Niko Sulawesi NE Nov. 2008 100% 5,182
Makassar
West Sageri Niko Strait Nov. 2008 100% 4,977
Cendrawasih Exxon Papua NW May 2009 45% 4,991
Kofiau Niko Papua W May 2009 57.5% 5,000
Kumawa Niko Papua SW May 2009 100% 5,004
East Bula Niko Seram NE Nov. 2009 55% 6,029
Halmahera-Kofiau Niko Papua W Nov. 2009 51%(2) 4,926
Makassar
North Makassar Niko Strait Nov. 2009 30% 1,787
West Papua IV Niko Papua SW Nov. 2009 51%(2) 6,389
Cendrawasih Bay
II Repsol Papua NW May 2010 50% 5,073
Cendrawasih Bay
III Niko Papua NW May 2010 50% 4,689
Cendrawasih Bay
IV Niko Papua NW May 2010 50% 3,904
Sunda
Sunda Strait I Niko Strait May 2010 100% 6,960
Obi Niko Papua W Nov. 2011 51%(3) 8,057
Makassar
North Ganal Eni Strait Nov. 2011 31% 2,432
Halmahera II Statoil Papua W Dec. 2011 20% 8,215
South East Seram Niko Papua SW Dec. 2011 100% 8,217
Aru Niko Papua SW July 2012 60% 8,054
----------------------------------------------------------------------------
(1) In October 2012, the Company received government approval for its farm-
in to the Lhokseumawe block.
(2) The Company has entered into farm-out agreements for the West Papua IV
and Halmahera-Kofiau blocks that, subject to government approval, will be
reduce its working interest to 48 percent and 40 percent, respectively.
(3) The Company has entered into a farm-out agreement for the Obi block
that, subject to government approval, will reduce its working interest to 42
percent.
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 September 30, 2012, the Company had remaining
minimum work commitments to drill a total of ten wells. As at
September 30, 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 is expected to 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 9,945 square kilometers. The table below
indicates the operator, the location of, the award date, the
working interest and the size of the block.
----------------------------------------------------------------------------
Exploration Working Area (Square
Area Operator Location Award Date interest Kilometres)
----------------------------------------------------------------------------
Block 2AB Niko Offshore July 2009 35.75% 1,605
Guayaguayare-
Shallow
Horizon Niko Onshore/Offshore July 2009 65% 1,134
Guayaguayare-
Deep Horizon Niko Onshore/Offshore July 2009 80% 1,190
Central Range-
Shallow
Horizon Parex Onshore Sept. 2008 32.50% 734
Central Range-
Deep Horizon Parex Onshore Sept. 2008 40% 856
Block 4(b) Niko Offshore April 2011 100% 754
NCMA2 Niko Offshore April 2011 56% 1,020
NCMA3 Niko Offshore April 2011 80% 2,107
Block 5(c) BG Group Offshore July 2005 25% 324
MG Block
(License) Niko Offshore July 2007 70% 223
----------------------------------------------------------------------------
The seismic work commitments on the majority of the blocks have
been fulfilled and as at September 30, 2012, the Company had
remaining minimum work commitments to drill a total of eleven
wells. As at September 30, 2012, the minimum remaining work
commitments under the PSCs were $175 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 six months ended September 30, 2012 for a
complete discussion of these contingencies.
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 is sold to one customer with a current price of
$6.00/Mcf expiring March 31, 2013. Sales of natural gas to this
customer accounted for two percent of the Company's total revenues
during the quarter.
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 holds a 49% working interest and operates the Qara
Dagh Block, which covers approximately 846 square kilometers
onshore. The Qara Dagh Block has an initial exploration period of
five years, extendable on a yearly basis up to a maximum period of
seven contract years. A 2D seismic exploration program was
conducted and data acquired on the block that led to the selection
of a drilling location. An exploratory well was drilled between May
2010 and October 2011. The 2D seismic program and the initial
exploratory well satisfy the work commitments for the first
sub-period of the initial term of the PSC. The second sub-period of
the initial term includes further 2D or 3D seismic data and
drilling one exploration well. The Company's share of the estimated
cost of the remaining work commitment for the exploration period is
$6 million to be spent by May 2013.
SEGMENT PROFIT
India
----------------------------------------------------------------------------
Three months ended Sept 30, Six months ended Sept 30,
(thousands of U.S.
dollars) 2012 2011 2012 2011
----------------------------------------------------------------------------
Natural gas revenue 40,007 63,545 85,120 130,358
Oil and condensate
revenue (1) 12,125 18,884 22,457 37,653
Royalties (2,601) (4,136) (5,456) (8,541)
Profit petroleum (1,016) (1,314) (8,338) (3,237)
Production and
operating expenses (7,318) (7,887) (13,404) (15,340)
Depletion and
depreciation
expense (35,163) (24,539) (73,465) (52,741)
Exploration and
evaluation expenses (414) (85) (354) (542)
Current income tax
recovery /
(expense) (281) (1,180) 2,099 (4,293)
Minimum alternate
tax expense (3,125) (4,917) (4,410) (12,798)
Deferred income tax
reduction 8,409 4,603 3,912 (184)
Change in accounting
estimate - deferred
taxes - - - (57,865)
----------------------------------------------------------------------------
Segment profit /
(loss)(2) 10,623 42,974 8,161 12,470
----------------------------------------------------------------------------
Daily natural gas
sales (Mcf/d) 105,474 167,698 112,926 173,450
Daily oil and
condensate sales
(bbls/d) (1) 1,289 1,889 1,219 1,854
Operating costs
($/Mcfe) $0.68 $0.48 $0.61 $0.43
Depletion rate
($/Mcfe) $3.33 $1.47 $3.30 $1.53
----------------------------------------------------------------------------
(1) Production that is in inventory has not been included in the revenue or
cost amounts indicated.
(2) Production (2) Segment profit / (loss) is a non-IFRS measure as
calculated above.
Segment profit from India includes the results from the
Dhirubhai 1 and 3 natural gas fields and the MA crude oil field in
the D6 Block, the Hazira crude oil and natural gas field and the
Surat gas field.
Revenue and Royalties
The Company's natural gas production for the quarter and
year-to-date was 105 MMcf/d and 113 MMcf/d, respectively, compared
to 168 MMcf/d and 173 MMcf/d respectively in the prior year's
periods. The reduction in production was primarily due to natural
declines and greater than anticipated water production at the D6
Block. Declines are expected to continue unless production volumes
are added from new fields in the D6 Block.
Crude oil production decreased due to a reduction in reservoir
pressure associated with production from the MA field in the D6
Block. The realized prices were $102/bbl and $100/bbl in the
quarter and year-to-date, respectively, compared to $109/bbl and
$111/bbl in the prior year's periods. Decreased production and
sales price contributed to the decrease in crude oil and condensate
revenue.
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 periods compared to the prior year's
periods.
Depletion Expense
The depletion rate increased by $1.77/Mcfe on a year to date
basis as a result of the revision to the reserve volumes and future
costs included in the March 31, 2012 reserve report. The effect of
the increased depletion rate on the depletion expense was partially
offset by decreased production.
Income Taxes
There was a current income tax recovery as a result of the
adjustment to profit petroleum described above, which is deductible
for tax purposes.
Minimum alternate tax expense is calculated on accounting income
from the D6 Block. Higher depletion rates reduced accounting income
and minimum alternate tax expense.
Contingencies
The Company has contingencies related to natural gas sales
contracts and the profit petroleum calculation for the Hazira Field
and related to income taxes for the Hazira Field and the Surat
Block as at September 30, 2012. Refer to note 14(c) to the
consolidated financial statements for six months ended September
30, 2012 for a complete discussion of these contingencies.
Bangladesh
----------------------------------------------------------------------------
Three months ended Sept 30, Six months ended Sept. 30
(thousands of U.S.
dollars) 2012 2011 2012 2011
----------------------------------------------------------------------------
Natural gas revenue 12,436 12,705 25,142 24,322
Condensate revenue 1,856 2,004 3,785 3,964
Profit petroleum (4,836) (4,979) (9,792) (9,577)
Production and
operating expenses (2,641) (1,625) (4,649) (3,721)
Depletion and
depreciation
expense (3,715) (3,064) (7,509) (5,922)
Exploration and
evaluation expenses - (133) (180) (392)
----------------------------------------------------------------------------
Segment profit /
(loss)(1) 3,100 4,908 6,797 8,674
----------------------------------------------------------------------------
Daily natural gas
sales (Mcf/d) 58,341 60,129 59,295 57,712
Daily condensate
sales (bbls/d) 187 191 189 186
Operating costs
($/Mcfe) $0.43 $0.25 $0.39 $0.35
Depletion rate
($/Mcfe) $0.68 $0.54 $0.68 $0.54
----------------------------------------------------------------------------
(1) Segment profit is a non-IFRS measure as calculated above.
Revenue, Profit Petroleum, Depletion and Operating Expenses
The natural gas price was consistent during the periods at
$2.32/Mcf.
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 increased due to increased 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
September 30, 2012. Refer to note 14 to the consolidated financial
statements for the six months ended September 30, 2012 for a
complete discussion of these contingencies.
Indonesia, Kurdistan and Trinidad and Tobago
----------------------------------------------------------------------------
(thousands of U.S. Exploration and evaluation
dollars) expense Asset impairment
---------------------------------------------------------
Six months ended September 30,
---------------------------------------------------------
2012 2011 2012 2011
----------------------------------------------------------------------------
Indonesia (48,426) (27,431) - -
Kurdistan (2,185) (1,599) (38,919) -
Trinidad (36,052) (26,314) - -
----------------------------------------------------------------------------
Indonesia, Kurdistan and Trinidad and Tobago
----------------------------------------------------------------------------
(thousands of U.S. Income tax Depreciation and
dollars) recovery other Segment Profit
---------------------------------------------------------
Six months ended September 30,
---------------------------------------------------------
2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Indonesia 21,058 - 207 (56) (27,161) (27,487)
Kurdistan - - - (12) (41,104) (1,611)
Trinidad - - (47) (40) (36,099) (26,354)
----------------------------------------------------------------------------
Indonesia
Costs of $24 million related to the unsuccessful Candralila-1
and Ratnadewi-1 wells in the Lhokseumawe block and $3 million
related to unsuccessful Lebah-1 well in the North Ganal block were
expensed in the period, costs totaling $10 million relating to
seismic and other exploration projects totaling were incurred for
various blocks, $3 million was spent on new ventures and $5 million
was incurred to operate the branch office. The prior year expense
relates primarily to seismic exploration programs.
Kurdistan
The Company recognized an asset impairment of $39 million when
it reassessed the recoverable amount of the Qara Dagh Block
exploration and evaluation asset.
Trinidad and Tobago
Costs of $20 million related to the unsuccessful Shadow-1 well
in Block 2AB were expensed in the period. Exploration and
evaluation costs expensed directly to income include $7 million of
seismic costs and $6 million payments that are specified in the
various PSCs.
Corporate
----------------------------------------------------------------------------
Three months ended Sept 30, Six months ended Sept 30,
(thousands of U.S.
dollars) 2012 2011 2012 2011
----------------------------------------------------------------------------
Share-based
compensation 3,342 20,424 6,902 26,620
Finance expense 8,853 8,004 17,176 15,741
Foreign exchange loss /
(gain) (3,824) 7,181 968 7,243
Loss on short-term
investments 32 9,783 276 8,568
----------------------------------------------------------------------------
Share-based compensation
The fair value per stock option granted decreased in the periods
due to decreased stock price in the period.
Finance expense
----------------------------------------------------------------------------
Three months ended Sept 30, Six months ended Sept 30,
(thousands of U.S.
dollars) 2012 2011 2012 2011
----------------------------------------------------------------------------
Interest expense 6,007 5,346 12,269 10,873
Accretion expense 2,162 1,951 4,158 3,741
Other 684 707 749 1,127
----------------------------------------------------------------------------
Finance expense 8,853 8,004 17,176 15,741
----------------------------------------------------------------------------
Interest expense increased as a result of the outstanding loan
balance incurred in connection with the credit agreement with no
corresponding borrowings attributable to a credit facility in the
prior year's quarter. Accretion expense is on convertible
debentures and decommissioning obligations. The recorded liability
for the convertible debenture increases as time progresses to the
maturity date resulting in a higher accretion expense than in the
prior period.
Foreign Exchange
----------------------------------------------------------------------------
Three months ended Sept 30, Six months ended Sept 30,
(thousands of U.S.
dollars) 2012 2011 2012 2011
----------------------------------------------------------------------------
Realized foreign
exchange (gain) /
loss 2,826 3,217 2,482 3,368
Unrealized foreign
exchange loss /
(gain) (6,650) 3,964 (1,514) 3,875
----------------------------------------------------------------------------
Total foreign exchange
loss / (gain) (3,824) 7,181 968 7,243
----------------------------------------------------------------------------
The realized foreign exchange losses and gains 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 arose primarily
on the revaluing of the Indian-rupee denominated income tax
receivable and site restoration deposit to U.S. dollars and the
strengthening of the Indian-rupee versus the U.S. dollar.
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.
Netbacks
The following tables outline operating, funds from operations
and earnings netbacks (all of which are non-IFRS measures):
----------------------------------------------------------------------------
Three months ended Three months ended
Sept 30, 2012 Sept 30, 2011
($/Mcfe) India Bangladesh Total India Bangladesh Total
----------------------------------------------------------------------------
Oil and natural
gas revenue 5.01 2.61 4.19 5.00 2.61 4.39
Royalties (0.25) - (0.16) (0.25) - (0.19)
Profit petroleum (0.10) (0.88) (0.37) (0.08) (0.88) (0.28)
Production and
operating expense (0.68) (0.43) (0.61) (0.48) (0.25) (0.43)
----------------------------------------------------------------------------
Operating netback 3.98 1.30 3.05 4.19 1.48 3.49
----------------------------------------------------------------------------
G&A (0.14) (0.08)
Other Income 0.02 -
Net finance
expense (0.56) (0.37)
Current income tax
expense (0.02) (0.05)
Minimum alternate
tax (0.20) (0.22)
----------------------------------------------------------------------------
Funds from
operations
netback 2.15 2.77
----------------------------------------------------------------------------
Production and
operating
expenses (0.02) -
Exploration and
evaluation costs (3.33) (2.04)
Other expense (0.20) (0.92)
Loss on short-term
investment - (0.44)
Deferred income
tax reduction 1.79 0.21
Net finance gain /
(expense) 0.28 (0.29)
Depletion and
depreciation
expense (2.47) (1.25)
----------------------------------------------------------------------------
Earnings netback (1.80) (1.96)
----------------------------------------------------------------------------
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.
----------------------------------------------------------------------------
Six months ended Six months ended
Sept 30, 2012 Sept 30, 2011
($/Mcfe) India Bangladesh Total India Bangladesh Total
----------------------------------------------------------------------------
Oil and natural
gas revenue 4.89 2.62 4.13 4.97 2.63 4.41
Royalties (0.25) - (0.16) (0.25) - (0.19)
Profit petroleum (0.38) (0.89) (0.55) (0.10) (0.89) (0.29)
Production and
operating expense (0.61) (0.39) (0.53) (0.43) (0.35) (0.41)
----------------------------------------------------------------------------
Operating netback 3.65 1.34 2.89 4.19 1.39 3.52
----------------------------------------------------------------------------
G&A (0.13) (0.09)
Other Income 0.01 -
Net finance
expense (0.44) (0.32)
Current income tax
reduction /
(expense) 0.06 (0.10)
Minimum alternate
tax (0.13) (0.29)
----------------------------------------------------------------------------
Funds from
operations
netback 2.26 2.72
----------------------------------------------------------------------------
Production and
operating
expenses (0.02) -
Exploration and
evaluation costs (2.70) (1.33)
Other Expense (1.39) (0.60)
Loss on short-term
investment (0.01) (0.19)
Deferred income
tax reduction 0.75 -
Change in
accounting
estimate -
deferred taxes - (1.30)
Net finance
expense (0.08) (0.20)
Depletion and
depreciation
expense (2.47) (1.32)
----------------------------------------------------------------------------
Earnings netback (3.66) (2.22)
----------------------------------------------------------------------------
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 the exchange amount, which is the amount agreed to
between related parties.
FINANCIAL INSTRUMENTS
The Company's financial instruments consist of short-term
investments, accounts receivable, long-term accounts receivable,
accounts payable and accrued liabilities, borrowings 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 debentures are in Canadian dollars.
The Company is exposed to changes in the market value of the
short-term investments.
The Company is exposed to credit risk with respect to all of its
financial instruments if a customer or counterparty fails to meet
its contractual obligations. The Company has deposited 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 debt component of the convertible debentures has been
recorded net of the fair value of the conversion feature. The fair
value of the conversion feature of the debentures included in
shareholders' equity at the date of issue was $15 million. The fair
value of the conversion feature of the debentures was 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 debentures. Interest and
financing expense of $5 million and $10 million for the three and
six months ended September 30, 2012 were recorded for interest
expense and accretion of the discount on the convertible
debentures.
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 2012, the Company had unrestricted cash of $98
million and a working capital deficit (current assets less current
liabilities) of $283 million. The deficit includes $314 million
related to convertible debentures that mature on December 30,
2012.
On December 30, 2009, the Company entered into Cdn$310 million
of convertible debentures. The debentures bear interest at a rate
of five percent and mature on December 30, 2012. Interest is paid
semi-annually in arrears on January 1st and July 1st of each year.
The debentures are convertible at the option of the holder into
common shares at a conversion price of Cdn$110.50 per common share
until 60 days prior to the maturity date. In May 2011, the terms of
the debentures were altered such that the Company may elect to
convert all or a portion of the debentures at maturity into common
shares at a six percent discount to the weighted average trading
price for the 20 trading days prior to the maturity date. The
Company continues to pursue its options for the repayment of the
convertible debentures and expects resolution well in advance of
maturity. The Company is working with the primary holder of the
debentures regarding the amount and timing of a prepayment at par
plus accrued interest, utilizing cash on hand and advances under
its credit facility.
In January 2012, the Company entered into a three-year facility
agreement for a $225 million revolving credit facility and a $25
million operating facility for general corporate purposes. The
maximum available credit under this agreement is subject to review
based on, among other things, updates to the Company's reserves. On
September 18, 2012, the Company received notice from the syndicate
of lenders of the redetermination of the borrowing base of the
facility which resulted in a reduction of the Company's credit
availability under the facility to an aggregate of $100 million.
The Company has borrowed $41 million against this facility as of
September 30, 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.
The Company's guidance on its capital program for the year ended
March 31, 2013, net of proceeds of negotiated farm-outs and other
arrangements, has been revised from $210 million to $170 million,
due primarily to deferrals of development spending. In addition,
Niko has funded and will continue to fund certain drilling
inventory and other costs related to its drilling program in future
years. Total spending for the year is expected to be approximately
$205 million.
The Company is currently in negotiations with various third
parties regarding farm-outs and other arrangements that have the
potential to provide additional proceeds of $135 million during the
year ended March 31, 2013 and is in preliminary discussions with
additional third parties regarding the farm-out or sale of further
assets.
The Company has a number of contingencies as at September 30,
2012 that could significantly impact liquidity. Refer to note 14 to
the consolidated financial statements for the six months ended
September 30, 2012 for a complete discussion of these
contingencies.
SUMMARY OF QUARTERLY RESULTS
The following tables set forth selected financial information,
in thousands of U.S. dollars unless otherwise indicated, for the
eight most recently completed quarters to September 30, 2012:
----------------------------------------------------------------------------
Dec. 31, Mar. 31, June. 30, Sept. 30,
Three months ended 2011 2012 2012 2012
----------------------------------------------------------------------------
Oil and natural gas
revenue (1) 74,789 71,434 55,099 58,080
Net income (loss) (40,405) (183,324) (92,121) (28,573)
Per share
Basic ($) (0.78) (3.55) (1.78) (0.55)
Diluted ($) (0.78) (3.55) (1.78) (0.55)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec. 31, Mar. 31, June. 30, Sept. 30,
Three months ended 2010 2011 2011 2011
----------------------------------------------------------------------------
Oil and natural gas
revenue (1) 99,220 94,168 88,277 86,810
Net income (loss) 25,806 6,234 (54,983) (43,916)
Per share
Basic ($) 0.50 0.12 (1.07) (0.85)
Diluted ($) 0.50 0.12 (1.07) (0.85)
----------------------------------------------------------------------------
(1) Oil and natural gas revenue is oil and natural gas sales less royalties
and profit petroleum expense.
Net income in the quarters was affected by:
-- D6 gas production declined over the quarters due to well performance.
-- The Company's short-term investments are valued at fair value, which is
the quoted market price. Gains and losses are recognized throughout the
quarters based on fluctuations in the market prices.
-- The Company expensed a portion of the exploration and evaluation costs
during the quarters and the level of activity varies over the periods.
-- The Company impaired assets of $133 million and long term receivables of
$23 million in the quarter ended March 31, 2012 and assets of $39
million in the quarter ended June 30, 2012.
-- For the quarter ended June 30, 2011, there was a change in accounting
estimate related to deferred income tax expense. There was a revision in
the method of estimating the amount of taxable temporary differences
reversing during the tax holiday period.
-- For the quarter ended September 30, 2011, there was a $14 million
expense upon cancellation of stock options to recognize the remainder of
the expense associated with the options.
-- Depletion expense increased in the quarter ended March 31, 2011 and
again in the quarter ended March 31, 2012 as a result of revisions to
the reserves and estimated future costs to develop the reserves.
-- In the quarter ended March 31, 2011, $9.7 million fine was recorded
related to the Company's guilty plea to one count of bribery under the
Corruption of Foreign Public Officials Act relating to two specific
instances that occurred in 2005.
-- There was a deferred income tax recovery in the quarter ended March 31,
2012 related to the revision to the reserve estimate, which increased
the value of the tax holiday for the D6 Block and there were deferred
income tax recoveries related to spending in Indonesia and Trinidad
applied against the deferred income tax liabilities recorded upon the
acquisitions of Voyager Energy Ltd. and Black Gold Energy LLC.
-- An additional $6 million of profit petroleum expense for the Hazira
Field reduced oil and natural gas revenue in the year-to-date. 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.
-- Deferred tax recovery for the quarter increased by $22 million, due to 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.
CRITICAL ACCOUNTING ESTIMATES
The Company makes assumptions in applying certain critical
accounting estimates that are uncertain at the time the accounting
estimate is made and may have a significant effect on the
consolidated financial statements of the Company.
The critical accounting estimates include oil and natural gas
reserves, depletion, depreciation and amortization expense, asset
impairment, decommissioning obligations, the amount and likelihood
of contingent liabilities and income taxes. The critical accounting
estimates are based on variable inputs including:
-- estimation of recoverable oil and natural gas reserves and future cash
flows from the reserves;
-- geological interpretations, exploration activities and success or
failure, and the Company's plans with respect to the property and
financial ability to hold the property;
-- risk-free interest rates;
-- estimation of future abandonment costs;
-- facts and circumstances supporting the likelihood and amount of
contingent liabilities; and
-- interpretation of income tax laws.
A change in a critical accounting estimate can have a
significant effect on net earnings as a result of their impact on
the depletion rate, decommissioning obligations, asset impairments,
losses and income taxes. A change in a critical accounting estimate
can have a significant effect on the value of property, plant and
equipment, decommissioning obligations and accounts payable.
For a complete discussion of the critical accounting estimates,
please refer to the MD&A for the Company's fiscal year ended
March 31, 2012, available at www.sedar.com.
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
The International Accounting Standards Board (IASB) has issued
IFRS 9 "Financial Instruments" to replace IAS 39 "Financial
Instruments: Recognition and Measurement". The new standard
replaces the multiple classification and measurement models for
financial assets and liabilities with a new model that has only two
categories: amortized cost and fair value through profit and loss.
Under IFRS 9, fair value changes due to credit risk for liabilities
designated at fair value through profit and loss would generally be
recorded in other comprehensive income. The Company is 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 consolidated financial statements and
interests in subsidiaries, joint arrangements, associates and
structured entities.
As a result of the new standards described above, the IASB has
amended IAS 28 "Investments in Associates and Joint Ventures" to
prescribe the accounting for investments in associates and to set
out the requirements for the application of the equity method when
accounting for investments in associates and joint ventures.
The IASB published IFRS 13 "Fair Value Measurement" which
provides a precise definition of fair value and a single source of
fair value measurement disclosures requirements for use across
IFRSs.
The IASB issued amendments to IAS 1 Presentation of Financial
Statements requiring companies preparing financial statements in
accordance with IFRS to group together items within other
comprehensive income (OCI) that may be reclassified to the profit
or loss section of the income statement. The amendments apply to
annual periods beginning on or after July 1, 2012.
The IASB reissued IAS 27 "Separate Financial Statements" to
focus solely on accounting and disclosure requirements when an
entity presents separate financial statements that are not
consolidated financial statements.
The Company is currently assessing the disclosure impact of the
standards listed above on its consolidated financial
statements.
DISCLOSURE CONTROLS AND PROCEDURES
The Company's Chief Executive Officer and Chief Financial
Officer are responsible for designing disclosure controls and
procedures or causing them to be designed under their supervision
and evaluating the effectiveness of disclosure controls and
procedures. The Company's Chief Executive Officer and Chief
Financial Officer oversee the design and evaluation process and
have concluded that the design and operation of these disclosure
controls and procedures were effective in ensuring material
information required to be disclosed in quarterly filings or other
reports filed or submitted under applicable Canadian securities
laws is made known to management on a timely basis to allow
decisions regarding required disclosure.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
The Company's Chief Executive Officer and Chief Financial
Officer are responsible for designing internal controls over
financial reporting or causing them to be designed under their
supervision and evaluating the effectiveness of internal controls
over financial reporting. The Company's Chief Executive Officer and
Chief Financial Officer have overseen the design and evaluation of
internal controls over financial reporting and have concluded that
the design and operation of these internal controls over financial
reporting were effective in providing reasonable assurance
regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in
accordance with IFRS.
Because of their inherent limitations, disclosure controls and
procedures and internal controls over financial reporting may not
prevent or detect misstatements, errors or fraud. Control systems,
no matter how well conceived or operated, can provide only
reasonable, not absolute, assurance that the objectives of the
control system are met. There were no changes in internal controls
over financial reporting during the period ended September 30,
2012. In August 2011, the Company hired a dedicated employee to
function as the Chief Compliance Officer and perform the duties
previously fulfilled by an existing officer. The Chief Compliance
Officer reports to the Audit Committee.
RISK FACTORS
In the normal course of business the Company is exposed to a
variety of actual and potential events, uncertainties, trends and
risks. In addition to the risks associated with the use of
assumptions in the critical accounting estimates, financial
instruments, the Company's commitments and actual and expected
operating events, all of which are discussed above, the Company has
identified the following events, uncertainties, trends and risks
that could have material adverse impact:
-- The Company may not be able to find reserves at a reasonable cost,
develop reserves within required time-frames or at a reasonable cost, or
sell these reserves for a reasonable profit;
-- Reserves may be revised due to economic and technical factors;
-- The Company may not be able to obtain approval, or obtain approval on a
timely basis for exploration and development activities;
-- Changing governmental policies, social instability and other political,
economic or diplomatic developments in the countries in which the
Company operates;
-- Changing taxation policies, taxation laws and interpretations thereof;
-- Adverse factors including climate and geographical conditions, weather
conditions and labour disputes;
-- Changes in foreign exchange rates that impact the Company's non-U.S.
dollar transactions; and
-- Changes in future oil and natural gas prices.
For a comprehensive discussion of all identified risks, refer to
the Company's Annual Information Form, which can be found at
www.sedar.com.
The Company has a number of contingencies as at September 30,
2012. Refer to the notes to the Company's consolidated financial
statements for a complete list of the contingencies and any
potential effects on the Company.
OUTSTANDING SHARE DATA
At November 13, 2012, the Company had the following outstanding
shares:
----------------------------------------------------------------------------
Number Cdn$ Amount (1)
----------------------------------------------------------------------------
Common shares 51,641,845 1,325,403,000
Preferred shares Nil Nil
Stock options 3,847,003 -
----------------------------------------------------------------------------
(1) This is the dollar amount received for common shares issued excluding
share issue costs and is presented in Canadian dollars. The U.S. dollar
equivalent at November 13, 2012 is $1,171,439,000.
ABBREVIATIONS
Bcfe billion cubic feet equivalent
Bbl barrel
CEO Chief Executive Officer
CICA Canadian Institute of Chartered Accountants
FPSO floating production, storage and off-loading vessel
GPSA gas purchase and sale agreement
GSPC Gujarat State Petroleum Corporation Ltd.
GOB Government of Bangladesh
GOI Government of India
GRI Government of the Republic of Indonesia
GTT Government of Trinidad and Tobago
IASB International Accounting Standards Board
IFRS International Financial Reporting Standards
Mcf thousand cubic feet
Mcfe thousand cubic feet equivalent
MD&A management's discussion and analysis
MMBtu million British thermal units
MMcfe million cubic feet equivalent
MMcf million cubic feet
PSC production sharing contract
/d per day
All amounts are in thousands of U.S. dollars unless otherwise stated.
All thousand cubic feet equivalent (Mcfe) figures are based on the ratio of
1bbl:6Mcf.
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
----------------------------------------------------------------------------
(unaudited) (thousands of U.S.
dollars) As at Sept 30, 2012 As at Mar 31, 2012
----------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents 98,060 64,495
Restricted cash 3,337 6,790
Accounts receivable (note 3) 71,389 61,247
Short-term investment 475 748
Inventories 11,155 9,961
----------------------------------------------------------------------------
184,416 143,241
----------------------------------------------------------------------------
Restricted cash 14,329 11,283
Long-term accounts receivable 1,360 2,202
Long-term investment 2,796 2,752
Exploration and evaluation assets
(notes 4, 13) 818,417 856,880
Property, plant and equipment
(note 5, 13) 438,191 509,091
Income tax receivable (note 14e) 27,552 34,724
Deferred tax asset 62,226 58,314
----------------------------------------------------------------------------
1,549,287 1,618,487
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued
liabilities 148,004 101,660
Current tax payable 1,301 1,220
Finance lease obligation 4,804 4,804
Convertible debentures(note 6) 313,661 306,052
----------------------------------------------------------------------------
467,770 413,736
----------------------------------------------------------------------------
Decommissioning obligation 41,203 40,017
Finance lease obligation 41,038 43,671
Borrowings 41,000 25,000
Deferred tax liabilities 174,455 195,515
----------------------------------------------------------------------------
765,466 717,939
----------------------------------------------------------------------------
Shareholders' Equity
Share capital (note 7) 1,171,439 1,171,439
Contributed surplus 116,433 104,964
Equity component of convertible
debentures 14,765 14,765
Currency translation reserve (6,577) (2,094)
Deficit (512,239) (388,526)
----------------------------------------------------------------------------
783,821 900,548
----------------------------------------------------------------------------
1,549,287 1,618,487
----------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
----------------------------------------------------------------------------
(unaudited) Three months ended Sept 30, Six months ended Sept 30,
(thousands of U.S.
dollars, except per
share amounts) 2012 2011 2012 2011
----------------------------------------------------------------------------
Oil and natural gas
revenue (note 8) 58,080 86,810 113,179 175,088
Production and
operating expenses (10,026) (9,550) (18,211) (19,105)
Depletion and
depreciation
expense (note 5) (39,204) (27,778) (81,616) (58,969)
Exploration and
evaluation expenses
(note 9) (52,879) (45,117) (89,300) (59,270)
Loss on short-term
investments (32) (9,783) (276) (8,568)
Asset (impairment) /
recovery (note 4) 181 - (38,919) -
Other income
(expenses) 311 - 311 78
Share-based
compensation
expense (note 7) (3,342) (20,424) (6,902) (26,620)
General and
administrative
expenses (note 10) (2,266) (1,857) (4,323) (4,015)
----------------------------------------------------------------------------
(49,177) (27,699) (126,057) (1,381)
----------------------------------------------------------------------------
Finance income 610 465 853 602
Finance expense
(note 11) (8,853) (8,004) (17,176) (15,741)
Foreign exchange
gain (loss) 3,824 (7,181) (968) (7,243)
----------------------------------------------------------------------------
Net finance expense (4,419) (14,720) (17,291) (22,382)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Loss before income
tax (53,596) (42,419) (143,348) (23,763)
----------------------------------------------------------------------------
Current income tax
reduction /
(expense) (285) (1,183) 2,091 (4,290)
Minimum alternate
tax expense (3,125) (4,917) (4,410) (12,797)
Deferred income tax
reduction /
(expense) 28,433 4,603 24,971 (58,049)
----------------------------------------------------------------------------
Income tax (expense) 25,023 (1,497) 22,652 (75,136)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net loss (28,573) (43,916) (120,696) (98,899)
----------------------------------------------------------------------------
Foreign currency
translation gain /
(loss) (9,635) 15,549 (4,483) 14,432
----------------------------------------------------------------------------
Comprehensive loss
for the period (38,208) (28,367) (125,179) (84,467)
----------------------------------------------------------------------------
Loss per share:
(note 12)
Basic $ (0.55) $ (0.85) $ (2.34) $ (1.92)
Diluted $ (0.55) $ (0.85) $ (2.34) $ (1.92)
----------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
----------------------------------------------------------------------------
(unaudited)
(thousands of U.S.
dollars, except Currency
number of common Common shares Contributed translation
shares) (#)Share capital surplus reserve
----------------------------------------------------------------------------
Balance, March 31,
2011 51,526,901 1,162,319 63,037 (8,344)
Options exercised 74,070 6,408 (1,556) -
Share-based
compensation expense - - 31,337 -
Net loss for the
period - - - -
Payment of
dividends(1) - - - -
Foreign currency
translation - - - 14,432
----------------------------------------------------------------------------
Balance, September
30, 2011 51,600,971 1,168,727 92,818 6,088
----------------------------------------------------------------------------
Options exercised 40,874 2,712 (732) -
Share-based
compensation expense - - 12,878 -
Net loss for the
period - - - -
Payment of
dividends(1) - - - -
Foreign currency
translation - - - (8,182)
----------------------------------------------------------------------------
Balance, March 31,
2012 51,641,845 1,171,439 104,964 (2,094)
----------------------------------------------------------------------------
Options exercised - - - -
Share-based
compensation (note
7) - - 11,469 -
Net loss for the
period - - - -
Payment of
dividends(1) - - - -
Foreign currency
translation - - - (4,483)
----------------------------------------------------------------------------
Balance, September
30, 2012 51,641,845 1,171,439 116,433 (6,577)
----------------------------------------------------------------------------
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS'
EQUITY
----------------------------------------------------------------------------
(unaudited)
(thousands of U.S.
dollars, except Equity component
number of common of convertible
shares) debentures Deficit Total
----------------------------------------------------------------------------
Balance, March 31,
2011 14,765 (53,392) 1,178,385
Options exercised - - 4,852
Share-based
compensation expense - - 31,337
Net loss for the
period - (98,899) (98,899)
Payment of
dividends(1) - (6,391) (6,391)
Foreign currency
translation - - 14,432
----------------------------------------------------------------------------
Balance, September
30, 2011 14,765 (158,682) 1,123,716
----------------------------------------------------------------------------
Options exercised - - 1,980
Share-based
compensation expense - - 12,878
Net loss for the
period - (223,729) (223,729)
Payment of
dividends(1) - (6,115) (6,115)
Foreign currency
translation - - (8,182)
----------------------------------------------------------------------------
Balance, March 31,
2012 14,765 (388,526) 900,548
----------------------------------------------------------------------------
Options exercised - - -
Share-based
compensation (note
7) - - 11,469
Net loss for the
period - (120,696) (120,696)
Payment of
dividends(1) - (3,017) (3,017)
Foreign currency
translation - - (4,483)
----------------------------------------------------------------------------
Balance, September
30, 2012 14,765 (512,239) 783,821
----------------------------------------------------------------------------
(1) The Company paid dividends of $0.12 per share in the six months ended
September 30, 2011 and $0.06 per share in the six months ended September 30,
2012.
The accompanying notes are an integral part of these financial statements.
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CASHFLOWS
----------------------------------------------------------------------------
(unaudited) Three months ended Sept 30, Six months ended Sept 30,
(thousands of U.S.
dollars) 2012 2011 2012 2011
----------------------------------------------------------------------------
Cash flows from
operating
activities:
Net loss (28,573) (43,916) (120,696) (98,899)
Adjustments for:
Depletion and
depreciation
expense 39,204 27,776 81,616 58,969
Accretion expense 2,162 1,951 4,158 3,741
Deferred income tax
(reduction) /
expense (28,433) (4,603) (24,972) 58,049
Unrealized foreign
exchange loss /
(gain) (6,650) 3,964 (1,514) 3,875
Loss on short-term
investment 32 9,783 276 8,568
Asset impairment (181) (69) 38,919 (69)
Exploration and
evaluation write-
off 37,015 43,191 49,482 56,046
Share-based
compensation
expense 5,533 19,688 10,935 27,637
Change in non-cash
working capital (1,333) (3,557) 4,307 13,184
Change in long-term
accounts receivable 10,401 (2,249) 8,619 25,141
----------------------------------------------------------------------------
Net cash from
operating
activities 29,177 51,959 51,130 156,242
----------------------------------------------------------------------------
Cash flows from
investing
activities:
Exploration and
evaluation
expenditures (60,155) (59,526) (93,053) (175,109)
Property, plant and
equipment
expenditures (7,866) (5,794) (11,060) (8,804)
Proceeds from other
arrangements (note
4) 36,000 - 36,000 -
Farm-out proceeds
(note 4) 9,203 - 9,203 -
Restricted cash
contributions (900) (2,000) (3,102) (2,600)
Release of
restricted cash 1,300 - 3,319 4,459
Disposition of
investments - - - 1,106
Change in non-cash
working capital 43,028 11,250 30,813 4,283
----------------------------------------------------------------------------
Net cash used in
investing
activities 20,610 (56,070) (27,880) (176,665)
----------------------------------------------------------------------------
Cash flows from
financing
activities:
Proceeds from
issuance of share
capital, net of
issuance costs - 4,743 - 4,852
Change in loans and
borrowings - - 16,000 -
Reduction in
finance lease
liability (1,350) (1,206) (2,633) (2,347)
Dividends paid - (3,166) (3,017) (6,391)
----------------------------------------------------------------------------
Net cash from
financing
activities (1,350) 371 10,350 (3,886)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Change in cash and
cash equivalents 48,437 (3,740) 33,600 (24,309)
----------------------------------------------------------------------------
Effect of
translation on
foreign currency
cash 36 (2,021) (35) (608)
Cash and cash
equivalents,
beginning of period 49,587 89,186 64,495 108,342
----------------------------------------------------------------------------
Cash and cash
equivalents, end of
period 98,060 83,425 98,060 83,425
----------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL
STATEMENTS
1. General Information
Niko Resources Ltd. (the "Company") is a limited company
incorporated in Alberta, Canada. The addresses of its registered
office and principal place of business is 4600, 400 - 3 Avenue SW,
Calgary, AB, T2P4H2. The Company is engaged in the exploration for
and development and production of oil and natural gas in the
countries listed in note 13. The Company's common shares are traded
on the Toronto Stock Exchange.
2. Basis of Presentation
The condensed interim consolidated financial statements include
the accounts of Niko Resources Ltd. (the "Company") and all of its
subsidiaries. The majority of the exploration, development and
production activities of the Company are conducted jointly with
others and, accordingly, these financial statements reflect only
the Company's proportionate interest in such activities. The
condensed interim consolidated financial statements have been
prepared in accordance with IAS 34 - Interim Financial Reporting
using accounting policies consistent with International Financial
Reporting Standards ("IFRS").
The interim consolidated financial statements have been prepared
following the same accounting policies and methods of application
as the audited consolidated financial statements for the fiscal
year ended March 31, 2012. The disclosures provided herein are
incremental to those included with the annual consolidated
financial statements and the notes thereto for the year ended March
31, 2012. The interim consolidated financial statements should be
read in conjunction with the consolidated financial statements and
notes thereto for the year ended March 31, 2012.
The consolidated financial statements are presented in US
dollars and all values are rounded to the nearest thousand dollars
($000), except where otherwise indicated.
These financial statements were authorized for issue by the
Board of Directors on November 13, 2012.
3. Accounts receivable
----------------------------------------------------------------------------
(thousands of U.S. dollars) As at As at
Sept 30, 2012 March 31, 2012
----------------------------------------------------------------------------
Oil and gas revenues receivable 22,190 28,033
Receivable from joint venture partners 23,022 13,004
Advances to vendors 3,593 1,751
Prepaid expenses and deposits 5,302 4,816
VAT receivable 12,444 9,405
Other receivables 4,838 4,238
----------------------------------------------------------------------------
71,389 61,247
----------------------------------------------------------------------------
4. Exploration and evaluation assets
----------------------------------------------------------------------------
(thousands of U.S. dollars) Six months ended Year ended
Sept 30, 2012 March 31, 2012
----------------------------------------------------------------------------
Opening balance 856,880 762,221
Additions (note 13) 93,705 164,976
Transfers - 5,354
Expensed (49,592) (71,500)
Impairment (38,384) -
Disposals and other arrangements (45,203) (2,355)
Foreign currency translation 1,011 (1,816)
----------------------------------------------------------------------------
Closing balance 818,417 856,880
----------------------------------------------------------------------------
The Company expensed $50 million of exploration costs related to
three unsuccessful exploration wells in Indonesia and one
unsuccessful exploration well in Trinidad. The Company also
estimated the recoverable amount of Kurdistan exploration and
evaluation assets and recognized an impairment of $38 million. In
addition, 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 obligations for future drilling
commitments.
5. Property, plant and equipment
a. Development assets
----------------------------------------------------------------------------
(thousands of U.S. dollars) Six months ended Year ended
Sept 30, 2012 March 31, 2012
----------------------------------------------------------------------------
Opening balance 16,988 18,421
Additions 2,971 7,447
Expensed - -
Transfers to other asset categories - (8,880)
----------------------------------------------------------------------------
Closing balance 19,959 16,988
----------------------------------------------------------------------------
b. Producing assets
----------------------------------------------------------------------------
(thousands of U.S. dollars) Six months ended Year ended
Sept 30, 2012 March 31, 2012
----------------------------------------------------------------------------
Cost
Opening balance 1,042,869 1,019,696
Additions - 16,458
Transfers from other asset categories - 6,791
Foreign currency translation 43 (76)
----------------------------------------------------------------------------
Closing balance 1,042,912 1,042,869
----------------------------------------------------------------------------
Accumulated depletion
Opening balance (453,957) (312,767)
Additions (80,051) (141,266)
Foreign currency translation (42) 76
----------------------------------------------------------------------------
Closing balance (534,050) (453,957)
----------------------------------------------------------------------------
Impairment (133,415) (133,415)
----------------------------------------------------------------------------
Net producing assets 375,447 455,497
----------------------------------------------------------------------------
c. Other Property, plant and equipment
----------------------------------------------------------------------------
Office
equipment,
furniture
(thousands of U.S. Land and Transportation and
dollars) buildings Vehicles fittings Pipelines Total
----------------------------------------------------------------------------
Cost
Balance, March 31,
2012 18,346 2,376 8,754 10,772 40,248
Additions /
Transfers 3 - 383 3 389
Disposals - (27) (136) - (163)
Foreign currency
translation - - 58 - 58
----------------------------------------------------------------------------
Balance, Sept 30,
2012 18,349 2,349 9,059 10,775 40,532
----------------------------------------------------------------------------
Accumulated
depreciation
Balance, March 31,
2012 (6,127) (1,482) (4,449) (7,341) (19,399)
Additions (508) (87) (723) (247) (1,565)
Disposals - - - - -
Foreign currency
translation - - (43) - (43)
----------------------------------------------------------------------------
Balance, Sept 30,
2012 (6,635) (1,569) (5,215) (7,588) (21,007)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value,
Sept 30, 2012 11,714 780 3,844 3,187 19,525
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Office
equipment,
furniture
(thousands of U.S. Land and Transportation and
dollars) buildings Vehicles fittings Pipelines Total
----------------------------------------------------------------------------
Cost
Balance, March 31,
2011 18,108 2,395 5,978 10,752 37,233
Additions 238 - 2,907 20 3,165
Disposals - (19) (89) - (108)
Foreign currency
translation loss - - (42) - (42)
----------------------------------------------------------------------------
Balance, March 31,
2012 18,346 2,376 8,754 10,772 40,248
----------------------------------------------------------------------------
Accumulated
depreciation
Balance, March 31,
2011 (4,880) (1,148) (3,390) (6,738) (16,156)
Additions (1,247) (352) (1,126) (603) (3,328)
Disposals - 18 34 - 52
Foreign currency
translation gain - - 33 - 33
----------------------------------------------------------------------------
Balance, March 31,
2012 (6,127) (1,482) (4,449) (7,341) (19,399)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value,
March 31, 2012 12,219 894 4,305 3,431 20,849
----------------------------------------------------------------------------
d. Capital work-in-progress
----------------------------------------------------------------------------
As at As at
(thousands of U.S. dollars) Sept 30, 2012 March 31, 2012
----------------------------------------------------------------------------
Capital work-in-progress 23,260 15,757
----------------------------------------------------------------------------
6. Convertible Debentures
The Company issued Cdn$310 million, 5 percent convertible
debentures (the "Debentures") on December 30, 2009. The Debentures
mature on December 30, 2012 with interest paid semi-annually in
arrears on January 1st and July 1st of each year. The Debentures
are convertible at the option of the holder into common shares of
the Company at a conversion price of Cdn$110.50 per common share
until 60 days prior to the maturity date. The Company has the
option to convert all or a portion of the Debentures at maturity
into common shares at a 6 percent discount to the weighted average
trading price for the 20 trading days prior to the maturity date.
The Company continues to pursue its options for the repayment of
the convertible debentures and expects resolution well in advance
of maturity. The Company is working with the primary holder of the
debentures regarding the amount and timing of a prepayment at par
plus accrued interest, utilizing cash on hand and advances under
its credit facility.
7. Share capital
a. Fully paid ordinary shares
The Company has authorized for issue an unlimited number of
common shares and an unlimited number of preferred shares. The
common shares issued are fully paid and the shares have no par
value. No preferred shares have been issued.
b. Share options granted under the employee share option
plan
The Company has reserved for issue 5,164,184 common shares for
granting under stock options to directors, officers, and employees.
The options become vested immediately to five years after the date
of grant and expire one to six years after the date of grant. The
stock options are settled in equity.
Stock option transactions for the respective periods were as
follows:
----------------------------------------------------------------------------
Six months ended Year ended
Sept 30, 2012 March 31, 2012
----------------------------------------------------------------------------
Weighted Weighted
average average
Number of exercise price Number of exercise price
options (Cdn$) options (Cdn$)
----------------------------------------------------------------------------
Opening balance 3,978,003 75.62 4,243,897 85.37
Granted 247,625 26.16 1,160,750 55.70
Forfeited (31,000) 70.73 (155,750) 86.43
Cancelled - - (587,500) 102.13
Expired (190,750) 90.52 (568,450) 80.97
Exercised - - (114,944) 58.01
----------------------------------------------------------------------------
Closing balance 4,003,878 71.89 3,978,003 75.62
----------------------------------------------------------------------------
Exercisable 1,022,249 85.72 952,624 85.19
----------------------------------------------------------------------------
The following table summarizes stock options outstanding and
exercisable under the plan at Sept 30, 2012:
----------------------------------------------------------------------------
Outstanding Options Exercisable Options
----------------------------------------------------------------------------
Weighted Weighted
average average
Remaining exercise exercise
life price price
Exercise Price Options (years) (Cdn$) Options (Cdn$)
----------------------------------------------------------------------------
13.48 - 19.99 115,500 4.44 13.92 - -
20.00 - 29.99 - - - - -
30.00 - 39.99 110,500 3.74 36.22 - -
40.00 - 49.99 1,214,066 1.97 47.62 154,811 49.35
50.00 - 59.99 252,375 3.37 52.04 - -
60.00 - 69.99 204,375 2.74 63.24 41,000 63.55
70.00 - 79.99 66,750 2.33 73.41 6,750 76.87
80.00 - 89.99 593,563 1.19 86.41 314,563 89.07
90.00 - 99.99 1,056,750 1.34 95.86 458,000 95.64
100.00 - 109.99 365,249 2.45 104.36 42,750 106.63
110.00 - 112.64 24,750 2.11 111.09 4,375 111.30
----------------------------------------------------------------------------
4,003,878 1.99 71.89 1,022,249 85.72
----------------------------------------------------------------------------
The weighted average share price during the six months ended
September 30, 2012 was $21.17 (2011 - $66.13).
c. Fair value measure of equity instruments granted
The fair value of each option granted was estimated on the date
of grant using the Black-Scholes option-pricing model with the
following weighted average inputs:
----------------------------------------------------------------------------
Three Three Six Months
months months Six months ended
ended Sept ended Sept ended Sept Sept.30,
30, 2012 30, 2011 30, 2012 2011
----------------------------------------------------------------------------
Grant-date fair value Cdn$5.04 Cdn$20.18 Cdn$8.55 Cdn$24.85
Market price per share Cdn$13.92 Cdn$57.05 Cdn$26.16 Cdn$74.39
Exercise price per option Cdn$13.92 Cdn$57.05 Cdn$26.16 Cdn$74.39
Expected volatility 51% 42% 47% 41%
Expected life (years) 4.1 4.5 3.9 4.1
Expected dividend rate 1.7% 0.4% 1.1% 0.3%
Risk-free interest rate 1.2% 1.7% 1.3% 2.1%
Expected forfeiture rate 9.5% 6.0% 9.2% 6.0%
----------------------------------------------------------------------------
Expected volatility was determined based on the historical
movements in the closing price of the Company's stock for a length
of time equal to the expected life of each option. See note d.
below for categorization of share-based payment expense during the
period.
d. Share-based compensation disclosure
The Company prepares its statement of comprehensive income
(loss) classifying costs according to function as opposed to the
nature of the costs. As a result, share-based compensation expense
is charged to various other headings in the statement of
comprehensive income (loss).
----------------------------------------------------------------------------
Three months Three months Six months Six months
ended Sept ended Sept ended Sept ended Sept
(thousands of U.S. dollars) 30, 2012 30, 2011 30, 2012 30, 2011
----------------------------------------------------------------------------
Share-based compensation
expense included in:
Exploration and evaluation
assets 268 122 534 475
Operating expense 330 493 637 1,017
Exploration and evaluation
expense 1,861 1,996 3,397 3,225
Share-based compensation
expense 3,342 20,424 6,902 26,620
----------------------------------------------------------------------------
Total 5,801 23,035 11,470 31,337
----------------------------------------------------------------------------
8. Revenue
----------------------------------------------------------------------------
Three Three
months months Six months Six months
ended Sept ended Sept ended Sept ended Sept
(thousands of U.S. dollars) 30, 2012 30, 2011 30, 2012 30, 2011
----------------------------------------------------------------------------
Natural gas sales 52,444 76,294 110,262 154,679
Oil and condensate sales 14,090 20,992 26,497 41,765
Less:
Royalties (2,602) (4,183) (5,450) (8,542)
Government's share of
profit petroleum (5,852) (6,293) (18,130) (12,814)
----------------------------------------------------------------------------
Oil and natural gas revenue 58,080 86,810 113,179 175,088
----------------------------------------------------------------------------
Revenues from oil and gas sales to Petrobangla comprised 21
percent of natural gas, oil and condensate sales for the six months
ended September 30, 2012 (2011 - 14 percent).
In June 2012, the Company recorded a $6 million increase in
profit petroleum expense due to a court ruling indicating the
36-inch pipeline is not eligible for cost recovery. The Company has
appealed the decision with division bench of Delhi High Court.
9. Exploration and evaluation expenses
----------------------------------------------------------------------------
Three months Three months Six months Six months
ended Sept ended Sept ended Sept ended Sept
(thousands of U.S. dollars) 30, 2012 30, 2011 30, 2012 30, 2011
----------------------------------------------------------------------------
Geological and geophysical 6,555 35,071 18,274 38,992
Exploration and evaluation
(well cost) 37,448 564 49,592 579
General and administrative 3,835 4,005 8,672 7,726
Production sharing contract
annual payments 1,797 3,191 6,492 7,433
New ventures 1,383 290 2,873 1,315
Share-based compensation 1,861 1,996 3,397 3,225
----------------------------------------------------------------------------
Exploration and evaluation 52,879 45,117 89,300 59,270
----------------------------------------------------------------------------
10. General and administrative expenses
----------------------------------------------------------------------------
Three Three
months months Six months Six months
ended Sept ended Sept ended Sept ended Sept
(thousands of U.S. dollars) 30, 2012 30, 2011 30, 2012 30, 2011
----------------------------------------------------------------------------
Salaries 927 953 2,054 1,191
Legal fees 84 819 187 2,855
Consultants 636 259 708 419
Rent 148 191 286 382
Management fees 122 164 264 327
Audit fees 172 138 212 251
Insurance - - 10 -
Others 536 104 1,023 (221)
Head office costs
reclassified according to
function (359) (771) (421) (1,189)
----------------------------------------------------------------------------
General and administrative
expense 2,266 1,857 4,323 4,015
----------------------------------------------------------------------------
The Company prepares its statement of comprehensive income
(loss) classifying costs according to function as opposed to the
nature of the costs. As a result, general and administrative
expenses are charged to various other headings in the statement of
comprehensive income / (loss). General and administrative expenses
of $4 million and $9 for the three and six months ended September
30, 2012 (2011 - $4 million and $8 million) are categorized as
exploration and evaluation expenses and of $3 million and $5
million for the three and six months ended September 30, 2012,
(2011 - $3 million and $6 million) are categorized as production
and operating expenses.
----------------------------------------------------------------------------
Three months Three months Six months Six months
ended Sept ended Sept ended Sept ended Sept
(thousands of U.S. dollars) 30, 2012 30, 2011 30, 2012 30, 2011
----------------------------------------------------------------------------
Audit fees 201 162 243 325
Management fees 125 167 270 332
Legal fees 261 900 460 3,137
Salary 3,286 3,457 6,987 5,374
Insurance 1,573 1,562 3,332 3,156
Security 208 226 425 447
Rent 521 386 1,008 776
Travel 116 215 357 437
Consultants 890 313 1,063 526
Non-operating and other 1,995 487 4,664 1,216
Office costs 342 740 579 1,510
----------------------------------------------------------------------------
Total 9,518 8,615 19,388 17,236
----------------------------------------------------------------------------
11. Finance expense
----------------------------------------------------------------------------
Three months Three months Six months Six months
ended Sept ended Sept ended Sept ended Sept
(thousands of U.S. dollars) 30, 2012 30, 2011 30, 2012 30, 2011
----------------------------------------------------------------------------
Interest expense related to
capital lease 1,360 1,472 2,759 3,012
Interest expense on long-
term debt 753 - 1,781 -
Interest expense on
convertible debentures 3,894 3,874 7,729 7,861
Accretion expense on
convertible debentures 1,459 1,358 2,765 2,624
Accretion expense on
decommissioning
obligations 703 593 1,393 1,117
Bank fees and charges and
other finance costs 684 707 749 1,127
----------------------------------------------------------------------------
Finance expense 8,853 8,004 17,176 15,741
----------------------------------------------------------------------------
12. Earnings per share
The earnings used in the calculation of basic and diluted per
share amounts are as follows:
----------------------------------------------------------------------------
(thousands of U.S. dollars) Three Three
months months Six months Six months
ended Sept ended Sept ended Sept ended Sept
30, 2012 30, 2011 30, 2012 30, 2011
----------------------------------------------------------------------------
Net loss (28,573) (43,916) (120,696) (98,899)
----------------------------------------------------------------------------
A reconciliation of the weighted average number of ordinary
shares for the purpose of calculating basic earnings per share to
the weighted average number of ordinary shares for the purpose of
calculating diluted earnings per share is as follows:
----------------------------------------------------------------------------
Three months Three months Six months Six months
ended Sept ended Sept ended Sept ended Sept
(thousands of U.S. dollars) 30, 2012 30, 2011 30, 2012 30, 2011
----------------------------------------------------------------------------
Weighted average number of
common shares used in the
calculation of basic and
diluted earnings per share 51,641,845 51,576,804 51,641,845 51,552,168
----------------------------------------------------------------------------
As a result of the net loss in the periods ended September 30,
2012 and 2011, the outstanding stock options of 4,003,878 and
3,766,752, respectively, and shares issuable upon conversion of the
outstanding debentures of 2,805,430 as at September 30, 2012 and
2011 were considered anti-dilutive to the loss per share and were
excluded from the weighted average number of common shares for the
purposes of diluted earnings per share. The average market value of
the Company's common shares for purposes of calculating the
dilutive effect of stock options for the periods was based on
quoted market prices for the periods that the options were
outstanding. The number of shares issuable upon conversion of the
outstanding debentures is based on the conversion price of
Cdn$110.50 per common share, which is applicable to conversion at
the option of the holder until 60 days prior to the maturity
date.
13. Segmented Information
a. Products and services from which reportable segments derive
their revenues
The Company's operations are conducted in one business sector,
the oil and natural gas industry. All revenues are from external
customers. All of Bangladesh sales are received from one customer
and this customer accounted for 21 percent of sales during the six
months ended September 30, 2012.
b. Determination of reportable segments
Geographical areas are used to identify the Company's reportable
segments. A geographic segment is considered a reportable segment
once its activities are regularly reviewed by the Company's
management. The accounting policies of the information of the
reportable segments are the same as those described in the summary
of significant accounting policies.
c. Segment assets and liabilities, revenues and results
----------------------------------------------------------------------------
Six months ended Year ended
September 30, 2012 March 31, 2012
----------------------------------------------------------------------------
Additions to:
----------------------------------------------------------------------------
Exploration Property,
and plant and Exploration Property,
evaluation equipment and evaluation plant and
Segment assets (E&E) (PP&E) assets equipment
----------------------------------------------------------------------------
Bangladesh - 955 63 3,004
India 111 292 2,432 18,599
Indonesia 66,737 8,214 16,676 -
Kurdistan 373 (565)(1) 24,795 -
Madagascar 2 - 9 -
Pakistan - - 248 -
Trinidad 26,482 1,913 120,753 1,466
All other - 51 - 3,165
----------------------------------------------------------------------------
Total 93,705 10,860 164,976 26,234
----------------------------------------------------------------------------
(1) Negative additions in property, plant and equipment for Kurdistan are
the result of impairment of inventory.
----------------------------------------------------------------------------
As at September 30, 2012 As at March 31, 2012
----------------------------------------------------------------------------
Segment Total Total
Total E&E Total PP&E assets Total E&E Total PP&E assets
----------------------------------------------------------------------------
Bangladesh 4,737 26,579 40,995 4,737 31,605 46,617
India 136,214 396,609 669,644 136,104 454,421 730,134
Indonesia 503,791 10,221 555,871 510,161 - 534,923
Kurdistan 11,532 - 14,505 50,519 749 54,573
Madagascar 1,211 44 1,347 1,209 - 1,377
Pakistan 248 15 323 248 - 310
Trinidad 160,684 3,581 189,246 153,902 1,467 190,617
All other - 1,142 77,356 - 20,849 59,936
----------------------------------------------------------------------------
Total 818,417 438,191 1,549,287 856,880 509,091 1,618,487
----------------------------------------------------------------------------
To view tables associated with this release, please visit the
following link: http://media3.marketwire.com/docs/1113nko.pdf.
14. Contingent Liabilities
a. During the year ended March 31, 2006, a group of petitioners
in Bangladesh (the petitioners) filed a writ with the High Court
Division of the Supreme Court of Bangladesh (the High Court)
against various parties including Niko Resources (Bangladesh) Ltd.
(NRBL), a subsidiary of the Company.
In November 2009, the High Court ruled on the writ. Both the
Company and the petitioners have the right to appeal the ruling to
the Supreme Court. The ruling can be summarized as follows:
----------------------------------------------------------------------------
Petitioner Request High Court Ruling
----------------------------------------------------------------------------
That the Joint Venture Agreement for The Joint Venture Agreement for Feni
the Feni and Chattak fields be and Chattak fields is valid.
declared null and illegal.
----------------------------------------------------------------------------
That the government realize from the The compensation claims should be
Company compensation for the natural decided by the lawsuit described in
gas lost as a result of the note (b) below or by mutual
uncontrolled flow problems as well agreement.
as for damage to the surrounding
area.
----------------------------------------------------------------------------
That Petrobangla withhold future Petrobangla to withhold future
payments to the Company relating to payments to the Company related to
production from the Feni field production from the Feni field until
($27.9 million as at September 30, the lawsuit described in note (b)
2012). below is resolved or both parties
agree to a settlement.
----------------------------------------------------------------------------
That all bank accounts of the The ruling did not address this
Company maintained in Bangladesh be issue, therefore the previous ruling
frozen. stands. Funds in the Company's bank
accounts maintained in Bangladesh
cannot be repatriated pending
resolution of the lawsuit described
in note (b) below.
----------------------------------------------------------------------------
On January 7, 2010, NRBL requested an arbitration proceeding
with the International Centre for the Settlement of Investment
disputes (ICSID). The arbitration is between NRBL and three
respondents: The People's Republic of Bangladesh; Bangladesh Oil,
Gas & Mineral Corporation (Petrobangla); and Bangladesh
Petroleum Exploration & Production Company Limited (Bapex). The
arbitration hearing will attempt to settle all compensation claims
described in this note and note (b). ICSID registered the request
on May 24, 2010.
In June 2010, the Company filed an additional proceeding with
ICSID to resolve its claims for payment from Petrobangla in
accordance with the Gas Purchase and Sale Agreement with
Petrobangla to receive all amounts for previously delivered
gas.
b. During the year ended March 31, 2006, Niko Resources
(Bangladesh) Ltd. received a letter from Petrobangla demanding
compensation related to the uncontrolled flow problems that
occurred in the Chattak field in January and June 2005. Subsequent
to March 31, 2008, Niko Resources (Bangladesh) Ltd. was named as a
defendant in a lawsuit that was filed in Bangladesh by Petrobangla
and the Republic of Bangladesh demanding compensation as
follows:
(i) taka 422,026,000 ($5.17 million) for 3 Bcf of free natural
gas delivered from the Feni field as compensation for the burnt
natural gas;
(ii) taka 828,579,000 ($10.15 million) for 5.89 Bcf of free
natural gas delivered from the Feni field as compensation for the
subsurface loss;
(iii) taka 845,560,000 ($10.36 million) for environmental
damages, an amount subject to be increased upon further
assessment;
(iv) taka 6,330,398,000 ($77.53 million) for 45 Bcf of natural
gas as compensation for further subsurface loss; and
(v) any other claims that arise from time to time.
ICSID has registered the request for arbitration of the issues
indicated above as discussed in note 14(a). In addition, the
Company will actively defend itself against the lawsuit, which may
take an extended period of time to settle. Alternatively, the
Company may attempt to receive a stay order on the lawsuit pending
either a settlement and/or results of ICSID arbitration. The
Company believes that the outcome of the lawsuit and/or ICSID
arbitration and the associated cost to the Company, if any, are not
determinable. As such, no amounts have been recorded in these
consolidated financial statements. Settlement costs, if any, will
be recorded in the period of determination.
c. In accordance with natural gas sales contracts to customers
of production from the Hazira field in India, the Company had
committed to deliver certain minimum quantities and was unable to
deliver the minimum quantities for a period ending December 31,
2007. The Company's partner in the Hazira field delivered the
shortfall volumes in return for either: (a) delivery of replacement
volumes five times greater than the shortfall; (b) a cash payment;
or (c) a combination of (a) and (b). The Company's partner has
served a notice of arbitration as the Company is unable to supply
gas from the D6 block to the partner and the arbitration process
has commenced. The Company estimates the cash amount to settle the
contingency at US$11.6 million. The Company believes that the
agreement with its partner is not effective as the Government of
India's gas utilization policy prevents the Company from supplying
the gas to the partner. The Company believes that the outcome is
not determinable.
The Company may not be able to supply gas to a customer in
Hazira whose contract runs until mid-2016. The Company had
previously planned to supply gas from the D6 Block to the customer.
Due to a change in the gas allocation policy by the Government of
India, the Company may not be able to fulfill the contract with gas
supply from the D6 Block. The Company has notified the customer
that the underperformance of reservoir is a force majeure event.
The customer does not agree with this position and has served a
notice of arbitration on the Company. The matter is subjudice in a
court of law. The Company believes that the outcome is not
determinable.
d. In a May 2012 letter, the GOI alleged that the joint venture
partners in the D6 Block are in breach of the PSC for the D6 Block
as they failed to drill all of the wells and attain production
levels contemplated in the Addendum to the Initial Development Plan
for the Dhirubhai 1 and 3 fields. The GOI has further asserted that
joint venture costs totalling $1.462 billion (the Company's share
totalling $146.2 million) are therefore disallowed for cost
recovery. The joint venture partners are of the view that the
disallowance of recovery of costs incurred by the joint venture has
no basis in the terms of the PSC and that there are strong grounds
to challenge the action of the GOI. Reliance has commenced
arbitration proceedings against the GOI challenging the allegations
and the disallowance of cost recovery. To the extent that any
amount of joint venture costs are disallowed, such amount would be
treated as profit petroleum in the future, a portion of which would
be payable to the GOI under the PSC. Because profit petroleum
percentages for the joint venture partners and the GOI change as
the joint venture partners recover specified percentages of their
investments, the potential impact on the Company's future profit
petroleum expense (which represents the GOI's share of profit
petroleum) is dependent on the future revenue and expenditures in
the block and cannot be precisely determined at this time. Based on
the economic inputs used for the proved and proved plus probable
reserves in the March 31, 2012 Ryder Scott Report, the Corporation
has estimated the potential undiscounted before tax impact to be
between $25 to $46 million. The arbitral tribunal is in the process
of being constituted with Reliance and the GOI having nominated two
of the three arbitrators. The outcome of these proceedings is not
determinable.
e. The Company has filed its income tax returns in India for the
taxation years 1998 through 2008 under provisions that provide for
a tax holiday deduction for eligible undertakings related to the
Hazira and Surat fields.
The Company has received unfavorable tax assessments related to
taxation years 1999 through 2008. The assessments contend that the
Company is not eligible for the requested tax holiday because: a)
the holiday only applies to "mineral oil" which excludes natural
gas; and/or b) the Company has inappropriately defined
undertakings.
In India, there are potentially four levels of appeal related to
tax assessments: Commissioner Income Tax - Appeals ("CITA"); the
Income Tax Appellate tribunal ("ITAT"); the High Court; and the
Supreme Court. For taxation years 1999 to 2004, the Company has
received favorable rulings at ITAT and the revenue Department has
appealed to the High Court. For the 2005 taxation year, the Company
has received a favorable ruling at CITA. For the 2006, 2007 and
2008 taxation years, the Company has appealed to CITA, however,
CITA has agreed to wait for the High Court ruling on previous years
prior to their ruling. The taxation years 2009 and later have not
yet been assessed by the tax authorities.
In August 2009, the Government of India through the Finance
(No.2) Act 2009 amended the tax holiday provisions in the Income
Tax Act (Act). The amended Act provides that the blocks licensed
under the NELP-VIII round of bidding and starting commercial
production on or after April 1, 2009 are eligible for the tax
holiday on production of natural gas. However, the budget did not
address the issue of whether the tax holiday is applicable to
natural gas production from blocks that have been awarded under
previous rounds of bidding, which includes all of the Company's
Indian blocks. The Company has previously filed and recorded its
income taxes on the basis that natural gas will be eligible for the
tax holiday.
With respect to "undertakings" eligible for the tax holiday
deduction, the Act was amended to include an "explanation" on how
to determine undertakings. The Act now states that all blocks
licensed under a single contract shall be treated as a single
undertaking. The "explanation" is described in the amendment as
having retrospective effect from April 1, 2000. Since tax holiday
provisions became effective April 1, 1997, it is unclear as to why
the "explanation" has effect from April 1, 2000. The Hazira
production sharing contract (PSC) was signed in 1994 and commenced
production prior to April 1, 2000. As a result, the Company is
unable to apply the amended definition of "undertaking" to the
Hazira PSC. The Company has previously filed and recorded its
income taxes for the taxation years of 1999 to 2008 on the basis of
multiple undertakings for the Hazira and Surat PSC.
The Company will continue to pursue both issues through the
appeal process. The Company has challenged the retrospective
amendments to the undertakings definition and the lack of
clarification of whether natural gas is eligible for the tax
holiday with the Gujarat High Court. The Company was granted an
interim relief by the High Court on March 12, 2010 instructing the
Revenue Department to not give effect to the "explanation" referred
to above retrospectively until the matter is clarified in the
courts. Even if the Company receives favourable outcomes with
respect to both issues discussed above, the Revenue Department can
challenge other aspects of the Company's tax filings.
For the taxation years ended March 31, 2009 through March 31,
2011, the Company has filed its tax return assuming natural gas is
eligible for the tax holiday at Hazira and Surat but, unlike all
previous years, has filed its tax return based on Hazira and Surat
each having a single undertaking. The Company has reserved its
right, under Indian tax law, to claim the tax holiday with multiple
undertakings. While the Company still believes that it is eligible
for the tax holiday on multiple undertakings, the change in method
of filing is because the legislative changes, referred to above,
lead to ambiguity in the Act. More specifically, if the Company had
filed its return in a manner that is deemed to be in violation of
the current legislation, the Company can be liable for interest and
penalties. Further, at the time of filing the 2009 and 2010 tax
returns, the Company had not appealed the amendments brought out in
the tax holiday provisions and did not have the benefit of the
interim relief by the High Court. As a result, the Company has
filed in a more conservative manner than its interpretation of tax
law as described previously. Despite filing in a conservative
manner, the Company will continue to pursue the tax holiday changes
through the appeals process.
Should the High Court overturn the rulings previously awarded in
favour of the Company by the Tribunal court, and the Company either
decides not to appeal to the Supreme Court or appeals to the
Supreme Court and is unsuccessful, the Company would have to
accordingly change its tax position and record a tax expense of
approximately $56 million (comprised of additional taxes of $34
million and write off of approximately $22 million of the net
income tax receivable). In addition, the Company could be obligated
to pay interest on taxes for the past periods.
f. The Cauvery and D4 Blocks in India are under relinquishment.
The Company believes it has fulfilled all commitments for the
Cauvery block while the Government of India contends that the
Company has unfulfilled commitments of up to approximately $2
million. The Company believes the outcome is currently not
determinable.
g. Various lawsuits have been filed against the Company for
incidents arising in the ordinary course of business. In the
opinion of management, the outcome of the lawsuits, now pending, is
not determinable or not material to the Company's operations.
Should any loss result from the resolution of these claims, such
loss will be charged to operations in the year of resolution.
Contacts: Niko Resources Ltd. Edward Sampson Chairman of the
Board, President & CEO (403) 262-1020 Niko Resources Ltd.
Murray Hesje VP Finance & CFO (403) 262-1020
www.nikoresources.com