NOT FOR DISTRIBUTION TO U.S. NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE
UNITED STATES
Ithaca Energy Inc. (TSX VENTURE:IAE)(AIM:IAE) announces its quarterly financial
results for the three months ended June 30, 2011 and half yearly financial
results for the six months ended June 30, 2011.
HIGHLIGHTS
Financial
-- Q2 Earnings of US$2.9 million (Q2 2010: US$14.1 million) resulting in
Half Yearly Earnings of US$9.5 million (1H 2010: US$26.2 million)
-- Q2 Cashflow from Operations of US$3.7 million (Q2 2010: US$22.8 million)
resulting in Half Yearly Cashflow from Operations of US$25.8 million (1H
2010: US$42.3 million)
-- Cash US$176.6 million, inclusive of US$7.6 million restricted cash (Q1
2011: US$198.9 million inclusive of restricted cash)
-- Undrawn US$140 million senior debt facility
-- Tax losses of US$265 million (Q1 2011 $221 million)
-- Further Oil Put Option taken out ensuring 2nd half 2011 Oil price floor
of $115/barrel for 300,000 barrels (in addition to the previous Oil Put
Option ensuring 10 months 2011 Oil price floor of $105/barrel for
804,500 barrels)
-- Results and comparatives are now reported under International Financial
Reporting Standards ("IFRS")
Operations
-- Production averaged 2,040 barrels of oil equivalent per day ("boepd")
net to Ithaca over the 3 months period to June 30 with sales averaging
1,950 boepd after accounting for increased pipeline stock. Q2 production
was lower than anticipated mainly as a result of the failure of the
Electrical Submersible Pumps ("ESP") in the Jacky J01 production well as
well as unscheduled interruptions during the drilling of the Jacky J03
well. The pumps were replaced during June 2011 and Jacky production was
fully restored at the start of July 2011.
-- The well workover campaign on Beatrice Alpha was completed in July, when
the 'A21' well was returned to production following the re-completion of
the well and deployment of a new ESP.
-- The modification works being performed in Dubai to extend the 'BW
Athena' FPSO vessel by 65 feet and install a turret mooring system were
completed on schedule in June 2011. The vessel was subsequently re-
floated ready for installation of the new power generation and water
injection modules.
-- The Sedco 704 drilling rig successfully concluded drilling operations on
the Athena field in June 2011. The rig subsequently commenced the
completion programme for the five development wells (four productions
and one water injection), with operations on the 'A2', 'A3' and 'A4'
wells having now been completed. The rig is currently undertaking
completion operations on the fourth of the five well programme.
-- The Athena Field Subsea Installation campaign began in early August with
loadout and transport to the field of the submerged buoy mooring system.
Other subsea equipment including risers and flowlines has been delivered
to quayside and is ready for installation. More details and images of
the Athena project are provided on the Company's website:
http://www.ithacaenergy.com/Athena-Area.asp
-- The first of the major contracts on the Stella project was awarded to GE
Oil & Gas for the manufacture of the subsea trees and control systems.
The Company has also completed an offshore geotechnical programme to
determine the suitability of certain jackup drilling units at potential
development drilling locations on the Stella and Harrier fields. The
programme also included a borehole survey in advance of the planned
Hurricane appraisal well.
Corporate
-- The Company entered into an agreement to acquire a 28.46% non-operated
interest in the Cook oil field from Hess Limited ("Hess") for a
consideration of $62.5 million and the transfer from Ithaca to Hess of a
10% interest in each of exploration blocks 42/25b, 43/16a and 43/21c in
the Southern North Sea (the "Cook Acquisition"). The transaction was
completed on August 25, 2011 with an effective date of January 1, 2011
and an adjusted consideration of $57 million. The adjusted consideration
does not reflect current oil inventory of approximately 185,000 barrels
which will be part of the next Ithaca cargo lifting (of approximately
300,000 barrels) anticipated in Q4 2011.
Cook production post completion shall be included in the Company's 2011
production figures. The field is currently producing approximately 7,000
boepd (1,992 boepd net to Ithaca).
With the conclusion of the Cook acquisition, the Company now has three
producing centres in Cook, Jacky & Beatrice and Anglia & Topaz. The
commencement of production from Athena will further widen the Company's
production base.
-- The Company signed an earn in agreement with Challenger Minerals (North
Sea) Limited to drill an appraisal well on the Hurricane discovery
subject to agreeing 'turnkey' terms for the provision of a drilling rig
and well management services.
Notes:
Further details on the above are provided in the Interim Consolidated Financial
Statements and Management's Discussion and Analysis for the three and six months
ended June 30, 2011 which have been filed with securities regulatory authorities
in Canada. These documents are also available on the System for Electronic
Document Analysis and Retrieval at www.sedar.com and on the Company's website:
www.ithacaenergy.com.
Notes to oil and gas disclosure:
In accordance with AIM Guidelines, Hugh Morel, BSc Physics and Geology (Durham),
PhD Hydrogeology (London) and senior petroleum engineer at Ithaca is the
qualified person that has reviewed the technical information contained in this
press release. Dr Morel has 30 years operating experience in the upstream oil
industry.
About Ithaca Energy:
Ithaca Energy Inc. and its wholly owned subsidiary Ithaca Energy (UK) Limited
("Ithaca" or "the Company"), is an oil and gas exploration, development and
production company active in the United Kingdom's Continental Shelf ("UKCS").
The goal of Ithaca, in the near term, is to maximize production and achieve
early production from the development of existing discoveries on properties held
by Ithaca, to originate and participate in exploration and appraisal on
properties held by Ithaca when capital permits, and to consider other
opportunities for growth as they are identified from time to time by Ithaca.
Not for Distribution to U.S. Newswire Services or for Dissemination in the
United States
Forward-looking statements
Some of the statements in this announcement are forward-looking. Forward-looking
statements include statements regarding the intent, belief and current
expectations of Ithaca or its officers with respect to various matters
including, but not limited to future production levels and the benefits of the
Cook Acquisition. When used in this announcement, the words "anticipate",
"continue", "estimate", "expect", "may", "will", "project", "plan", "should",
"believe", "could", "target" and similar expressions, and the negatives thereof,
are intended to identify forward-looking statements. Such statements are not
promises or guarantees, and are subject to known and unknown risks and
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking statements or
information. Please refer to the risk factors affecting Ithaca as set out in the
Company's Annual Information Form and the Company's Q2 MD&A filed on SEDAR at
www.sedar.com. These forward-looking statements speak only as of the date of
this announcement. Ithaca Energy Inc. expressly disclaims any obligation or
undertaking to release publicly any updates or revisions to any forward-looking
statement contained herein to reflect any change in its expectations with regard
thereto or any change in events, conditions or circumstances on which any
forward-looking statement is based except as required by applicable securities
laws.
The term "boe" may be misleading, particularly if used in isolation. A boe
conversion of 6 Mcf: 1 bbl is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
ITHACA ENERGY INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS
FOR THE QUARTER ENDED JUNE 30, 2011
The following is management's discussion and analysis ("MD&A") of the operating
and financial results of Ithaca Energy Inc. (the "Corporation" or "Ithaca" or
the "Company") for the three and six months ended June 30, 2011. The information
is provided as of August 25, 2011. The second quarter 2011 results have been
compared to the results of the comparative period in 2010. This discussion and
analysis should be read in conjunction with the Corporation's unaudited
consolidated financial statements as at June 30, 2011 and with the Corporation's
audited consolidated financial statements as at December 31, 2010 together with
the accompanying notes, MD&A and Annual Information Form ("AIF") for the 2010
fiscal year. These documents and additional information about Ithaca are
available on SEDAR at www.sedar.com.
Certain statements contained in this MD&A, including estimates of reserves,
estimates of future cash flows and estimates of future production as well as
other statements about future events or anticipated results, are forward-looking
statements. The forward-looking statements contained herein are based on
assumptions and are subject to known and unknown risks, uncertainties and other
factors. Should the underlying assumptions prove incorrect or should one or more
of these risks, uncertainties or factors materialize, actual results may vary
significantly from those expected. See "Forward-Looking Information", below.
All financial data contained herein is presented in accordance with
International Financial Reporting Standards ("IFRS") and is expressed in United
States dollars ("$"), unless otherwise stated. All comparative figures for 2010
have been restated to be in accordance with IFRS.
BUSINESS OF THE CORPORATION
Ithaca is an oil and gas exploration, development and production company active
in the United Kingdom's Continental Shelf ("UKCS"). The goal of Ithaca, in the
near term, is to maximize production and achieve early production from the
development of existing discoveries on properties held by Ithaca, to originate
and participate in exploration and appraisal on properties held by Ithaca when
capital permits, and to consider other opportunities for growth as they are
identified from time to time by Ithaca.
The Corporation's common shares are listed for trading on the TSX Venture
Exchange and the Alternative Investment Market of the London Stock Exchange
under the symbol "IAE".
NON-GAAP MEASURES
'Cashflow from operations' referred to in this MD&A is not prescribed by IFRS.
This non-GAAP financial measure does not have any standardized meaning and
therefore is unlikely to be comparable to similar measures presented by other
companies. The Corporation uses this measure to help evaluate its performance.
As an indicator of the Corporation's performance, cashflow from operations
should not be considered as an alternative to, or more meaningful than, net cash
from operating activities as determined in accordance with IFRS. The
Corporation's determination of cashflow from operations does not have any
standardized meaning and therefore may not be comparable to similar measures
presented by other companies. The Corporation considers cashflow from operations
to be a key measure as it demonstrates the Corporation's ability to generate the
cash necessary to fund operations and support activities related to its major
assets. Cashflow from operations is determined by adding back changes in
non-cash operating working capital to cash provided by operating activities.
BOE PRESENTATION
The calculation of barrels of oil equivalent ("boe") is based on a conversion
rate of six thousand cubic feet of natural gas ("mcf") to one barrel of crude
oil ("bbl"). The term boe may be misleading, particularly if used in isolation.
A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead.
HIGHLIGHTS SECOND QUARTER 2011
Ithaca achieved the following highlights during the second three months of 2011.
Financial
-- Q2 Profit after tax of $2.9 million (Q2 2010: $14.1 million) resulting
in Half yearly Profit after tax of $9.5 million (Q2 2010 YTD: $26.2
million)
-- Q2 Cashflow from operations of $3.7 million (Q2 2010: $22.8 million)
resulting in Half yearly cashflow from operations of $25.8 million (Q2
2010 YTD: $42.3 million)
-- Cash $176.6 million, inclusive of $7.6 million restricted cash (Q1 2011:
$198.9 million)
-- Undrawn $140 million senior debt facility
-- Tax losses of $265 million (Q1 2011 $221 million)
-- Further oil put option taken out ensuring 2nd half 2011 oil price floor
of $115/barrel for 300,000 barrels (in addition to the previous oil put
option ensuring 10 months 2011 Oil price floor of $105/barrel for
804,500 barrels)
Operational
Production
Production averaged 2,040 barrels of oil equivalent per day ("boepd") net to
Ithaca over the 3 months period to June 30 with sales averaging 1,950 boepd.
Production dipped in Q2 mainly as a result of the failure of the Electrical
Submersible Pumps ("ESP") in the Jacky J01 production well and interruption to
production caused by the drilling of the Jacky J03 well. The pumps were replaced
during June 2011 and Jacky production was fully restored at the start of July
2011.
Athena
In June, the final Athena production well completed drilling and was fully
cased. The well encountered a considerable section of oil saturated net
reservoir, with good porosities. Development drilling has now successfully
concluded and the project remains on schedule for production start up in Q4
2011.
Also in June, the modification and recertification work on the Floating
Production Storage and Offload vessel ("FPSO") the 'BW Athena' was significantly
progressed. The vessel was successfully separated for installation of a turret
docking section welded into the structure amidships.
Following the end of the quarter, in July, the engineering and modifications
associated with the dry dock works in Dubai to extend the vessel by 65 feet and
install a turret docking system were completed. The vessel was re-floated ready
for installation of the new power generation and water injection modules.
In July operations to prepare the Athena field development well 14/18b-A2Z for
production were successfully concluded. A 7" production liner and a dual
electrical submersible pump system were successfully installed above the
horizontal section of the well and the subsea xmas tree and flowbase are now
ready for hook-up of flowlines by the subsea installation contractor. The Sedco
704 drilling unit has stayed on location to undertake further completion work
and has completed the 14/18b-16 and 14/18b-18 wells. It is now working on
14/18b-A1, the fourth well of a five well program of completions (four
productions and one water injection) to be carried out before hook-up to the 'BW
Athena'.
In August the Athena Field Subsea Installation campaign began with loadout and
transport to the field of the submerged buoy mooring system. Other subsea
equipment including risers and flowlines has been delivered to quayside and is
ready for installation.
Jacky
In April both ESPs in the Jacky production well, J01, developed faults under
routine operations, requiring the ESPs to be replaced. As a result the well was
free flowing and gross production from the J01 well reduced to approximately 700
bopd (approximately 335 bopd net to Ithaca); prior to this, under ESP support,
gross production was approximately 2,800 bopd (1,330 bopd net to Ithaca). The
J01 production well continued to free flow until the Jacky J03 well reached the
target reservoir formation, in May. The Northern Enhancer rig was utilised to
undertake a workover operation to replace the failed ESPs, reperforate the well
and reinstate J01 production. The operation was completed in June. In July,
following the end of the quarter, stable production from the Jacky field was
restored at approximately 3,120 bopd (1,482 bopd net to Ithaca).
The Jacky J03 well noted above was suspended having encountered a smaller than
anticipated oil column in the Beatrice 'A' Sand reservoir. Technical work is
ongoing to determine whether to re-enter the well and complete it as a water
injector.
Following an announcement in December 2010 that North Sea Energy was seeking to
withdraw from participating in the drilling of the Jacky J03 well, Ithaca
commenced proceedings in the High Court of Justice in London for a declaration
that the Jacky J03 well is a joint operation. A court date for the proceedings
has been set for April 19, 2012.
Beatrice
Production from the Beatrice field wells has continued throughout the quarter.
In April the workover of well A28 was partially completed and it is now free
flowing at approximately 130 bopd gross (65 bopd net to Ithaca). Operations then
transferred to the workover of the A21 well.
In July, the workover campaign on Beatrice Alpha was completed with the final
workover well, A21, returned to ESP production. The workover unit was
demobilised from Beatrice Alpha in July.
Beatrice production and water injection uptimes have remained excellent
throughout the quarter with no significant process failures.
Stella
In July the development of the Stella field moved ahead with the placement of a
contract with GE Oil & Gas to manufacture and supply subsea trees and controls
systems. The initial phase of detailed engineering work commenced and is
focusing on the procurement of forgings and materials for the systems. The
systems will be delivered as an integrated package and are designed for
installation using a heavy duty jackup drilling unit. A geotechnical program has
also been successfully completed to determine the suitability of certain jackup
drilling units at four potential development drilling locations on the Stella
and Harrier fields. The program incorporated test boreholes in advance of the
planned Hurricane appraisal well. Two drill centres will be selected. Final
development concept selection will be made in the second half of 2011 with Field
Development Plan ("FDP") submission expected by the end of the year.
Corporate
Cook Acquisition
The Company entered into an agreement to acquire a 28.46% non-operated interest
in the Cook oil field from Hess Limited ("Hess") for a consideration of $62.5
million and the transfer from Ithaca to Hess of a 10% interest in each of
exploration blocks 42/25b, 43/16a and 43/21c in the Southern North Sea. The
transaction was completed on August 25, with an effective date of January 1,
2011 and an adjusted consideration of $57 million. The adjusted consideration
does not reflect current oil inventory of approximately 185,000 barrels which
will be part of the next Ithaca cargo lifting (of approximately 300,000 barrels)
anticipated in Q4 2011.
The Maclure field, originally included in the agreement was subject to
pre-emption, the right of which was exercised by one of the existing Maclure
co-venturers. The interest in the Maclure field was therefore removed from the
acquisition and the consideration was adjusted such that Ithaca acquired a
28.46% non-operated interest in the Cook field only.
The Reserves Audit Opinion on the Cook field issued by Sproule in the quarter
confirmed management's view that the acquisition would increase the
Corporation's remaining Proved plus Probable reserves by 5.75 million barrels of
oil equivalent ("mmboe") net to Ithaca as at January 1, 2011 as reasonable.
Hurricane
In April the Corporation signed an earn in agreement with Challenger Minerals
(North Sea) Limited ("CMI") on the Hurricane discovery. Under the terms of the
agreement CMI has agreed to pay a share of the initial well costs in return for
an option, exercisable within 90 days of abandonment or suspension of the
initial appraisal and any sidetrack well, to acquire an interest in Block
29/10b. CMI will pay 40% of gross Hurricane appraisal well costs in exchange for
a 31% equity interest in Block 29/10b, thereby carrying a part of Ithaca's share
of all costs of drilling an initial appraisal well. In addition, upon successful
appraisal, CMI will pay 40% of gross costs of a drill stem well test of any
sidetrack. All additional costs, including those for planned sidetrack drilling,
will be apportioned such that CMI will pay its 31% pro rata share. The
transaction is subject to agreed 'turnkey' terms with ADTI for the provision of
a suitable drilling unit and well management services.
Other
In April the Corporation purchased a further put option with a floor price of
$115 per barrel for 300,000 barrels of oil. This put option delivers a minimum
price on the specified volume of oil and leaves the Corporation to benefit from
any oil price upside above $115 per barrel.
Following the end of the quarter, in July, the Corporation announced that from
January 2012 Mr. Mike Travis would be appointed as Chief Production Officer. He
has over 28 years of diverse offshore and onshore experience in the oil industry
and has held key leadership positions throughout his career in all aspects of
production and development projects including asset management, drilling and
operations.
In July the Corporation established a Share Incentive Plan ("SIP") effective as
of July 19, 2011. The purpose of the SIP is to provide UK based officers and
employees with the opportunity to acquire common shares in the Company in a
tax-effective way. Approval for the SIP was obtained from HM Revenue & Customs
under Schedule 2 to the Income Tax (Earnings and Pensions) Act 2003.
RESULTS OF OPERATIONS
Revenue
Three months ended June 30, 2011
Sales revenue has decreased in Q2 2011 to $16.7 million (Q2 2010 $34.1 million).
This movement comprises a decrease in total net oil production, an increase in
average realized prices, and the addition of gas sales from the Anglia and Topaz
fields from December 17, 2010.
Oil production decreased from 4,914 bopd in Q2 2010 to 1,248 bopd for Q2
2011 predominantly due to the ESP failures on Jacky, noted above. The
Corporation has benefited from an increase in average realized oil prices
from $73.98 / bbl in Q2 2010 to $116.59/ bbl in Q2 2011.
The addition of gas production also contributed to revenue in Q2 2011 (no
gas production in Q2 2010). The combined production from the Anglia and
Topaz fields contributed over $3 million to revenue.
Six months ended June 30, 2011
Sales revenue has decreased in 1H 2011 to $47.8 million (1H 2010 $64.9 million).
This movement comprises a decrease in total net oil production, an increase in
average realized prices, and the addition of gas sales from the Anglia and Topaz
fields from December 17, 2010.
Oil production decreased from 4,552 bopd in 1H 2010 to 1,876 bopd for 1H
2011. The Corporation has benefited from an increase in average realized
oil prices from $76.70 / bbl in 1H 2010 to $112.98/ bbl in 1H 2011.
The addition of gas production noted above contributed over $7 million to
revenue.
Cost of Sales
Three months ended June 30, 2011
Cost of sales has increased in Q2 2011 to $15.7 million (Q2 2010 $14.8
million) due to an increase in operating costs offset by a decrease in
DD&A expense.
Operating costs have increased in Q2 2011 to $11.5 million (Q2 2010 $9.5
million) primarily due to the addition of Anglia and Topaz operating
costs. Operating costs for the Great Beatrice Area have remained
consistent in the period.
DD&A expense for the quarter has decreased in Q2 2011 to $4.2 million (Q2
2010 $5.3 million) due to the decrease in production noted above,
partially offset by an increase in the DD&A rate due to the addition of
the Anglia and Topaz gas assets and capital expenditure in the period.
Six months ended June 30, 2011
Cost of sales has increased in 1H 2011 to $32.9 million (1H 2010 $27.9 million)
due to an increase in operating costs and DD&A expense.
Operating costs have increased in 1H 2011 to $21.8 million (1H 2010 $18.1
million) primarily due to the addition of Anglia and Topaz assets noted
above.
DD&A expense for the six months ended June 30 has increased in 1H 2011 to
$11.2 million (1H 2010 $9.7 million) due to the addition of the Anglia
and Topaz assets and the significant capital expenditure in the period.
Administrative expenses and Exploration & Evaluation expenses
Three months ended June 30, 2011
Administrative expenses have increased in Q2 2011 to $2.5 million (Q2 2010 $0.2
million). The main reason for the increase was the continued growth of the
corporation as the Athena project progresses to first oil and the Greater Stella
Area moves towards FDP approval together with an increase in stock based
compensation. A year-to-date stock based compensation reclassification to credit
costs in Q2 2010 also contributed to the movement in costs from 2010.
Exploration and evaluation expenses of less than $0.2 million (Q2 2010 $Nil)
were recorded for the three months ended June 30, 2011 due to the expensing of
previously capitalized costs relating to areas where the Corporation has decided
to cease exploration and evaluation activities.
Six months ended June 30, 2011
Administrative expenses have increased in 1H 2011 to $3.5 million (1H 2010 $2.1
million). The main reason for the increase was the continued growth of the
corporation noted above together with an increase in stock based compensation.
A credit of $0.3 million has been recorded in the income statement for
exploration and evaluation expenses for the six months ended June 30, 2011 (1H
2010 $Nil). The credit relates to the expensing of certain prospects declared
non-commercial and areas where exploration and evaluation activities has ceased
of $1.5 million and the offsetting release of $2 million of associated
contingent consideration relating to those licences and prospects. The Opal and
Garnet prospects, acquired as part of the GdF Acquisition, were included within
this write-off.
Foreign exchange and Financial Instruments
Three months ended June 30, 2011
Foreign exchange movements increased $0.8 million to an overall gain of $0.4
million in the three months ended June 30, 2011 (Q2 2010 $0.4 million loss). The
gain in Q2 2011 was caused by increases in the USD : GBP exchange rate
experienced in the quarter, causing an increase in the value of GBP cash held on
deposit. This compares to a decrease in the average USD : GBP exchange rate for
the three months ended June 30, 2010.
The Corporation recorded a $0.3 million loss on financial instruments for the
three months ended June 30, 2011 (Q2 2010: $4.6 million loss). The loss was
primarily due to a $1.5 million loss recorded from the revaluation of the oil
'put options' caused by the high Brent oil price per barrel of $113.20 as at
June 30, and movements in forecast oil prices for the option life partially
offset by a $1.2 million gain on the revaluation of the embedded derivative
within the Anglia gas sales contract. The remaining movement was made up of
revaluations of other financial instruments.
Six months ended June 30, 2011
Foreign exchange gains / losses increased $4.5 million to an overall gain of
$2.6 million in the six months ended June 30, 2011 (1H 2010 $1.9 million loss).
The gain in Q2 2011 was again caused by increases in the USD : GBP exchange rate
experienced in the 6 months ended 30 June 2011, causing an increase in the value
of GBP cash held on deposit. This compares to a decrease in the average USD :
GBP exchange rate for the six months ended June 30, 2010.
The Corporation recorded a $2.6 million loss on financial instruments for the
six months ended June 30, 2011 (1H 2010: $6.6 million loss). The loss was
primarily due to a $3.6 million loss recorded from the revaluation of the oil
'Put Options' held, partially offset by a $1.0 million gain on the revaluation
of the embedded derivative within the Anglia gas sales contract. The remaining
movement was made up of revaluations of other financial instruments.
Taxation
Three months ended June 30, 2011
A deferred tax credit of $4.7 million was recognized in the three months ended
June 30, 2011 (Q2 2010: $Nil) due to adjustments relating to the tax impact of
derivative financial instruments and the UK Ring Fence Expenditure Supplement in
the quarter.
Six months ended June 30, 2011
A deferred tax charge of $1.7 million was recognized in the six months ended
June 30, 2011 (1H 2010: $Nil) representing an effective tax rate of 16%. This
rate is a product of adjustments to taxable income due to adjustments relating
to the tax impact of derivative financial instruments and the UK Ring Fence
Expenditure Supplement in the quarter and the changes in UK Corporation Tax
rates for upstream and non-upstream oil and gas activities.
No tax is expected to be paid in the mid-term future relating to upstream oil
and gas activities.
As a result of the above factors, Profit after tax for the three months ended
June 30 decreased to $2.9 million (Q2 2010 $14.1 million) and for the six months
ended June 30 decreased to $9.5 million (1H 2010 $26.2 million).
SUMMARY OF QUARTERLY RESULTS
The following table provides a summary of quarterly results of the Corporation
for its eight most recently completed quarters:
31/06/2011 31/03/2011 31/12/2010 30/09/2010
$'000 $'000 $'000 $'000
----------------------------------------------------------------------
----------------------------------------------------------------------
Revenue 16,724 31,050 34,260 35,965
Profit after tax 2,860 6,593 17,922 18,073
----------------------------------------------------------------------
----------------------------------------------------------------------
Earnings per share
Basic 0.01 0.03 0.07 0.08
Diluted 0.01 0.03 0.07 0.08
----------------------------------------------------------------------
----------------------------------------------------------------------
Selected other
information
(Loss) / Profit
before tax (1,827) 13,037 14,257 18,154
30/06/2010 31/03/2010 31/12/2009(i) 30/09/2009(i)
$'000 $'000 $'000 $'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 34,129 30,767 39,676 37,395
Profit after tax 14,098 12,108 17,488 (1,145)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings per share
Basic 0.09 0.07 0.11 (0.01)
Diluted 0.09 0.07 0.11 (0.01)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected other
information
(Loss) / Profit
before tax 14,098 12,108 17,488 (1,145)
(i) Comparative figures for 2009 have been reported under Canadian GAAP
The most significant factors to have affected the Corporation's results during
the above quarters are fluctuation in underlying commodity prices and movement
in production volumes in the current period. Commodity prices have generally
risen through the periods in which the Corporation had production. The
Corporation has utilized forward sales contracts and foreign exchange contracts
to take advantage of higher commodity prices while reducing the exposure to
price volatility. These contracts can cause volatility in profit after tax as a
result of unrealized gains and losses due to movements in the oil price and USD
: GBP exchange rate.
LIQUIDITY AND CAPITAL RESOURCES
As at June 30, 2011, Ithaca had working capital of $197.2 million including a
free cash balance of $169.0 million. Available cash has been, and is currently,
invested in money market deposit accounts with the Bank of Scotland. Management
has received confirmation from the financial institution that these funds are
available on demand. The restricted cash of $7.6 million comprises $7.2 million
currently held by the Bank of Scotland as decommissioning security provided as
part of the acquisition of gas interests from GDF SUEZ E&P UK Ltd and $0.4
million held by the Bank of Scotland as cash security for a bank guarantee that
Ithaca Energy (UK) Limited ("Ithaca UK") provided to the Crown Estate when it
was granted Field Development Plan approval for the Jacky Field.
During the three months ended June 30, 2011 there was a cash outflow from
operating, investing and financing activities of $22.4 million (Q2 2010 inflow
of $30.9 million). The net outflow was due to cash inflows from operating
activities of $5.5 million; cash outflows from investing activities of $25.6
million due to investment in fixed assets and movements in working capital, and
cash outflows from financing activities of $2.4 million. The remainder of the
movement was due to foreign exchange on non US Dollar denominated cash deposits.
The fixed asset investment in the quarter predominantly related to capital
expenditure on the development of Athena, J03 well drilling costs and J01 well
ESP replacement operations on Jacky, the purchase of long lead items for the
Greater Stella Area and the hydraulic workover program on Beatrice Alpha.
All of the Corporation's current projects are anticipated to be fully funded
through to first production.
COMMITMENTS
The Corporation has the following financial commitments:
Subsequent
Year ended 2011 2012 2013 2014 to 2014
US$'000 US$'000 US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Office lease 128 256 256 256 833
Exploration license fees 875 1,248 1,602 - -
Engineering 14,362 20,079 11,679 11,679 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 15,365 21,583 13,537 11,935 833
OUTSTANDING SHARE INFORMATION
As at June 30, 2011, Ithaca had 258,535,295 common shares outstanding along with
19,398,505 options to employees and directors to acquire common shares.
As at August 25, 2011, Ithaca had 259,105,295 common shares outstanding along
with 18,351,005 options to employees and directors to acquire common shares.
CRITICAL ACCOUNTING ESTIMATES
Certain accounting policies require that management make appropriate decisions
with respect to the formulation of estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses. These accounting
policies are discussed below and are included to aid the reader in assessing the
critical accounting policies and practices of the Corporation and the likelihood
of materially different results being reported. Ithaca's management reviews
these estimates regularly. The emergence of new information and changed
circumstances may result in actual results or changes to estimated amounts that
differ materially from current estimates.
The following assessment of significant accounting policies and associated
estimates is not meant to be exhaustive. The Corporation might realize different
results from the application of new accounting standards promulgated, from time
to time, by various rule-making bodies.
Capitalized costs relating to the exploration and development of oil and gas
reserves, along with estimated future capital expenditures required in order to
develop proved and probable reserves are depreciated on a unit-of-production
basis, by asset, using estimated proved and probable reserves as adjusted for
production.
A review is carried out each reporting date for any indication that the carrying
value of the Corporation's Development & Production ("D&P") assets may be
impaired. For D&P assets where there are such indications, an impairment test is
carried out on the Cash Generating Unit ("CGU"). Each CGU is identified in
accordance with IAS 36. The Corporation's CGUs are those assets which generate
largely independent cash flows and are normally, but not always, single
developments or production areas. The impairment test involves comparing the
carrying value with the recoverable value of an asset. The recoverable amount of
an asset is determined as the higher of its fair value less costs to sell and
value in use, where the value in use is determined from estimated future net
cash flows. Any additional depreciation resulting from the impairment testing is
charged to the Income Statement.
Recognition of decommissioning liabilities associated with oil and gas wells are
determined using estimated costs discounted based on the estimated life of the
asset. In periods following recognition, the liability and associated asset are
adjusted for any changes in the estimated amount or timing of the settlement of
the obligations. The liability is accreted up to the actual expected cash outlay
to perform the abandonment and reclamation. The carrying amounts of the
associated assets are depleted using the unit of production method, in
accordance with the depreciation policy for development and production assets.
Actual costs to retire tangible assets are deducted from the liability as
incurred.
All financial instruments (including derivatives, financial assets and
liabilities) are initially recognized at fair value on the balance sheet. The
Corporation's financial instruments consist of cash, restricted cash, accounts
receivable, deposits, derivatives, loan fees, accounts payable, accrued
liabilities and the long term liability on the Beatrice acquisition. Measurement
in subsequent periods is dependent on the classification of the respective
financial instrument.
In order to recognize stock based compensation expense, the Corporation
estimates the fair value of stock options granted using assumptions related to
interest rates, expected life of the option, volatility of the underlying
security and expected dividend yields. These assumptions may vary over time.
The determination of the Corporation's income and other tax liabilities / assets
requires interpretation of complex laws and regulations. Tax filings are subject
to audit and potential reassessment after the lapse of considerable time.
Accordingly, the actual income tax liability may differ significantly from that
estimated and recorded on the financial statements.
The accrual method of accounting will require management to incorporate certain
estimates of revenues, production costs and other costs as at a specific
reporting date. In addition, the Corporation must estimate capital expenditures
on capital projects that are in progress or recently completed where actual
costs have not been received as of the reporting date.
OFF-BALANCE SHEET ARRANGEMENTS
The Corporation has certain lease agreements which were entered into in the
normal course of operations, all of which are disclosed under the heading
"Commitments", above. Leases are treated as either operating leases or finance
leases based on the extent to which risks and rewards incidental to ownership
lie with the lessor or the lessee under IAS 17. No asset or liability value has
been assigned to any leases on the balance sheet as at June 30, 2011.
RELATED PARTY TRANSACTIONS
A director of the Corporation is a partner of Burstall Winger LLP who acts as
counsel for the Corporation. The amount of fees paid to Burstall Winger LLP in
Q2 2011 was $0.1 million (Q2 2010 - $0.1 million). All related party
transactions are in the normal course of business and are conducted on normal
commercial terms with consideration comparable to those charged by third
parties.
RISKS AND UNCERTAINTIES
The business of exploring for, developing and producing oil and natural gas
reserves is inherently risky. There is substantial risk that the manpower and
capital employed will not result in the finding of new reserves in economic
quantities. There is a risk that the sale of reserves may be delayed due to
processing constraints, lack of pipeline capacity or lack of markets.
The Corporation is dependent upon the production rates and oil price to fund the
current development program. In order to mitigate the Corporation's risk to
fluctuations in oil price, the Corporation has taken out a number of commodity
derivatives. In March 2011, a put option to sell 804,500 bbls of the
Corporation's 2011 forecast production at $105 / bbl was entered into. In April
2011 a further put option to sell an additional 300,000 bbls of the
Corporation's forecast 2011 production at $115 / bbl was entered into. These
options deliver a minimum price on the specified volumes of oil and leave the
Corporation to benefit from any oil price upside above $105 and $115 per barrel
respectively.
The Corporation is exposed to financial risks including financial market
volatility, fluctuation in interest rates and various foreign exchange rates.
Given the increasing development expenditure and operating costs in currencies
other than the United States dollar, the Board of Directors of the Corporation
has a hedging policy to mitigate foreign exchange rate risk on committed
expenditure. In 2011 in order to protect against movements in USD/GBP exchange
rates, the Corporation holds GBP denominated cash on deposit in order to match
the forecast 2011 GBP denominated expenditure.
A further risk relates to the Corporation's ability to meet the conditions
precedent for a full drawdown on the Corporation's credit facility with the Bank
of Scotland (the "Credit Facility"). Ability to drawdown the Credit Facility is
based on the Corporation meeting certain tests including coverage ratio tests,
liquidity tests and development funding tests which are determined by a detailed
economic model of the Corporation. There can be no assurance that the
Corporation will satisfy such tests in order to have access to the full amount
of the Credit Facility, however at present the Corporation believes that there
are no circumstances present that would lead to failure to meet those tests.
In addition, the Credit Facility contains covenants that require the Corporation
to meet certain financial tests and that restrict, among other things, the
ability of Ithaca to incur additional debt or dispose of assets. To the extent
the cash flow from operations is not adequate to fund Ithaca's cash
requirements, external financing may be required. Lack of timely access to such
additional financing, or which may not be on favorable terms, could limit the
future growth of the business of Ithaca. To the extent that external sources of
capital, including public and private markets, become limited or unavailable,
Ithaca's ability to make the necessary capital investments to maintain or expand
its current business and to make necessary principal payments under the Credit
Facility may be impaired. At present the Corporation believes that there are no
circumstances present that would lead to failure to meet those certain financial
tests.
A failure to access adequate capital to continue its expenditure program may
require that the Corporation meet any liquidity shortfalls through the selected
divestment of its portfolio or delays to existing development programs. As is
standard to a Credit facility, the Corporation's and Ithaca UK assets have been
pledged as collateral and are subject to foreclosure in the event the
Corporation or Ithaca UK defaults. At present the Corporation believes that
there are no circumstances present that would lead to selected divestment,
delays to existing programs or a default relating to the Credit Facility.
The Corporation is and may in the future be exposed to third-party credit risk
through its contractual arrangements with its current and future joint venture
partners, marketers of its petroleum production and other parties. The
Corporation extends unsecured credit to these parties, and therefore, the
collection of any receivables may be affected by changes in the economic
environment or other conditions. Management believes the risk is mitigated by
the financial position of the parties. The Corporation has entered in to a five
year marketing agreement with BP Oil International Limited to sell all of its
North Sea oil production. All gas production, acquired through the purchase of
the Anglia and Topaz fields from GDF SUEZ E&P UK Ltd, is currently sold through
three contracts on a monthly basis to RWE NPower PLC and Hess Energy Gas Power
(UK) Ltd. The Corporation has not experienced any material credit loss in the
collection of accounts receivable to date.
The Corporation's properties will be generally held in the form of licenses,
concessions, permits and regulatory consents ("Authorizations"). The
Corporation's activities are dependent upon the grant and maintenance of
appropriate Authorizations, which may not be granted; may be made subject to
limitations which, if not met, will result in the termination or withdrawal of
the Authorization; or may be otherwise withdrawn. Also, in the majority of its
licenses, the Corporation is often a joint interest-holder with another third
party over which it has no control. An Authorization may be revoked by the
relevant regulatory authority if the other interest-holder is no longer deemed
to be financially credible. There can be no assurance that any of the
obligations required to maintain each Authorization will be met. Although the
Corporation believes that the Authorizations will be renewed following expiry or
granted (as the case may be), there can be no assurance that such Authorizations
will be renewed or granted or as to the terms of such renewals or grants. The
termination or expiration of the Corporation's Authorizations may have a
material adverse effect on the Corporation's results of operations and business.
In addition, the areas covered by the Authorizations are or may be subject to
agreements with the proprietors of the land. If such agreements are terminated,
found void or otherwise challenged, the Corporation may suffer significant
damage through the loss of opportunity to identify and extract oil or gas.
The Corporation is also subject to the risks associated with owning oil and
natural gas properties, including environmental risks associated with air, land
and water. The Corporation takes out market insurance to mitigate many of these
operational, construction and environmental risks. In all areas of the
Corporation's business there is competition with entities that may have greater
technical and financial resources. There are numerous uncertainties in
estimating the Corporation's reserve base due to the complexities in estimating
the magnitude and timing of future production, revenue, expenses and capital.
All of the Corporation's operations are conducted offshore in the UKCS; as such
Ithaca is exposed to operational risk associated with weather delays that can
result in a material delay in project execution. Third parties operate some of
the assets in which the Corporation has interests. As a result, the Corporation
may have limited ability to exercise influence over the operations of these
assets and their associated costs. The success and timing of these activities
may be outside the Corporation's control.
It should be noted that the Corporation is not required to certify the design
and evaluation of the Corporation's disclosure controls and procedures and
internal control over financial reporting and it has not completed such an
evaluation. Furthermore, given the size of the Corporation there are inherent
limitations on the certifying officers to design and implement on a cost
effective basis disclosure controls and procedures and internal control over
financial reporting that may result in additional risks to the quality,
reliability, transparency, and timeliness of annual filings.
For additional detail regarding the Corporation's risks and uncertainties, refer
to the Corporation's most recent AIF filed on SEDAR at www.sedar.com.
CONTROL ENVIRONMENT
As of June 30, 2011, there were no changes in our internal control over
financial reporting that occurred during 2011 that have materially affected, or
are reasonably likely to materially affect, our internal control over financial
reporting.
Based on their inherent limitations, disclosure controls and procedures and
internal controls over financial reporting may not prevent or detect
misstatements and even those options determined to be effective can provide only
reasonable assurance with respect to financial statement preparation and
presentation.
CHANGES IN ACCOUNTING POLICIES
On January 1, 2011, the Corporation adopted IFRS using a transition date of
January 1, 2010. The financial statements for the three months ended June 30,
2011, including required comparative information, have been prepared in
accordance with International Financial Reporting Standards 1, First-time
Adoption of International Financial Reporting Standards, and with International
Accounting Standard ("IAS") 34, Interim Financial Reporting, as issued by the
International Accounting Standards Board ("IASB"). Previously, the Corporation
prepared its Interim and Annual Consolidated Financial Statements in accordance
with Canadian GAAP. Refer to Note 24 of the Interim Consolidated Financial
Statements for the Corporation's assessment of impacts of the transition to
IFRS.
IMPACT OF FUTURE ACCOUNTING CHANGES
In May 2011, the IASB issued the following standards: IFRS 10, Consolidated
Financial Statements ("IFRS 10"), IFRS 11, Joint Arrangements ("IFRS 11"), IFRS
12, Disclosure of Interests in Other Entities ("IFRS 12"), IAS 27, Separate
Financial Statements ("IAS 27"), IFRS 13, Fair Value Measurement ("IFRS 13") and
amended IAS 28, Investments in Associates and Joint Ventures ("IAS 28"). Each of
the new standards is effective for annual periods beginning on or after January
1, 2013 with early adoption permitted. The Corporation has not yet assessed the
impact that the new and amended standards will have on its financial statements
or whether to early adopt any of the new requirements.
FINANCIAL INSTRUMENTS AND OTHER INSTRUMENTS
All financial instruments are initially measured in the balance sheet at fair
value. Subsequent measurement of the financial instruments is based on their
classification. The Corporation has classified each financial instrument into
one of these categories: held-for-trading, held-to-maturity investments, loans
and receivables, or other financial liabilities. Loans and receivables,
held-to-maturity investments and other financial liabilities are measured at
amortized cost using the effective interest rate method. For all financial
assets and financial liabilities that are not classified as held-for-trading,
the transaction costs that are directly attributable to the acquisition or issue
of a financial asset or financial liability are adjusted to the fair value
initially recognized for that financial instrument. These costs are expensed
using the effective interest rate method and are recorded within interest
expense. Held-for-trading financial assets are measured at fair value and
changes in fair value are recognized in net income.
All derivative instruments are recorded in the balance sheet at fair value
unless they qualify for the expected purchase, sale and usage exemption. All
changes in their fair value are recorded in income unless cash flow hedge
accounting is used, in which case changes in fair value are recorded in other
comprehensive income.
The Corporation has classified its cash and cash equivalents, restricted cash,
derivatives, commodity hedge and long term liability as held-for-trading, which
are measured at fair value with changes being recognized in net income. Accounts
receivable are classified as loans and receivables; operating bank loans,
accounts payable and accrued liabilities are classified as other liabilities,
all of which are measured at amortized cost. The classification of all financial
instruments is the same at inception and at June 30, 2011.
FORWARD-LOOKING INFORMATION
This MD&A and any documents incorporated by reference herein contain certain
forward-looking statements and forward-looking information which are based on
the Corporation's internal expectations, estimates, projections, assumptions and
beliefs as at the date of such statements or information, including, among other
things, assumptions with respect to production, future capital expenditures and
cash flow. The reader is cautioned that assumptions used in the preparation of
such information may prove to be incorrect. The use of any of the words
"anticipate", "continue", "estimate", "expect", "may", "will", "project",
"plan", "should", "believe", "could", "scheduled", "targeted" and similar
expressions are intended to identify forward-looking statements and
forward-looking information. These statements are not guarantees of future
performance and involve known and unknown risks, uncertainties and other factors
that may cause actual results or events to differ materially from those
anticipated in such forward-looking statements or information. The Corporation
believes that the expectations reflected in those forward-looking statements and
information are reasonable but no assurance can be given that these
expectations, or the assumptions underlying these expectations, will prove to be
correct and such forward-looking statements and information included in this
MD&A and any documents incorporated by reference herein should not be unduly
relied upon. Such forward-looking statements and information speak only as of
the date of this MD&A and any documents incorporated by reference herein and the
Corporation does not undertake any obligation to publicly update or revise any
forward-looking statements or information, except as required by applicable
laws.
In particular, this MD&A and any documents incorporated by reference herein,
contains specific forward-looking statements and information pertaining to the
following:
-- the quality of and future net revenues from the Corporation's reserves;
-- oil, natural gas liquids ("NGLs") and natural gas production levels;
-- commodity prices, foreign currency exchange rates and interest rates;
-- capital expenditure programs and other expenditures;
-- the sale, farming in, farming out or development of certain exploration
properties using third party resources;
-- supply and demand for oil, NGLs and natural gas;
-- the Corporation's ability to raise capital;
-- the Corporation's acquisition strategy, the criteria to be considered in
connection therewith and the benefits to be derived therefrom;
-- the Corporation's ability to continually add to reserves;
-- schedules and timing of certain projects and the Corporation's strategy
for growth;
-- the Corporation's future operating and financial results;
-- the ability of the Corporation to optimize operations and reduce
operational expenditures;
-- treatment under governmental and other regulatory regimes and tax,
environmental and other laws;
-- production rates;
-- targeted production levels;
-- timing and cost of the development of the Corporation's reserves; and
-- estimates of production volumes and reserves in connection with the
acquisition of Cook.
With respect to forward-looking statements contained in this MD&A and any
documents incorporated by reference herein, the Corporation has made assumptions
regarding, among other things:
-- Ithaca's ability to obtain additional drilling rigs and other equipment
in a timely manner, as required;
-- Access to third party hosts and associated pipelines can be negotiated
and accessed within the expected timeframe;
-- Field development plan approval and operational construction and
development is obtained within expected timeframes;
-- The Corporation's development plan for the Stella and Harrier
discoveries will be implemented as planned;
-- Reserves volumes assigned to Ithaca's properties;
-- Ability to recover reserves volumes assigned to Ithaca's properties;
-- Revenues do not decrease below anticipated levels and operating costs do
not increase significantly above anticipated levels;
-- future oil, NGLs and natural gas production levels from Ithaca's
properties and the prices obtained from the sales of such production;
-- the level of future capital expenditure required to exploit and develop
reserves;
-- Ithaca's ability to obtain financing on acceptable terms, in particular,
the Corporation's ability to access the Credit Facility;
-- Ithaca's reliance on partners and their ability to meet commitments
under relevant agreements; and
-- the state of the debt and equity markets in the current economic
environment.
The Corporation's actual results could differ materially from those anticipated
in these forward-looking statements and information as a result of assumptions
proving inaccurate and of both known and unknown risks, including the risk
factors set forth in this MD&A and under the heading "Risk Factors" in the AIF
and the documents incorporated by reference herein, and those set forth below:
-- risks associated with the exploration for and development of oil and
natural gas reserves in the North Sea;
-- risks associated with offshore development and production including
transport facilities;
-- operational risks and liabilities that are not covered by insurance;
-- volatility in market prices for oil, NGLs and natural gas;
-- the ability of the Corporation to fund its substantial capital
requirements and operations;
-- risks associated with ensuring title to the Corporation's properties;
-- changes in environmental, health and safety or other legislation
applicable to the Corporation's operations, and the Corporation's
ability to comply with current and future environmental, health and
safety and other laws;
-- the accuracy of oil and gas reserve estimates and estimated production
levels as they are affected by the Corporation's exploration and
development drilling and estimated decline rates;
-- the Corporation's success at acquisition, exploration, exploitation and
development of reserves;
-- the Corporation's reliance on key operational and management personnel;
-- the ability of the Corporation to obtain and maintain all of its
required permits and licenses;
-- competition for, among other things, capital, drilling equipment,
acquisitions of reserves, undeveloped lands and skilled personnel;
-- changes in general economic, market and business conditions in Canada,
North America, the United Kingdom, Europe and worldwide, specifically
being the unavailability of the debt and equity markets to the
Corporation during the current economic crisis;
-- actions by governmental or regulatory authorities including changes in
income tax laws or changes in tax laws, royalty rates and incentive
programs relating to the oil and gas industry including the recent
increase in UK taxes;
-- adverse regulatory rulings, orders and decisions;
-- risks associated with the nature of the common shares; and
-- the impact of adoption of IFRS as opposed to GAAP from January 1, 2011.
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 can be profitably produced in the future. Many of
these risk factors, other specific risks, uncertainties and material assumptions
are discussed in further detail throughout the AIF and in the MD&A. Readers are
specifically referred to the risk factors described in the AIF under "Risk
Factors" and in other documents the Corporation files from time to time with
securities regulatory authorities. Copies of these documents are available
without charge from Ithaca or electronically on the internet on Ithaca's SEDAR
profile at www.sedar.com.
The estimates of reserves and future net revenue for individual properties may
not reflect the same confidence level as estimates of reserves and future net
revenue for all properties, due to the effects of aggregation.
Q2 2011 CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Statement of Income
For the three and six months ended June 30, 2011 and 2010
Three months Six months
(unaudited) ended June 30 ended June 30
2011 2010 2011 2010
Note US$'000 US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 4 16,724 34,129 47,774 64,896
Cost of sales 5 (15,714) (14,806) (32,932) (27,884)
----------------------------------------------------------------------------
Gross Profit 1,010 19,323 14,842 37,012
Exploration and evaluation
expenses 8 (175) - 344 -
Administrative expenses 6 (2,454) (160) (3,514) (2,117)
----------------------------------------------------------------------------
Operating (Loss) / Profit (1,619) 19,163 11,672 34,895
Foreign exchange 428 (362) 2,562 (1,938)
Loss on financial
instruments 19 (263) (4,631) (2,550) (6,604)
----------------------------------------------------------------------------
(Loss) / Profit Before
Interest and Tax (1,454) 14,170 11,684 26,353
Finance costs (489) (75) (749) (151)
Interest income 116 3 275 5
----------------------------------------------------------------------------
(Loss) / Profit Before Tax (1,827) 14,098 11,210 26,207
Taxation - Deferred tax 17 4,687 - (1,740) -
----------------------------------------------------------------------------
Profit After Tax 2,860 14,098 9,470 26,207
Earnings per share
Basic 16 0.01 0.09 0.04 0.16
Diluted 16 0.01 0.09 0.04 0.16
No separate statement of comprehensive income has been prepared as all such
gains and losses have been incorporated in the consolidated statement of income
above.
The accompanying notes are an integral part of the financial statements.
Consolidated Statement of Financial Position
(unaudited)
June 30 December 31 January 1
2011 2010 2010
Note US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents 168,970 195,581 29,886
Restricted cash 7 7,596 6,308 5,224
Accounts receivable 100,168 93,434 67,166
Deposits, prepaid expenses
and other 17,270 12,341 352
Inventory 1,202 - -
Derivative financial
instruments 20 2,932 - 685
Deferred tax asset 2,006 3,745 -
----------------------------------------------------------------------------
300,144 311,409 103,313
Non current assets
Restricted cash 7 - - 352
Exploration and evaluation
assets 8 17,624 17,522 15,500
Property, plant & equipment 9 305,903 249,968 189,975
----------------------------------------------------------------------------
323,527 267,490 205,827
Total assets 623,671 578,899 309,140
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables 102,959 75,564 43,613
Commodity hedge - 349 397
----------------------------------------------------------------------------
102,959 75,913 44,010
Non current liabilities
Decommissioning liabilities 11 25,653 23,652 8,751
Other long term liabilities 12 2,726 2,872 2,718
Contingent consideration 13 10,976 12,976 6,933
Derivative financial
instruments 20 3,509 4,378 -
----------------------------------------------------------------------------
42,864 43,878 18,402
---------------------------------------------------------------------------
Net Assets 477,848 459,108 246,728
----------------------------------------------------------------------------
Equity attributable to
equity holders
Share capital 14 428,819 422,373 277,075
Contributed surplus 15 14,562 11,427 6,860
Warrants issued 14 - 311 -
Retained earnings /
(deficit) 34,467 24,997 (37,207)
----------------------------------------------------------------------------
Shareholders' Equity 477,848 459,108 246,728
----------------------------------------------------------------------------
Jay Zammit, Director
John Summers, Director
The accompanying notes are an integral part of the financial statements.
Consolidated Statement of Changes in Equity
(unaudited)
Retained
Share Contributed Warrants E'ings/
Capital Surplus Issued (Deficit) Total
US$'000 US$'000 US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, Jan 1 2010 277,075 6,860 - (37,207) 246,728
Net income for the
period - - - 12,108 12,108
----------------------------------------------------------------------------
Total comprehensive
income 277,075 6,860 - (25,099) 258,836
Transactions with
owners
Stock based
compensation - 1,181 - - 1,181
Options exercised 99 (47) - - 52
----------------------------------------------------------------------------
Balance, June 30
2010 277,174 7,994 - (25,099) 260,069
----------------------------------------------------------------------------
Balance, Jan 1 2011 422,373 11,427 311 24,997 459,108
Net income for the
period - - - 9,470 9,470
----------------------------------------------------------------------------
Total comprehensive
income 422,373 11,427 311 34,467 468,578
Transactions with
owners
Stock based
compensation - 3,283 - - 3,283
Options exercised 349 (148) - - 201
Warrants exercised 6,097 - (311) - 5,786
----------------------------------------------------------------------------
Balance, June 30
2011 428,819 14,562 - 34,467 477,848
----------------------------------------------------------------------------
The accompanying notes are an integral part of the financial statements.
Consolidated Statement of Cash Flow
For the six months ended June 30, 2011 and 2010
(unaudited)
Three months Six months
ended June 30 ended June 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CASH PROVIDED BY (USED
IN):
Operating activities
(Loss) / Profit Before
Tax (1,827) 14,098 11,210 26,207
Adjustments for:
Depletion,
depreciation and
amortization 4,200 5,346 11,172 9,735
Exploration and
evaluation expenses 175 - 1,656 -
Stock based
compensation 643 (581) 1,235 601
Loan fee amortization 78 - 154 -
Unrealized (gain) /
loss on financial
instruments 263 (225) 2,057 1,583
Revaluation of
contingent
consideration - 4,044 (2,000) 4,044
Accretion 175 71 353 143
----------------------------------------------------------------------------
Cashflow from operations 3,707 22,753 25,837 42,313
----------------------------------------------------------------------------
Movement in working
capital 1,751 15,589 7,378 729
----------------------------------------------------------------------------
Net cash from operating
activities 5,458 38,342 33,215 43,042
----------------------------------------------------------------------------
Investing activities
Capital expenditure
Oil and gas assets (42,169) (13,794) (65,950) (28,360)
Non oil and gas
assets (90) (46) (472) (145)
Movement in working
capital 16,643 6,385 7,470 2,529
----------------------------------------------------------------------------
Net cash used in
investing activities (25,616) (7,455) (58,952) (25,976)
----------------------------------------------------------------------------
Financing activities
Proceeds from issuance
of shares - 69 5,986 121
(Increase) / decrease
in restricted cash (1) - (1,288) 5,241
Derivatives (2,445) - (6,508) -
---------------------------------------------------------------------------
Net cash from financing
activities (2,446) 69 (1,810) 5,362
----------------------------------------------------------------------------
Currency translation
differences relating to
cash 240 (30) 936 (1,304)
----------------------------------------------------------------------------
(Decrease) / increase in
cash & cash equiv. (22,364) 30,926 (26,611) 21,124
----------------------------------------------------------------------------
Cash and cash
equivalents, beginning
of period 191,334 20,084 195,581 29,886
----------------------------------------------------------------------------
Cash and cash
equivalents, end of
period 168,970 51,010 168,970 51,010
----------------------------------------------------------------------------
The accompanying notes are an integral part of the financial statements.
1. NATURE OF OPERATIONS
Ithaca Energy Inc. (the "Corporation" or "Ithaca"), incorporated and domiciled
in Alberta, Canada on April 27, 2004, is a publicly traded company involved in
the exploration, development and production of oil and gas in the North Sea. The
Corporation's registered office is 1600, 333 - 7th Avenue S.W., Calgary,
Alberta, Canada, T2P 2Z1. The Corporation's shares are listed on the TSX Venture
Exchange in Canada and the London Stock Exchange's Alternative Investment Market
in the United Kingdom under the symbol "IAE". Ithaca has a wholly-owned
subsidiary Ithaca Energy (UK) Limited ("Ithaca UK"), incorporated in Scotland.
2. BASIS OF PREPARATION AND ADOPTION OF IFRS
The Corporation prepares its financial statements in accordance with Canadian
generally accepted accounting principles as set out in the Handbook of the
Canadian Institute of Chartered Accountants ("CICA Handbook"). In 2010, the CICA
Handbook was revised to incorporate International Financial Reporting Standards
("IFRS"), and require publicly accountable enterprises to apply such standards
effective for years beginning on or after January 1, 2011. Accordingly, the
Corporation has commenced reporting on this basis in these interim consolidated
financial statements. In the financial statements, the term "Canadian GAAP"
refers to Canadian GAAP before the adoption of IFRS.
These interim consolidated financial statements have been prepared in accordance
with IFRS applicable to the preparation of interim financial statements,
including IAS 34 Interim Financial Reporting and IFRS 1 First Time Adoption of
IFRS. These interim consolidated financial statements do not include all the
necessary annual disclosures in accordance with IFRS. Subject to certain
transition elections disclosed in note 24, the Corporation has consistently
applied the same accounting policies in its opening IFRS statement of financial
position at January 1, 2010 and throughout all periods presented, as if these
policies had always been in effect. Note 24 discloses the impact of the
transition to IFRS on the Corporation's reported financial position, financial
performance and cash flows, including the nature and effect of significant
changes in accounting policies from those used in the Corporation's consolidated
financial statements for the year ended December 31, 2010.
The policies applied in these condensed interim consolidated financial
statements are based on IFRS issued and outstanding as of August 25, 2011, the
date the Board of Directors approved the statements. Any subsequent changes to
IFRS that are given effect in the Corporation's annual consolidated financial
statements for the year ending December 31, 2011 could result in restatement of
these interim consolidated financial statements, including the transition
adjustments recognized on change-over to IFRS.
The condensed interim consolidated financial statements should be read in
conjunction with the Corporation's Canadian GAAP annual financial statements for
the year ended December 31, 2010. Note 24 discloses IFRS information for the
year ended December 31, 2010 not provided in the 2010 annual financial
statements.
3. SIGNIFICANT ACCOUNTING POLICIES, JUDGEMENTS AND ESTIMATION UNCERTAINTY
Basis of measurement
The consolidated financial statements have been prepared under the historical
cost convention, except for the revaluation of certain financial assets and
financial liabilities to fair value, including derivative instruments.
Principles of consolidation
The consolidated financial statements of the Corporation include the accounts of
Ithaca Inc. and its wholly-owned subsidiary Ithaca Energy (UK) Ltd. All
inter-company transactions and balances have been eliminated on consolidation.
A subsidiary is an entity (including special purpose entities) which the
Corporation controls by having the power to govern the financial and operating
policies. The existence and effect of potential voting rights that are currently
exercisable or convertible are considered when assessing whether Ithaca controls
another entity. A subsidiary is fully consolidated from the date on which
control is obtained by Ithaca and is de-consolidated from the date that control
ceases.
Foreign currency translation
Items included in the financial statements are measured using the currency of
the primary economic environment in which the Corporation and its subsidiary
operate (the 'functional currency'). The consolidated financial statements are
presented in United States Dollars, which is the Corporation's and Ithaca UK's
functional and presentation currency.
Foreign currency transactions are translated into the functional currency using
the exchange rates prevailing at the dates of the transactions. Foreign exchange
gains and losses resulting from the settlement of such transactions and from the
translation at year end exchange rates of monetary assets and liabilities
denominated in foreign currencies are recognized in the statement of income.
Share based payments
The Corporation has a stock based compensation plan as described in note 14 (b).
The Corporation's proportionate share of expense is recorded in the statement of
income or capitalized for all options granted in the year, with the gross
increase recorded as contributed surplus. Compensation costs are based on the
estimated fair values at the time of the grant and the expense or capitalized
amount is recognized over the vesting period of the options. Upon the exercise
of the stock options, consideration paid together with the amount previously
recognized in contributed surplus is recorded as an increase in share capital.
In the event that vested options expire unexercised, previously recognized
compensation expense associated with such stock options is not reversed. In the
event that unvested options are forfeited or expired, previously recognized
compensation expense associated with the unvested portion of such stock options
is reversed.
Cash and cash equivalents
For the purpose of cash flow statements, cash and cash equivalents include
investments with an original maturity of three months or less.
Restricted cash
Cash that is held for security for bank guarantees is reported in the balance
sheet and cash flow statements separately. If the expected duration of the
restriction is less than twelve months then it is shown in current assets.
Financial instruments
All financial instruments are initially recognized at fair value on the balance
sheet. The Corporation's financial instruments consist of cash, restricted cash,
accounts receivable, deposits, derivatives, loan fees, accounts payable, accrued
liabilities, contingent consideration and the long term liability on the
Beatrice acquisition. The Corporation classifies its financial instruments into
one of the following categories: held-for-trading financial assets and financial
liabilities; held-to-maturity investments; loans and receivables; and other
financial liabilities. All financial instruments are required to be measured at
fair value on initial recognition. Measurement in subsequent periods is
dependent on the classification of the respective financial instrument.
Held-for-trading financial instruments are subsequently measured at fair value
with changes in fair value recognized in net earnings. All other categories of
financial instruments are measured at amortized cost using the effective
interest method. Cash and cash equivalents are classified as held-for-trading
and are measured at fair value. Accounts receivable are classified as loans and
receivables. Accounts payable, accrued liabilities, certain other long-term
liabilities, and long-term debt are classified as other financial liabilities.
Although the Corporation does not intend to trade its derivative financial
instruments, they are classified as held-for-trading for accounting purposes.
Transaction costs that are directly attributable to the acquisition or issue of
a financial asset or liability and original issue discounts on long-term debt
have been included in the carrying value of the related financial asset or
liability and are amortized to consolidated net earnings over the life of the
financial instrument using the effective interest method.
Analysis of the fair values of financial instruments and further details as to
how they are measured are provided in notes 19 to 21.
Inventory
Inventories of materials and product inventory supplies, other than oil and gas
inventories, are stated at the lower of cost and net realizable value. Cost is
determined on the first-in, first-out method. Oil and gas inventories are stated
at fair value less cost to sell.
Property, plant and equipment
Oil and gas expenditure - exploration and evaluation assets
Capitalisation
Pre-acquisition costs on oil and gas assets are recognised in the Income
Statement when incurred. Costs incurred after rights to explore have been
obtained, such as geological and geophysical surveys, drilling and commercial
appraisal costs and other directly attributable costs of exploration and
evaluation including technical and administrative costs are capitalised as
intangible exploration and evaluation ("E&E") assets.
E&E costs are not amortised prior to the conclusion of evaluation activities. At
completion of evaluation activities, if technical feasibility is demonstrated
and commercial reserves are discovered then, following development sanction, the
carrying value of the E&E asset is reclassified as a development and production
("D&P") asset, but only after the carrying value is assessed for impairment and
where appropriate its carrying value adjusted. If after completion of evaluation
activities in an area, it is not possible to determine technical feasibility and
commercial viability or if the legal right to explore expires or if the
Corporation decides not to continue exploration and evaluation activity, then
the costs of such unsuccessful exploration and evaluation is written off to the
Income Statement in the period the relevant events occur.
Impairment
The Corporation's oil and gas assets are analysed into cash generating units
("CGU") for impairment review purposes, with E&E asset impairment testing being
performed at a grouped CGU level. The current E&E CGU consists of the
Corporation's whole E&E portfolio. E&E assets are reviewed for impairment when
circumstances arise which indicate that the carrying value of an E&E asset
exceeds the recoverable amount. When reviewing E&E assets for impairment, the
combined carrying value of the grouped CGU is compared with the grouped CGU's
recoverable amount. The recoverable amount of a grouped CGU is determined as the
higher of its fair value less costs to sell and value in use. Impairment losses
resulting from an impairment review are written off to the Income Statement.
Oil and gas expenditure - development and production assets
Capitalisation
Costs of bringing a field into production, including the cost of facilities,
wells and sub-sea equipment together with E&E assets reclassified in accordance
with the above policy, are capitalised as a D&P asset. Normally each individual
field development will form an individual D&P asset but there may be cases, such
as phased developments, or multiple fields around a single production facility
when fields are grouped together to form a single D&P asset.
Depreciation
All costs relating to a development are accumulated and not depreciated until
the commencement of production. Depreciation is calculated on a unit of
production basis based on the proved and probable reserves of the asset. Any
re-assessment of reserves affects the depreciation rate prospectively.
Significant items of plant and equipment will normally be fully depreciated over
the life of the field. However, these items are assessed to consider if their
useful lives differ from the expected life of the D&P asset and should this
occur a different depreciation rate would be charged.
Impairment
A review is carried out each reporting date for any indication that the carrying
value of the Corporation's D&P assets may be impaired. For D&P assets where
there are such indications, an impairment test is carried out on the CGU. Each
CGU is identified in accordance with IAS 36. The Corporation's CGUs are those
assets which generate largely independent cash flows and are normally, but not
always, single developments or production areas. The impairment test involves
comparing the carrying value with the recoverable value of an asset. The
recoverable amount of an asset is determined as the higher of its fair value
less costs to sell and value in use, where the value in use is determined from
estimated future net cash flows. Any additional depreciation resulting from the
impairment testing is charged to the Income Statement.
(b) Non Oil and Natural Gas Operations
Computer and office equipment is recorded at cost and depreciated over its
estimated useful life on a straight-line basis over three years. Furniture and
fixtures are recorded at cost and depreciated over their estimated useful lives
on a straight-line basis over five years.
Decommissioning liabilities
The Corporation records the present value of legal obligations associated with
the retirement of long term tangible assets, such as producing well sites and
processing plants, in the period in which they are incurred with a corresponding
increase in the carrying amount of the related long term asset. In subsequent
periods, the asset is adjusted for any changes in the estimated amount or timing
of the settlement of the obligations. The carrying amounts of the associated
assets are depleted using the unit of production method, in accordance with the
depreciation policy for development and production assets. Actual costs to
retire tangible assets are deducted from the liability as incurred.
Contingent consideration
Contingent consideration is accounted for as a financial liability and measured
at fair value at the date of acquisition with any subsequent remeasurements
recognised either in profit or loss or in other comprehensive income in
accordance with IAS 39.
Taxation
Deferred tax is recognized for all deductible temporary differences and the
carry-forward of unused tax losses. Deferred tax assets and liabilities are
measured using enacted or substantively enacted income tax rates expected to
apply to taxable income in the years in which temporary differences are expected
to be recovered or settled. The effect on deferred tax assets and liabilities of
a change in rates is included in earnings in the period of the enactment date.
Deferred tax assets are recorded in the consolidated financial statements if
realization is considered more likely than not.
Recent accounting pronouncements
In May 2011, the IASB issued the following standards: IFRS 10, Consolidated
Financial Statements ("IFRS 10"), IFRS 11, Joint Arrangements ("IFRS 11"), IFRS
12, Disclosure of Interests in Other Entities ("IFRS 12"), IAS 27, Separate
Financial Statements ("IAS 27"), IFRS 13, Fair Value Measurement ("IFRS 13") and
amended IAS 28, Investments in Associates and Joint Ventures ("IAS 28"). Each of
the new standards is effective for annual periods beginning on or after January
1, 2013 with early adoption permitted. The Corporation has not yet assessed the
impact that the new and amended standards will have on its financial statements
or whether to early adopt any of the new requirements.
Significant accounting judgements and estimation uncertainties
The preparation of financial statements in conformity with IFRS requires
management to make estimates and assumptions regarding certain assets,
liabilities, revenues and expenses. Such estimates must often be made based on
unsettled transactions and other events and a precise determination of many
assets and liabilities is dependent upon future events. Actual results may
differ from estimated amounts.
The amounts recorded for depletion, depreciation of property and equipment,
long-term liability, stock-based compensation, contingent consideration,
decommissioning liabilities, derivatives, warrants, and deferred taxes are based
on estimates. The depreciation charge and any impairment tests are based on
estimates of proved and probable reserves, production rates, prices, future
costs and other relevant assumptions. By their nature, these estimates are
subject to measurement uncertainty and the effect on the financial statements of
changes in such estimates in future periods could be material.
4. REVENUE
Three months Six months
ended June 30 ended June 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil sales 13,246 33,094 38,379 63,196
Gas sales 2,841 - 6,763 -
Condensate sales 255 - 576 -
Other income 382 1,035 2,056 1,700
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 16,724 34,129 47,774 64,896
5. COST OF SALES
Three months Six months
ended June 30 ended June 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating costs (11,514) (9,460) (21,760) (18,149)
Depletion, depreciation and
amortisation (4,200) (5,346) (11,172) (9,735)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(15,714) (14,806) (32,932) (27,884)
6. ADMINISTRATIVE EXPENSES
Three months Six months
ended June 30 ended June 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General & administrative (1,811) (741) (2,279) (1,516)
Stock based compensation (643) 581 (1,235) (601)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(2,454) (160) (3,514) (2,117)
7. RESTRICTED CASH
June 30 Dec 31 Jan 1
2011 2010 2010
US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Decommissioning security 7,240 5,956 -
Cash security - Crown estate 356 352 352
Cash security - Foreign exchange
contract - - 5,224
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7,596 6,308 5,576
Restricted cash of $7.2 million is held by the Bank of Scotland as
decommissioning security in respect of the Corporation's interests in the Anglia
field.
Further restricted cash of $0.4 million is held by the Bank of Scotland as cash
security for a Bank Guarantee that Ithaca Energy (UK) Limited provided to the
Crown Estate when it was granted Field Development Plan approval for the Jacky
Field.
$5.2 million of restricted cash held by the Bank of Scotland in 2009 as cash
security for the 2010 foreign exchange forward contract was released in January
2010.
8.EXPLORATION AND EVALUATION ASSETS
US$'000
------------------------------------------------------------
------------------------------------------------------------
At January 1, 2010 15,500
Additions 3,141
Write offs/relinquishments (1,119)
------------------------------------------------------------
At December 31, 2010 17,522
Additions 1,758
Write offs/relinquishments (1,656)
------------------------------------------------------------
------------------------------------------------------------
At June 30, 2011 17,624
Following completion of geotechnical evaluation activity, certain licences were
declared unsuccessful and certain prospects were declared non-commercial and
therefore the related expenditures of $0.2 million and $1.7 million were
expensed in the three and six months to June 30, 2011 respectively. $2 million
of associated contingent consideration relating to those licences and prospects
was also released to the consolidated statement of income in Q1 to give a total
credit of $0.3 million for the six months ended June 30, 2011. See note 13 for
details.
9. PROPERTY, PLANT AND EQUIPMENT
Development &
Production Other
Oil and fixed
Gas assets assets Total
US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cost
At January 1, 2010 189,458 1,274 190,732
Additions 82,879 313 83,192
----------------------------------------------------------------------------
At December 31, 2010 272,337 1,587 273,924
Additions 66,634 473 67,107
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At June 30, 2011 338,971 2,060 341,031
DD&A
At January 1, 2010 - (757) (757)
Charge for the period (22,852) (347) (23,199)
----------------------------------------------------------------------------
At December 31, 2010 (22,852) (1,104) (23,956)
Charge for the period (10,978) (194) (11,172)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At June 30, 2011 (33,830) (1,298) (35,128)
NBV at January 1, 2010 189,458 517 189,975
NBV at January 1, 2011 249,485 483 249,968
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NBV at June 30, 2011 305,141 762 305,903
10. LOAN FACILITY
On July 12, 2010, the Corporation signed and completed a Senior Secured
Borrowing Base Facility agreement (the "Facility") for up to US$140 million with
the Bank of Scotland Plc. The loan term is up to five years and will attract
interest at LIBOR plus 3-4.5%. Loan issue costs of $0.9 million were incurred in
the year ended December 31, 2010 and are being amortized over the period of the
loan (approx $0.2 million amortized in the six months ended June 30, 2011).
The Corporation is subject to financial and operating covenants related to the
Facility. Failure to meet the terms of one or more of these covenants may
constitute an event of default as defined in the Facility agreement, potentially
resulting in accelerated repayment of the debt obligations.
The Corporation is in compliance with its financial and operating covenants.
No funds are currently drawn down under the Facility.
11. DECOMMISSIONING LIABILITIES
June 30 Dec 31
2011 2010
US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, beginning of period 23,652 8,751
Additions 1,921 12,772
Accretion 353 283
Revision to estimates (273) 1,846
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, end of period 25,653 23,652
The total future decommissioning liability was calculated by management based on
its net ownership interest in all wells and facilities, estimated costs to
reclaim and abandon wells and facilities and the estimated timing of the costs
to be incurred in future periods. The Corporation uses a risk free rate of 3
percent and an inflation rate of 2 percent over the varying lives of the assets
to calculate the present value of the decommissioning liabilities. These costs
are expected to be incurred at various intervals over the next 9 years. The
economic life and the timing of the obligations are dependent on Government
legislation, commodity price and the future production profiles of the
respective production and development facilities. Note that upon the acquisition
of the Beatrice Field in November 2008, the Corporation did not assume the
decommissioning liabilities.
12. OTHER LONG TERM LIABILITIES
June 30 Dec 31
2011 2010
US$'000 US$'000
----------------------------------------------------------------------
----------------------------------------------------------------------
Balance, beginning of period 2,872 2,718
Revaluation in the period (146) 154
----------------------------------------------------------------------
----------------------------------------------------------------------
Balance, end of period 2,726 2,872
On completion of the acquisition of the Beatrice Facilities on November 10, 2008
there were 75,000 barrels of oil in an oil storage tank at the Nigg Terminal.
This volume of oil is required to be in the storage tank when the Beatrice
Facilities are re-transferred. This volume of oil is valued at the price on the
forward oil price curve at the expected date of re-transfer and discounted. The
liability is subject to revaluation at each financial period end. The expected
date of re-transfer is likely to be more than three years in the future.
13. CONTINGENT CONSIDERATION
June 30 Dec 31
2011 2010
US$'000 US$'000
----------------------------------------------------------------------
----------------------------------------------------------------------
Balance, beginning of period 12,976 6,933
Additions - 2,000
Revision to estimates (2,000) 4,043
----------------------------------------------------------------------
----------------------------------------------------------------------
Balance, end of period 10,976 12,976
The contingent consideration at the end of the period relates to the acquisition
of the Stella field and is payable once Field Development Plan approval is
received.
The revision in the period relates to the reassessment of the Opal and Garnet
prospects which have been determined uncommercial, resulting in a release of the
associated contingent consideration.
14. SHARE CAPITAL
(a) Issued
The issued share capital is as follows:
Issued
Number of
common Amount
shares US$'000
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Balance January 1, 2010 162,361,975 277,075
Issued for cash - options exercised 765,205 305
Transfer from Contributed Surplus on options
exercised 273
Issued for cash - prospectus 92,662,284 153,248
Share issue costs (8,528)
---------------------------------------------------------------------------
Balance December 31, 2010 255,789,464 422,373
Issued for cash - options exercised 245,831 201
Issued for cash - warrants exercised 2,500,000 5,786
Transfer from Contributed Surplus on options
exercised 148
Transfer from Warrants issued on warrants
exercised 311
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Balance June 30, 2011 258,535,295 428,819
On July 28 2010, the Corporation successfully closed a Canadian bought deal and
UK private placement. Gross proceeds were $78.3 million (C$80.9 million) through
the issue of 47.6 million shares at a price of C$1.70 per share and $74.9
million (GBP 48.2 million) through the issue of 45.1 million shares at GBP 1.07
per common share.
(b) Stock options
In the quarter ended March 31, 2011, the Corporation's Board of Directors
granted 260,000 options at a weighted average exercise price of $1.99 (C$2.01).
200,000 of these options were reserved for issue in Q3 2010 in contemplation of
hiring.
The Corporation's stock options and exercise prices are denominated in Canadian
Dollars when granted. As at June 30, 2011, 19,398,505 stock options to purchase
common shares were outstanding, having an exercise price range of $0.20 to $3.65
(C$0.25 to C$3.65) per share and a vesting period of up to 3 years in the
future.
Changes to the Corporation's stock options are summarized as follows:
June 30, 2011 December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Wt. Avg Wt. Avg
No. of Exercise No. of Exercise
Options Price (i) Options Price (i)
----------------------------------------------------------------------------
Balance, beginning of period 20,146,003 $1.61 11,042,875 $1.48
Granted 260,000 $1.99 10,100,000 $1.88
Forfeited / expired (761,667) $2.15 (231,667) $1.28
Exercised (245,831) $0.77 (765,205) $0.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Options 19,398,505 $1.65 20,146,003 $1.61
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i) The weighted average exercise price has been converted into U.S. dollars
based on the foreign exchange rate in effect at the date of issuance.
The following is a summary of stock options as at June 30, 2011
Options Options
Outstanding Exercisable
------------------------------------- -------------------------------------
Wt. Wt.
Wt. Avg. Wt. Avg.
Avg. Exer- Avg. Exer-
Range of Life cise Range of Life cise
Exercise No. of (Ye- Price Exercise No. of (Ye- Price
Price Options ars) (i) Price Options ars) (i)
------------------------------------- -------------------------------------
$3.65 $3.65
(C$3.65) 2,365,000 0.6 $3.65 (C$3.65) 2,365,000 0.6 $3.65
$2.22-$2.86 $2.22-$2.86
(C$2.25- (C$2.25-
C$3.00) 5,935,000 3.0 $2.24 C$3.00) 818,333 0.2 $2.35
$1.49-$1.76 $1.49-$1.68
(C$1.54- (C$1.54-
C$1.85) 5,411,667 2.5 $1.55 C$1.80) 1,711,664 2.3 $1.53
$0.20-$0.81 $0.20-$0.81
(C$0.25- (C$0.25-
C$0.87) 5,686,838 2.3 $0.55 C$0.87) 2,622,753 2.3 $0.45
------------------------------------- -------------------------------------
19,398,505 2.4 $1.73 7,517,750 1.6 $1.91
------------------------------------- -------------------------------------
------------------------------------- -------------------------------------
The following is a summary of stock options as at December 31, 2010
Options Options
Outstanding Exercisable
------------------------------------- -------------------------------------
Wt. Wt.
Wt. Avg. Wt. Avg.
Avg. Exer- Avg. Exer-
Range of Life cise Range of Life cise
Exercise No. of (Ye- Price Exercise No. of (Ye- Price
Price Options ars) (i) Price Options ars) (i)
------------------------------------- -------------------------------------
$3.65 $3.65
(C$3.65) 2,435,000 1.14 $3.65 (C$3.65) 1,623,334 1.1 $3.65
$2.22-$2.86 $2.29-$2.86
(C$2.25- (C$2.51-
C$3.00) 6,375,000 2.40 $2.25 C$3.00) 1,285,000 0.3 $2.38
$1.49-$1.76 $1.49-$1.68
(C$1.54- (C$1.54-
C$1.85) 5,345,000 3.01 $1.54 C$1.80) 300,000 1.7 $1.68
$0.20-$0.81 $0.20-$0.81
(C$0.25- (C$0.25-
C$0.87) 5,991,003 2.77 $0.55 C$0.87) 2,591,084 2.8 $0.45
------------------------------------- -------------------------------------
20,146,003 2.50 $1.61 5,799,418 1.3 $1.44
------------------------------------- -------------------------------------
------------------------------------- -------------------------------------
(c) Stock based compensation
Options granted are accounted for using the fair value method. The compensation
cost during the three months and six months ended June 30, 2011 for total stock
options granted was $1.7 million and $3.3 million respectively (Q2 2010: $1.2
million, Q2 YTD: $2.3 million). $0.6 million and $1.2 million were charged
through the income statement for stock based compensation for the three and six
months ended June 31, 2011 respectively, being the Corporation's share of stock
based compensation chargeable through the income statement. The remainder of the
Corporation's share of stock based compensation has been capitalized. The fair
value of each stock option granted was estimated at the date of grant, using the
Black-Scholes option pricing model with the following assumptions:
For the six For the
months ended year ended
June 30, 2011 December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Risk free interest rate 1.20% 1.20%
Expected stock volatility 97% 104%
Expected life of options 3 years 3 years
Weighted Average Fair Value $1.64 $1.14
(d) Gemini Agreement
In September 2006 Gemini Oil & Gas Fund 11 L.P. ("Gemini") provided non-recourse
funding of $6 million. Further to a supplemental agreement entered into in
August 2008, the loan was fully repaid. Under the supplemental agreement Gemini
retained rights, under certain circumstances relating to the Athena Field, to
elect to receive warrants to acquire up to 3,000,000 common shares at $3.00 per
share and to receive payments connected to asset sales of interests in Athena.
On September 20, 2010, a further agreement was entered into with Gemini whereby
in exchange for and in consideration of Gemini's waiver of any right to proceeds
from the disposal of equity interest in the Athena discovery and in substitution
for any previously awarded or agreed warrants, Ithaca Energy Inc. granted Gemini
warrants to acquire up to 2,500,000 common shares in Ithaca Energy Inc. The
warrants were exercised at C$2.25 per share on March 3, 2011. The agreement
terminates all rights that Gemini has in respect of the Corporation's interests.
The total fair value attributed to warrants issued in 2010 was $0.3 million.
15.CONTRIBUTED SURPLUS
June 30 Dec 31
2011 2010
US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, beginning of period 11,427 6,860
Stock based compensation cost 3,283 4,840
Transfer to share capital on exercise of
options (148) (273)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, end of period 14,562 11,427
16. EARNINGS PER SHARE
The calculation of basic earnings per share is based on the profit after tax and
the weighted average number of common shares in issue during the period. The
calculation of diluted earnings per share is based on the profit after tax and
the weighted average number of potential common shares in issue during the
period.
Three months Six months
ended June 30 ended June 30
2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Wtd av. number of
common shares (basic) 258,535,295 162,555,640 257,691,879 162,555,640
Wtd av. number of
common shares
(diluted) 263,211,406 165,518,118 262,979,178 165,518,118
17. TAXATION
Three months Six months
ended June 30 ended June 30
2011 2010 2011 2010
US$000 US$000 US$000 US$000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Deferred tax 4,687 - (1,740) -
Current corporation tax payable of $23k is related to tax on interest income
from cash held on deposit. No corporation tax is payable in relation to upstream
oil and gas activities.
18.COMMITMENTS
Year ended
Subsequent
to
2011 2012 2013 2014 2014
US$'000 US$'000 US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Office lease 128 256 256 256 833
Exploration 875 1,248 1,602 - -
Engineering 14,362 20,079 11,679 11,679 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 15,365 21,583 13,537 11,935 833
19. FINANCIAL INSTRUMENTS
To estimate fair value of financial instruments, the Corporation uses quoted
market prices when available, or industry accepted third-party models and
valuation methodologies that utilize observable market data. In addition to
market information, the Corporation incorporates transaction specific details
that market participants would utilize in a fair value measurement, including
the impact of non-performance risk. The Corporation characterizes inputs used in
determining fair value using a hierarchy that prioritizes inputs depending on
the degree to which they are observable. However, these fair value estimates may
not necessarily be indicative of the amounts that could be realized or settled
in a current market transaction. The three levels of the fair value hierarchy
are as follows:
-- Level 1 - inputs represent quoted prices in active markets for identical
assets or liabilities (for example, exchange- traded commodity
derivatives). Active markets are those in which transactions occur in
sufficient frequency and volume to provide pricing information on an
ongoing basis.
-- Level 2 - inputs other than quoted prices included within Level 1 that
are observable, either directly or indirectly, as of the reporting date.
Level 2 valuations are based on inputs, including quoted forward prices
for commodities, market interest rates, and volatility factors, which
can be observed or corroborated in the marketplace. The Corporation
obtains information from sources such as the New York Mercantile
Exchange and independent price publications.
-- Level 3 - inputs that are less observable, unavailable or where the
observable data does not support the majority of the instrument's fair
value.
In forming estimates, the Corporation utilizes the most observable inputs
available for valuation purposes. If a fair value measurement reflects inputs of
different levels within the hierarchy, the measurement is categorized based upon
the lowest level of input that is significant to the fair value measurement. The
valuation of over-the-counter financial swaps and collars is based on similar
transactions observable in active markets or industry standard models that
primarily rely on market observable inputs. Substantially all of the assumptions
for industry standard models are observable in active markets throughout the
full term of the instrument. These are categorized as Level 2.
The following table presents the Corporation's material financial instruments
measured at fair value for each hierarchy level as of June 30, 2011:
Total Fair
Level 1 Level 2 Level 3 Value
US$'000 US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivative financial
instrument assets - 2,932 - 2,932
Long term liability on
Beatrice acquisition - - (2,726) (2,726)
Contingent consideration - (10,976) - (10,976)
Derivative financial
instrument liability - (3,509) - (3,509)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The table below presents the total gain / (loss) on financial instruments that
has been disclosed through the statement of net and comprehensive income /
(loss):
Three months Six months
ended June 30 ended June 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Unrealized gain/(loss)
on forex forward
contracts - 229 - (2,159)
Realized (loss)/gain on
forex forward contracts - (811) - (1,062)
Revaluation of gas
contract 1,221 - 1,024 -
Revaluation of other
long term liability 32 (5) 146 179
Contingent consideration - (4,044) - (4,044)
Unrealized (loss)/gain
on commodity hedges (1,516) - (3,227) 86
Realized (loss)/gain on
commodity hedges - - (493) 396
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total (loss) on
financial instruments (263) (4,631) (2,550) (6,604)
The Corporation has identified that it is exposed principally to these areas of
market risk.
i) Commodity Risk
Commodity price risk related to crude oil prices is the Corporation's most
significant market risk exposure. Crude oil prices and quality differentials are
influenced by worldwide factors such as OPEC actions, political events and
supply and demand fundamentals. The Corporation is also exposed to natural gas
price movements on uncontracted gas sales. Natural gas prices, in addition to
the worldwide factors noted above, can also be influenced by local market
conditions. The Corporation's expenditures are subject to the effects of
inflation, and prices received for the product sold are not readily adjustable
to cover any increase in expenses from inflation. The Corporation may
periodically use different types of derivative instruments to manage its
exposure to price volatility, thus mitigating fluctuations in commodity-related
cash flows.
In Q4 2009 the Corporation entered into a forward swap for 51,000 barrels per
month over November, December, January and February 2010 production fixing the
price at $77/barrel. In Q4 2010, the Corporation entered into another forward
swap for 108,668 and 80,600 barrels per month over December and January
respectively to hedge a proportion of November and December production. The
combination of these forward swaps resulted in a realized loss of $0.5 million
and an unrealized gain of $0.3 million in the 6 months ended June 30, 2011.
In Q1 2011 the Corporation purchased a put option with a floor price of $105 /
barrel for 804,500 barrels of oil for the period March to December 2011. The
option delivers a minimum price on the specified volume of oil and allows the
Corporation to benefit from any upside above $105 / barrel. Due to movements in
forecast oil prices the revaluation of this instrument in the three months ended
June 30, 2011 resulted in an unrealized loss of $1.4 million.
In Q2 2011 the Corporation purchased a put option with a floor price of $115 /
barrel for 300,000 barrels of 2011 production. The option delivers a minimum
price on the specified volume of oil and allows the Corporation to benefit from
any upside above $115 / barrel. Due to movements in forecast oil prices the
revaluation of this instrument in the three months ended June 30, 2011 resulted
in an unrealized loss of $0.1 million.
ii) Interest Risk
Calculation of interest payments for the Senior Secured Borrowing Base Facility
agreement with the Bank of Scotland that was signed on July 12, 2010
incorporates LIBOR. The Corporation will therefore be exposed to interest rate
risk to the extent that LIBOR may fluctuate. The Corporation will evaluate its
annual forward cash flow requirements on a rolling monthly basis. No funds are
currently drawn down under the facility.
iii) Foreign Exchange Rate Risk
The Corporation is exposed to foreign exchange risks to the extent it transacts
in various currencies, while measuring and reporting its results in US Dollars.
Since time passes between the recording of a receivable or payable transaction
and its collection or payment, the Corporation is exposed to gains or losses on
non USD amounts and on balance sheet translation of monetary accounts
denominated in non USD amounts upon spot rate fluctuations from quarter to
quarter.
On July 7, 2010, in order to protect against the strengthening of the US Dollar
and secure the net proceeds from the equity raise of $150 million the
Corporation entered into a foreign exchange forward contract to swap the
Canadian Dollars and Pounds Sterling proceeds of the Canadian bought deal and UK
Private placement in exchange for US Dollars when the proceeds were estimated to
be received at contracted rates of $1.00 / C$1.0489 and $1.00 / GBP 0.6592.
During the period the US Dollar weakened with the result that the forex
instruments prevented an exchange gain being realized. Forex losses of $3.1
million were recorded which offset the natural gain reflected in equity.
On October 12, 2009, the Corporation entered in to a Window Forward Plus
contract with the Bank of Scotland to hedge its forecast British Pounds Sterling
2010 operating costs, including general and administrative expenses. The hedge
amounts to $4 million per month (total $48 million) at a US$/GBP rate of no
worse than USD1.60/1.0 and a Trigger rate of USD1.4975/GBP 1.00. A realized loss
of $1.3 million has been recognized on the contract for the year ended December
31, 2010. This contract expired in December 2010, and the resulting unwinding of
unrealized gains and losses on the contracts resulted in an unrealized loss of
$0.7 million for the year ended December 31, 2010.
iv) Credit Risk
The Corporation's accounts receivable with customers in the oil and gas industry
are subject to normal industry credit risks and are unsecured. It should be
noted that the Corporation has entered in to a five year marketing agreement
with BP Oil International Limited to sell all of its North Sea oil production.
All gas production, acquired through the purchase of the Anglia and Topaz fields
from GDF SUEZ E&P UK Ltd, is currently sold through three contracts on a monthly
basis to RWE NPower PLC and Hess Energy Gas Power (UK) Ltd.
The Corporation assesses partners' credit worthiness before entering into
farm-in or joint venture agreements. In the past, the Corporation has not
experienced credit loss in the collection of accounts receivable. As the
Corporation's exploration, drilling and development activities expand with
existing and new joint venture partners, the Corporation will assess and
continuously update its management of associated credit risk and related
procedures.
The Corporation regularly monitors all customer receivable balances outstanding
in excess of 90 days. As at June 30, 2011 all of accounts receivables are
current, being defined as less than 90 days. The Corporation has no allowance
for doubtful accounts as at June 30, 2011 (December 31, 2010 $Nil).
The Corporation may be exposed to certain losses in the event that
counterparties to derivative financial instruments are unable to meet the terms
of the contracts. The Corporation's exposure is limited to those counterparties
holding derivative contracts with positive fair values at the reporting date. As
at June 30, 2011, exposure is $2.9 million (December 31, 2010: $Nil).
The Corporation also has credit risk arising from cash and cash equivalents held
with banks and financial institutions. The maximum credit exposure associated
with financial assets is the carrying values.
v) Liquidity Risk
Liquidity risk includes the risk that as a result of its operational liquidity
requirements the Corporation will not have sufficient funds to settle a
transaction on the due date. The Corporation manages liquidity risk by
maintaining adequate cash reserves, banking facilities, and by considering
medium and future requirements by continuously monitoring forecast and actual
cash flows. The Corporation considers the maturity profiles of its financial
assets and liabilities. As at June 30, 2011, substantially all accounts payable
are current.
The following table shows the timing of cash outflows relating to trade and
other payables.
Within 1 to 5
1 year years
US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities 102,959 -
Other long term liabilities - 2,726
----------------------------------------------------------------------------
----------------------------------------------------------------------------
102,959 2,726
20.DERIVATIVE FINANCIAL INSTRUMENTS
June 30 December 31 January 1
2011 2010 2010
US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil put premiums 2,932 - -
Embedded derivative (3,509) (4,378) -
Foreign exchange forward
contract - - 685
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(577) (4,378) 685
In Q1 2011 the Corporation entered into a 'put' option to sell 804,500 barrels
of the Corporation's 2011 forecast production at $105 / bbl. This is recognized
at its fair value in the financial statements. Fair value represents the market
price for the instrument, measured as at June 30, 2011.
In Q2 2011 the Corporation entered into a further 'put' option to sell 300,000
barrels of the Corporation's 2011 forecast production at $115 / bbl. This is
recognized at its fair value in the financial statements. Fair value represents
the market price for the instrument, measured as at June 30, 2011.
In Q4 2010, the Corporation acquired an embedded derivative within an Anglia gas
sales contract. This is recognized at its fair value in the financial
statements. Fair value represents the difference between the contract price and
the period end market price for the contracted volumes.
21. FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES
Financial instruments of the Corporation consist mainly of cash and cash
equivalents, receivables, payables, loans and financial derivative contracts,
all of which are included in these financial statements. At June 30, 2010, the
classification of financial instruments and the carrying amounts reported on the
balance sheet and their estimated fair values are as follows:
June 30, 2011 December 31, 2010
US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Carrying Fair Carrying Fair
Classification Amount Value Amount Value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash and cash equivalents
(Held for trading) 168,970 168,970 195,581 195,581
Restricted cash 7,596 7,596 6,308 6,308
Derivative financial
instruments (Held for
trading) 2,932 2,932 - -
Accounts receivable (Loans
and Receivables) 100,168 100,168 93,434 93,434
Deposits 256 256 248 248
Loan fees - current 261 261 286 286
Loan fees - non-current 391 391 521 521
Commodity hedge (Held for
trading) - - 349 349
Contingent consideration 10,976 10,976 12,976 12,976
Derivative financial
instruments (Held for
trading) 3,509 3,509 4,378 4,378
Other long term liabilities 2,726 2,726 2,872 2,872
Accounts payable (Other
financial liabilities) 102,959 102,959 75,564 75,564
22. RELATED PARTY TRANSACTIONS
Director of the Corporation is a partner of Burstall Winger LLP who acts as
counsel for the Corporation. The amount of fees paid to Burstall Winger LLP in
the three and six months ended June 30, 2011 was $0.1 million (June 30, 2010 -
$0.1 million June 30, 2010 YTD - $0.1 million). The balance outstanding at June
30, 2011 was $Nil (June 30, 2010 - $Nil).
23. SEASONALITY
The effect of seasonality on the Corporation's financial results for any
individual quarter is not material.
24. TRANSITION TO IFRS
These are the Corporation's second condensed interim consolidated financial
statements to be prepared in accordance with IFRS.
The accounting policies in Note 3 have been applied in preparing the condensed
interim consolidated financial statements for the three and six months ended
June 30, 2011, the comparative information for the three and six months ended
June 30, 2010, the balance sheet for the year ended December 31, 2010 and the
preparation of an opening IFRS balance sheet on the transition date, January 1,
2010.
An explanation of how the transition from Canadian GAAP to IFRS has affected the
Corporation's financial position, financial performance and cash flows is set
out below.
IFRS 1 Exemptions
IFRS 1 First-Time Adoption of International Financial Reporting Standards allows
first-time adopters certain exemptions from retrospective application of certain
IFRS.
The Corporation has applied the following exemptions:
Oil and gas assets in property, plant and equipment were recognized and measured
on a full cost basis in accordance with Canadian GAAP. The Corporation has
elected to measure its properties at the amount determined under Canadian GAAP
as at January 1, 2010. Costs included in the full cost pool on January 1, 2010
were allocated on a pro rata basis to the underlying assets on the basis of
pre-tax net present values using proved and probable reserves as at January 1,
2010.
Associated decommissioning assets were also measured at their carrying value
under Canadian GAAP while all decommissioning liabilities were measured using a
risk free rate, with a corresponding adjustment recorded to opening retained
earnings.
IFRS 3 Business Combinations has not been applied to acquisitions of
subsidiaries or interests in joint ventures that occurred before January 1,
2010.
IFRS 2 Share-Based Payments has not been applied to equity awards that were
granted prior to November 7, 2002, nor those that were granted after November 7,
2002 and vested prior to January 1, 2010.
The Corporation has elected to apply IAS 23 Borrowing Costs with an effective
date of January 1, 2010 which requires mandatory capitalization of borrowing
costs directly attributable to the acquisition, construction or production of
qualifying assets. No borrowing costs previously capitalized in accordance with
Canadian GAAP have been derecognized.
Reconciliations from Canadian GAAP to IFRS
In preparing the interim condensed Consolidated Financial Statements, the
Corporation has adjusted amounts reported previously in its Consolidated
Financial Statements prepared under Canadian GAAP. The following reconciliations
present the adjustments made to the Corporation's financial position, financial
performance and cashflow (as required by IFRS 1), along with explanatory notes.
Reconciliation of equity as at January 1, 2010 (date of transition to IFRS)
CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents 29,886 - 29,886
Restricted cash 5,224 - 5,224
Accounts receivable 67,166 - 67,166
Deposits, prepaid expenses and other 352 - 352
Foreign exchange forward contract 685 - 685
----------------------------------------------------------------------------
103,313 - 103,313
Non current assets
Restricted cash 352 - 352
Exploration and evaluation assets
(note a) - 15,500 15,500
Property, plant & equipment (notes a,
b, c) 205,475 (15,500) 189,975
----------------------------------------------------------------------------
205,827 - 205,827
Total assets 309,140 - 309,140
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables 43,613 - 43,613
Commodity hedge 397 - 397
----------------------------------------------------------------------------
44,010 - 44,010
Non current liabilities
Long term liability 2,718 - 2,718
Decommissioning liabilities (note d) 7,956 795 8,751
Contingent consideration (note e) - 6,933 6,933
----------------------------------------------------------------------------
10,674 7,728 18,402
----------------------------------------------------------------------------
Net Assets 254,456 (7,728) 246,728
----------------------------------------------------------------------------
Equity attributable to equity holders
Share capital 277,075 - 277,075
Contributed surplus (note f) 7,812 (952) 6,860
Retained earnings / (deficit) (notes
d and e) (30,431) (6,776) (37,207)
----------------------------------------------------------------------------
Shareholders' Equity 254,456 (7,728) 246,728
----------------------------------------------------------------------------
Reconciliation of equity as at June
30, 2010
CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents 51,010 - 51,010
Accounts receivable 79,560 - 79,560
Deposits, prepaid expenses and other 506 - 506
----------------------------------------------------------------------------
131,076 - 131,076
Non current assets
Restricted cash 335 - 335
Exploration and evaluation assets
(note a) - 17,624 17,624
Property, plant & equipment (notes a,
b, c) 208,570 (1,564) 207,006
----------------------------------------------------------------------------
208,905 16,060 224,965
Total assets 339,981 16,060 356,041
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables 58,589 - 58,589
----------------------------------------------------------------------------
58,589 - 58,589
Non current liabilities
Long term liability 2,539 - 2,539
Decommissioning liabilities (note d) 6,098 2,380 8,478
Contingent consideration (note e) - 10,976 10,976
Derivative financial instruments - - -
----------------------------------------------------------------------------
8,637 13,356 21,993
----------------------------------------------------------------------------
Net Assets 272,755 2,704 275,459
----------------------------------------------------------------------------
Equity attributable to equity holders
Share capital 277,307 - 277,307
Contributed surplus (note f) 10,012 (862) 9,150
Retained earnings / (deficit) (notes
b, d, e and f) (14,564) 3,566 (10,998)
----------------------------------------------------------------------------
Shareholders' Equity 272,755 2,704 275,459
----------------------------------------------------------------------------
Reconciliation of equity as at
December 31, 2010
CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
--------------------------------------------------------------------------
--------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents 195,581 - 195,581
Restricted cash 6,308 - 6,308
Accounts receivable 93,434 - 93,434
Deposits, prepaid expenses and other 12,341 - 12,341
Deferred tax asset (note g) 16,074 (12,329) 3,745
--------------------------------------------------------------------------
323,738 (12,329) 311,409
Non current assets
Exploration and evaluation assets
(note a) - 17,522 17,522
Property, plant & equipment (notes a,
b, c) 238,113 11,855 249,968
--------------------------------------------------------------------------
238,113 29,377 267,490
-
Total assets 561,851 17,048 578,899
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables 75,564 - 75,564
Commodity hedge 349 349
--------------------------------------------------------------------------
75,913 - 75,913
Non current liabilities
Long term liability 2,872 - 2,872
Decommissioning liabilities (note d) 20,868 2,784 23,652
Contingent consideration (e) - 12,976 12,976
Derivative financial instruments 4,378 - 4,378
--------------------------------------------------------------------------
28,118 15,760 43,878
--------------------------------------------------------------------------
Net Assets 457,820 1,288 459,108
--------------------------------------------------------------------------
Equity attributable to equity holders
Share capital 422,373 - 422,373
Contributed surplus (note f) 11,530 (103) 11,427
Warrants issued 311 - 311
Retained earnings (notes b, d, e and
f) 23,606 1,391 24,997
--------------------------------------------------------------------------
Shareholders' Equity 457,820 1,288 459,108
--------------------------------------------------------------------------
Reconciliation of total comprehensive income for the six months ended June
30, 2010
CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
Revenue 64,896 - 64,896
Cost of sales (note b) (42,236) 14,352 (27,884)
----------------------------------------------------------------------------
Gross Profit 22,660 14,352 37,012
Admin expenses (note f) (2,028) (89) (2,117)
----------------------------------------------------------------------------
Operating Profit 20,632 14,263 34,895
Foreign exchange (1,938) - (1,938)
Gain / (loss) on financial
instruments (note e) (2,560) (4,044) (6,604)
----------------------------------------------------------------------------
Profit on ordinary activities Before
Interest and Tax 16,134 10,219 26,353
Finance costs (note d) (272) 121 (152)
Interest income 5 - 5
----------------------------------------------------------------------------
Profit Before Tax 15,867 10,340 26,206
Taxation - - -
----------------------------------------------------------------------------
Profit After Tax 15,867 10,340 26,206
Reconciliation of total comprehensive income for the three months ended
June 30, 2010
CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
Revenue 34,129 - 34,129
Cost of sales (note b) (22,453) 7,647 (14,806)
----------------------------------------------------------------------------
Gross Profit 11,676 7,647 19,323
Admin expenses (note f) (100) (60) (160)
----------------------------------------------------------------------------
Operating Profit 11,576 7,587 19,163
Foreign exchange (362) - (362)
Gain / (loss) on financial
instruments (note e) (587) (4,044) (4,631)
----------------------------------------------------------------------------
Profit on ordinary activities Before
Interest and Tax 10,627 3,543 14,170
Finance costs (note d) (114) 39 (75)
Interest income 3 - 3
----------------------------------------------------------------------------
Profit Before Tax 10,516 3,582 14,098
Taxation - - -
----------------------------------------------------------------------------
Profit After Tax 10,516 3,582 14,098
Reconciliation of total comprehensive income for the year ended December
31, 2010
CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
Revenue 135,121 - 135,121
Cost of sales (note b) (87,307) 26,257 (61,050)
----------------------------------------------------------------------------
Gross Profit 47,814 26,257 74,071
Exploration and evaluation (note a) - (1,119) (1,119)
Admin expenses (note f) (4,620) (848) (5,468)
----------------------------------------------------------------------------
Operating Profit 43,194 24,290 67,484
Foreign exchange 818 - 818
Revaluation of financial instruments
(note e) (5,268) (4,044) (9,312)
----------------------------------------------------------------------------
Profit on ordinary activities Before
Interest and Tax 38,744 20,246 58,990
Finance costs (note d) (814) 249 (565)
Interest income 113 113
----------------------------------------------------------------------------
Profit Before Tax 38,043 20,495 58,538
Taxation (note g) 15,994 (12,329) 3,665
----------------------------------------------------------------------------
Profit After Tax 54,037 8,166 62,203
Adjustments to the statement of cash flows
All IFRS transition adjustments were non-cash items therefore the transition
from Canadian GAAP to IFRS had no impact on cash flows generated by the
Corporation, nor on the categorisation cash flows between operating activities,
investing activities or financing activities.
Notes to the reconciliations of equity and total comprehensive income from
Canadian GAAP to IFRS
(a) Exploration and evaluation assets
Under IFRS 6, as at January 1, 2010, management has deemed exploration and
evaluation assets to be $15.5 million, representing the unproved properties
balance under previous GAAP. This resulted in reclassification of $15.5 million
from property, plant and equipment to exploration and evaluation assets.
(b) Depletion, depreciation and amortization
Under Canadian GAAP, development costs were depleted on a unit of production
basis based on the proved reserves of the cost pool. Under IFRS, the Corporation
depletes development costs at a field level on a unit of production basis, and
has elected to deplete these over the proved and probable reserves of the
assets. For the six months ended June 30, 2010, the Corporation has recognized
depletion, depreciation and amortization expense of $9.7 million under IFRS when
compared to $24.1 million under Canadian GAAP. For the three months ended June
30, 2010, the Corporation has recognized depletion, depreciation and
amortization expense of $5.3 million under IFRS when compared to $13.0 million
under Canadian GAAP. For the year ended December 31, 2010, the Corporation has
recognized depletion, depreciation and amortization expense of $23.2 million
under IFRS when compared to $49.5 million under Canadian GAAP.
(c) Deemed cost allocation
The most significant changes to the Corporation's accounting policies relate to
the accounting for upstream costs. Under Canadian GAAP, the Corporation followed
the full cost method of accounting for oil and gas assets whereby all costs of
acquisition, exploration for and development of oil and gas reserves were
capitalized and accumulated within one cost centre (UK North Sea). Costs
accumulated were depleted using the unit-of-production method based on proved
reserves determined using estimated future prices and costs.
The Corporation has elected to apply the IFRS 1 exemption for its Canadian oil
and gas assets whereby development costs as at January 1, 2010 were deemed to be
$189.5 million, being the full cost proved PP&E net book value. As stated above
exploration and evaluation costs as at January 1, 2010 were deemed to be $15.5m,
being the unproved properties balance under Canadian GAAP.
(d) Decommissioning liabilities
Under Canadian GAAP, similar to IFRS, decommissioning liabilities were
calculated based on the Corporation's best estimate of the expenditure required
to settle the present obligation at the end of the reporting period or to
transfer it to a third party at that time. The liability is however required to
be remeasured at the end of each period including changes in discount rates. As
stated above, the Corporation utilized an exemption under IFRS for measurement
of oil and gas assets. This exemption has a consequential impact to the
measurement of the oil and gas assets' decommissioning liabilities upon
transition to IFRS, whereby the differences arising from the remeasurement of
the decommissioning liabilities are taken directly to retained earnings rather
than adjusting the carrying amount of the underlying oil and gas assets. This
resulted in an increase in decommissioning liabilities and a decrease to
retained earnings of $0.8 million as at January 1, 2010.
Subsequent remeasurements and differences in accretion were recorded in
property, plant and equipment and finance costs respectively. For the six months
ended June 30, 2010, the Corporation recorded accretion of $0.4 million compared
to $0.5 million under CGAAP. For the three months ended June 30, 2010, the
Corporation recorded accretion of $0.2 million compared to $0.3 million under
CGAAP. As at December 31, 2010, the Corporation remeasured the decommissioning
liabilities resulting in an increase to decommissioning liabilities of $2.7
million. For the 12 months ended December 31, 2010, the Corporation reduced
recorded accretion by $0.2 million.
Associated decommissioning assets were measured at their carrying value under
Canadian GAAP while all decommissioning liabilities were measured using a risk
free rate, with a corresponding adjustment recorded to opening retained
earnings.
(e) Contingent consideration
Under IFRS, contingent consideration is required to be accounted for as a
financial liability and measured at fair value at the date of acquisition with
any subsequent remeasurements recognised either in profit or loss or in other
comprehensive income in accordance with IAS 39.
On transition, as at January 1, 2010, the Corporation recognized a liability of
$6.9 million and a decrease in retained earnings relating to a contingent
consideration on the Stella acquisition.
For the six months ended June 30, 2010, the Corporation recognized a further $4
million of contingent consideration, being $4m adjustment to the Stella
acquisition (opposite side recognised in the income statement).
For the year ended December 31, 2010, the Corporation recognized a further $2
million of liability relating to the GDF assets acquisition (opposite side
recognised in PP&E).
(f) Share based payments
Under Canadian GAAP, similar to IFRS, the expense relating to the Corporation's
equity-settled stock based compensation plans was recorded at fair value using
the Black-Scholes option pricing model.
Some of the required valuation inputs however differ according to each GAAP. As
stated above, on transition, as at January 1, 2010, the Corporation recognized a
decrease in contributed surplus with an offsetting increase in retained earnings
of $1 million.
(g) Deferred tax
Deferred tax has been adjusted to reflect the tax effect arising from the
differences between IFRS and Canadian GAAP. Upon transition to IFRS, similar to
Canadian GAAP, no deferred tax asset was recognized as realization of the asset
was not considered to be more likely than not. For the twelve months ended
December 31, 2010, the application of the IFRS adjustments as discussed in a) to
f) above resulted in the recognition of a reduced deferred tax asset of $3.7
million and a $12.3 million decrease to the Company's deferred tax credit.
25. SUBSEQUENT EVENTS
On August 25, 2011, the Company completed the acquisition of a 28.46%
non-operated interest in the Cook oil field from Hess Limited ("Hess") for an
adjusted consideration of $57 million and the transfer from Ithaca to Hess of a
10% interest in each of exploration blocks 42/25b, 43/16a and 43/21c in the
Southern North Sea.
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