NOT FOR DISTRIBUTION TO U.S. NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE
UNITED STATES
Ithaca Energy Inc. ("Ithaca" or "the Company") (AIM:IAE)(TSX VENTURE:IAE)
announces its financial results for the three months ended March 31, 2011.
HIGHLIGHTS - For the three months ended March 31, 2011
Financial
-- Profit before tax US$13.0 million (Q1 2010: US$12.1 million)
-- Cashflow from Operations of US$22.1 million (Q1 2010: US$19.6 million)
-- Cash US$198.9 million, inclusive of US$7.6 million restricted cash (Q4
2010: US$201.9 million)
-- Undrawn US$140 million senior debt facility
-- Tax losses of US$221 million (Q4 2010 $216 million)
-- Results and comparatives are now reported under International Financial
Reporting Standards ("IFRS")
Operational
-- Sales averaged 3,493 barrels of oil equivalent per day ("boepd") net to
Ithaca over the period to March 31.
-- Successfully completed the drilling of the water injection well for the
Athena field and commenced drilling of the final production well
(drilling was successfully concluded post period end)
-- Significant progress made on modification and recertification works of
the Athena FPSO vessel "BW Athena" following arrival in a Dubai
shipyard. The works are on schedule and anticipated to be completed in
Q3 2011 ahead of first production in Q4 2011.
Corporate
-- Lawrie Payne, Non-Executive Chairman of the Board, retired from the
Board of Directors. Jack C. Lee assumed the position of Non-Executive
Chairman of the Board.
SIGNIFICANT POST Q1 EVENTS
-- 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 is expected to
complete in Q3 2011 with an effective date of January 1, 2011. Sproule
International Limited subsequently confirmed management's estimate of
Cook Proved plus Probable ("2P") reserves of 5.75 mmboe.
-- Signed an earn in agreement with Challenger Minerals (North Sea) Limited
("CMI") 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, CMI will pay 40% of gross Hurricane initial
appraisal well costs in exchange for a 31% equity interest in Block
29/10b. In addition, upon successful appraisal, CMI will pay 40% of
gross costs of a drill stem well test of any sidetrack.
-- The Electrical Submersible Pump ("ESP") units in the Jacky production
well, J01, encountered faults, requiring the ESP units to be replaced. A
rig based workover ESP replacement and reperforation operation was
undertaken which has recently been completed and J01 production, under
ESP support, has been reinstated. The Company will report J01 production
rates once production is fully stabilized and the well flow has
completely cleaned up.
-- Drilling of the Jacky J03 well was suspended due to the well
encountering 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 to maximise oil
recovery from the Jacky field.
-- Development drilling on the Athena field was completed with the
conclusion of drilling on the final production well. The rig is
currently in the process of batch completing all five development wells.
First oil is on schedule for Q4 2011 at 22,000 bopd (gross) and the
project remains on budget. The FPSO is in dry dock with modification and
recertification works well advanced. The vessel has been successfully
separated for installation of a turret docking section which has been
welded into the structure amidships.
PRODUCTION UPDATE
As a result of the Jacky well issues highlighted above, average daily production
from existing assets in Q2 2011 is expected to be approximately 2,100 boepd.
With less than 4 days remaining in the quarter no further production update will
be announced ahead of the Q2 Financial Results which are expected to breakeven
or possibly show a small loss for the quarter.
Although Ithaca benefits from the production associated with the Cook
Acquisition from January 1, 2011, the production reported for Q1-2011 and the
forecast for Q2-2011 highlighted above exclude such volumes. Adding anticipated
Cook volumes from January 1, 2011 to that of the existing assets, full year
production is forecast to be approximately 5,000 boepd, with a forecast 2011
exit rate of around 10,000 boepd following first oil from the Athena field.
Looking ahead, the Company expects to update its longer range production
profiles once it has first production from the Athena field, closed the Cook
Acquisition, and submitted its FDP on the Stella development.
Iain McKendrick, CEO, commented,
"Despite the short term set-backs that caused production shortfalls on Jacky in
the first half of the year, Q1 has delivered a strong set of results. With
completion of the Cook acquisition and Athena first oil in the second half of
2011 the vulnerability of the company's production to single well upsets has
been addressed. This reduction of risk concentration will continue as we look to
add further quality production acquisitions. With J01 production now restored,
we look forward with confidence to first oil on Athena following the successful
drilling program and the excellent progress being made elsewhere on the
project."
Notes:
Further details on the above are provided in the Interim Consolidated Financial
Statements and Management's Discussion and Analysis for the three months ended
March 31, 2011, below 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 Energy 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 Energy Inc. 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 Q1 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 MARCH 31, 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 months ended March 31, 2011. The information is
provided as of June 27, 2011. The first 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 March 31, 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
'Operating costs per boe' referred to in this MD&A are 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. Ithaca includes operating costs per barrel data because investors may
use this information to analyze operating performance. The additional
information should not be considered in isolation or as a substitute for
measures of performance prepared in accordance with GAAP. See "Results of
Operations" section for details.
'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 FIRST QUARTER 2011
Ithaca achieved the following highlights during the first three months of 2011.
Financial
-- Profit before tax of $13.0 million (Q1 2010 $12.1 million)
-- Cashflow from operations of $22.1 million (Q1 2010 $19.6 million)
-- Cash of $198.9 million, inclusive of $7.6 million restricted cash (Q4
2010 $201.9 million)
-- Tax losses attributable to upstream oil and gas activities of $221
million (Q4 2010 $216 million)
Profit before tax in Q1 2011 rose compared to the prior year, despite it being a
period of significant issues. This was driven by rising realized average oil
price of $111.19 / bbl ($79.95 / bbl in Q1 2010), income from the Anglia and
Topaz gas fields acquired in December 2010, and foreign exchange gains on
Sterling bank deposits.
The significant capital expenditure program, in combination with the strong
operating cashflow resulted in a cash balance of $198.9 million at March 31,
2011.
Operational
Production
-- Average net sales were 3,493 boe per day (4,193boepd in Q1 2010). Net
sales in the Greater Beatrice Area for Q1 were affected by mechanical
issues with the drilling mud handling system on the Energy Enhancer,
positioning of the Energy Enhancer over the J03 well and the requirement
to retrofit an ESP in the Beatrice Alpha A28 workover well (see below
for further discussion).
Athena
-- In January 2011, the Sedco 704 drilling unit anchored on location over
the Athena field ready to commence campaign to drill a fourth production
well, a water injector well and complete the three existing wells on the
field as producers. Modification and recertification of the FPSO vessel
"BW Athena" continued in a Dubai shipyard with works to re-certify
existing equipment and install new equipment on the FPSO. All work is
anticipated to be completed in Q3 2011 allowing the vessel to return to
UK waters and arrive on location at Athena.
-- In February 2011, the Corporation successfully completed the drilling of
the water injection well. The well exceeded the net reservoir
requirements for water injection to support initial gross production,
showed excellent average porosity across the reservoir section and tests
indicated good fluid mobility in all selected sandstone units tested.
The well was drilled down flank from three successful appraisal wells
and was the first well of the campaign.
-- In March 2011 the Sedco 704 semi submersible drilling unit commenced the
drilling of the final production well. The well was drilled from the
Athena drill centre and was the final well to be drilled. The well was
directionally drilled in the north west of the field and intersected the
top reservoir (Top Scapa A sands). These drilling operations precede
subsea equipment installation and hook-up of the BW Athena FPSO later in
the year.
Jacky
-- In March 2011, the Energy Enhancer jack-up drilling unit commenced
drilling on the second production well, J03. The well was drilled to
access additional reserves and increase production as part of a field
management strategy. The drilling unit was positioned over the Jacky
platform to drill from an existing spare wellbay.
-- Mechanical issues were experienced on the drilling unit causing the
suspension of drilling on the J03 well and an extension to the
suspension of production from the J01 well that was necessary to
complete the 'top hole section' of the J03 well (as is normal practice).
Following successful repair to the drilling mud handling system onboard
the rig and completion of the top hole section, production from the J01
well was reinstated by March 22, with the recommencement of drilling on
the J03 well on the Jacky field on March 29.
Beatrice
-- In April 2011 the workover well A28 was partially completed and was free
flowing at approximately 130 bopd gross (65 bopd net to Ithaca).
Operations have transferred to the workover of the A21 well. On
completion of the A21 well operations will transfer back to A28 to
retrofit a downhole electric submersible pump ("ESP") to support
production.
Corporate
-- In February 2011, Lawrie Payne, Non-Executive Chairman of the Board,
notified the Corporation of his intention to retire from service of the
Corporation and resigned from the Board of Directors effective February
22, 2011. Jack C. Lee succeeded Lawrie Payne as Non-Executive Chairman
effective as of the same date.
-- In March 2011 Gemini Oil & Gas Fund II, L.P. ("Gemini") exercised all
warrants granted by the Corporation in Q3 2010 to acquire 2,500,000
common shares of the Corporation at C$2.25 per share.
-- In March 2011, in order to benefit from the recent rise in oil price,
Ithaca purchased a 'put option' with a floor price of $105 per barrel
for 804,500 barrels of oil for the period March to December 2011. The
put option delivers a minimum price on the specified volume of oil and
leaves the Corporation to benefit from any oil price upside above $105
per barrel.
HIGHLIGHTS SUBSEQUENT TO QUARTER END:
-- In April 2011 the Corporation entered into an agreement to acquire a
28.46% non-operated interest in the Cook oil field and a 7.41% non-
operated interest in the Maclure oil field from Hess Limited ("Hess")
for a consideration of $74.5 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 acquisition of Maclure was subject
to pre-emption within 30 days of notification to other parties in the
Maclure field. The Corporation commissioned Sproule International Ltd
("Sproule") to provide a Reserves Audit Opinion on Cook and Maclure. The
transaction is expected to complete in Q3 2011 with an effective date of
January 1, 2011.
-- In April 2011 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.
-- In April 2011 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 barrels of oil per day ("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)
as measured at the Nigg storage facility. The Corporation continued to
free flow the J01 production well until the J03 well reached the target
reservoir formation, the Beatrice "A" Sand. The Northern Enhancer rig
was then utilised to undertake a workover operation to replace the
failed ESPs in the J01 production well.
-- In April 2011, the Corporation purchased a further put option with a
floor price of $115 per barrel for 300,000 barrels of oil. This put
option also 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.
-- In May 2011, the Corporation was notified that an exercising notice had
been received in relation to the right of pre-emption held by each of
the existing Maclure co-venturers. Subject to completed documentation
being executed by Hess and any pre-empting parties, the interest in the
Maclure field will be removed from the acquisition and the consideration
will be adjusted to $62.5 million such that Ithaca shall acquire a
28.46% non-operated interest in the Cook field only.
-- In May 2011 Sproule completed its Reserves Audit Opinion on the Cook
field. Management's view that the acquisition will increase the
Corporation's remaining Proved plus Probable ("2P") reserves by 5.75
million barrels of oil equivalent ("mmboe") net to Ithaca as at January
1, 2011 was confirmed by Sproule as reasonable. Based on 5.75 mmboe of
2P reserves, the acquisition is priced at $10.87 per boe.
-- In May, 2011 the Corporation announced that the Jacky J03 well has been
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 to
maximise oil recovery from the Jacky field.
-- In May 2011, capital expenditure plans for 2011 were revised showing an
increase from $120 million to $136 million mainly to cover the re-
phasing of long lead items for the Stella project.
-- Following an announcement in December 2010 that North Sea Energy ("NSE")
was seeking to withdraw from investing in 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.
-- In June 2011, 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 at approximately 22,000 barrels of oil
per day ("bopd") (gross), approx. 5,000 bopd (net to Ithaca). The
drilling rig, Sedco 704, is now proceeding to run completion equipment
and perforate the well, the three existing suspended production wells
and the water injection well.
-- In June 2011, ongoing modification and recertification work on the FPSO
BW Athena is well advanced. The vessel has been successfully separated
for installation of a turret docking section which is currently being
welded into the structure amidships. The vessel will be extended by
approximately 65 feet. The FPSO will return to UK waters for 'hook up'
to the turret mooring buoy by the end of Q3 2011.
-- In June 2011, the rig based workover ESP replacement and reperforation
operation was successfully completed and J01 production, under ESP
support, has been reinstated. The Company will report J01 production
rates once production is fully stabilized and the well flow has
completely cleaned up.
RESULTS OF OPERATIONS
Sales revenue has increased in Q1 2011 to $31.1 million (Q1 2010 $30.8 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 4,193 bopd in Q1 2010 to 2,511 bopd for Q1 2011
predominantly due to the workover and drilling activities experienced on
Beatrice and Jacky noted above. The Corporation has benefited from an increase
in average realized oil prices from $79.95 / bbl in Q1 2010 to $111.19 / bbl,
due to an increase in the 'spot' Brent oil price in the year.
The addition of gas production due to the acquisition of producing gas assets
from GDF SUEZ E&P UK Ltd in December 2010 ("GdF Acquisition") also contributed
to increased revenue in Q1 2011 (no gas production in Q1 2010). The combined
production from the Anglia and Topaz fields contributed over $4.2 million to
revenue through 981 boepd of allocated gas.
Cost of Sales has increased in Q1 2011 to $17.2 million (Q1 2010 $13.1 million)
due to an increase in both operating costs and DD&A expense.
Operating costs have increased in Q1 2011 to $10.2 million (Q1 2010 $8.7
million) due to the addition of Anglia and Topaz operating costs acquired in
December 2010. Operating costs for the Great Beatrice Area have remained
consistent in the period.
DD&A expense for the quarter has increased in Q1 2011 to $7.0 million (Q1 2010
$4.4 million). Although oil production has decreased year on year, an increase
in expense has been recorded due to the increase in the depletion rate per
barrel partly due to the addition of higher DD&A from the Anglia and Topaz gas
assets.
A credit of $0.5 million has been recorded in the income statement relating to
Exploration and Evaluation expenses for the three months ended March 31, 2011
(Q1 2010 $Nil). The credit relates to the expensing of certain prospects
declared non-commercial 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.
Administrative expenses have decreased in Q1 2011 to $1.0 million (Q1 2010 $2.0
million). Tight cost control combined with increased capitalization of general &
administrative expenses and stock based compensation costs associated with
higher levels of project work has delivered the reduction in costs charged to
the income statement.
Foreign exchange gains / losses increased $3.7 million to an overall gain of
$2.1 million in the three months ended March 31, 2011 (Q1 2010 $1.6 million
loss). The gain in Q1 2011 was caused by a increase in the average USD : GBP
exchange rate 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 March 31, 2010.
The Corporation recorded a $2.3 million loss on financial instruments for the
three months ended March 31, 2011 (Q1 2010: $2.0 million loss). $2.1 million of
the loss resulted from the revaluation of the oil 'Put Option' that was
purchased in the period due to movements in forecast oil prices. The remainder
of the movement was made up of a $0.1 million loss on the oil hedges taken out
at the end of 2010 and $0.1 million of revaluations of other financial
instruments.
A deferred tax charge of $6.4 million was recognized in the three months ended
March 31, 2011 (Q1 2010: $Nil) representing a tax rate of 49%. This rate is a
product of the movements in UK Corporation Tax rates to 62% and 26% for upstream
oil and gas and non-upstream oil and gas activities respectively. Although the
Corporation has now recorded a deferred tax charge for the first reporting
period, 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 before tax increased to $13.0 million
(Q1 2010 $12.1 million), and Profit after tax has decreased to $6.6 million for
the quarter ended March 31, 2011 (Q1 2010 $12.1 million).
SUMMARY OF QUARTERLY RESULTS
The following table provides a summary of quarterly results of the Corporation
for its eight most recently completed quarters:
31/03/ 31/12/ 30/09/ 30/06/ 31/03/ 31/12/ 30/09/ 30/06/
2011 2010 2010 2010 2010 2009(i) 2009(i) 2009(i)
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
----------------------------------------------------------------------------
Revenue 31,050 34,260 35,965 34,129 30,767 39,676 37,395 29,903
Profit
after tax 6,593 17,922 18,073 14,010 12,108 17,488 (1,145) 3,780
----------------------------------------------------------------------------
Earnings per share
Basic 0.03 0.07 0.08 0.09 0.07 0.11 (0.01) 0.02
Diluted 0.03 0.07 0.08 0.08 0.07 0.11 (0.01) 0.02
----------------------------------------------------------------------------
Selected other information
Profit
before
tax 13,037 14,257 18,154 14,010 12,108 17,488 (1,145) 3,780
(i) Comparative figures for 2009 have been reported under Canadian GAAP
The most significant factor to have affected the Corporation's results during
the above periods is fluctuation in underlying commodity prices. 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 US Dollar: British Pounds Sterling exchange rate.
LIQUIDITY AND CAPITAL RESOURCES
As at March 31, 2011, Ithaca had working capital of $234.7 million including a
free cash balance of $191.3 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 March 31, 2011 there was a cash outflow from
operating, investing and financing activities of $4.2 million (Q1 2010 outflow
of $9.8 million). The net outflow was due to positive cash flows from operating
activities of $27.8 million; a decrease in cashflows from investing activities
of $33.3 million due to investment in fixed assets and movements in working
capital, and positive cash flows from financing activities of $0.6 million, due
to the proceeds from the exercise of the Gemini warrants and share options,
offset by movements in restricted cash and the purchase of the put option for
804,500 barrels at $105 / barrel. The fixed asset investment in the quarter
predominantly related to capital expenditure on the development of Athena, the
continuing hydraulic workover program on Beatrice Alpha, and drilling costs on
the Jacky J03 well.
All of the Corporation's current projects are anticipated to be fully funded
through to first production.
COMMITMENTS
The Corporation has the following financial commitments of which the largest
component relates to the Engineering (Athena and Stella projects):
Year ended 2011 2012 2013 2014 Subsequent to 2014
US$'000 US$'000 US$'000 US$'000 US$'000
----------------------------------------------------------------------------
Office lease 192 257 257 257 834
Exploration license fees 876 1,249 1,603 - -
Engineering 17,046 12,266 20,666 12,266 -
----------------------------------------------------------------------------
Total 18,114 13,772 22,526 12,523 834
OUTSTANDING SHARE INFORMATION
As at March 31, 2011, Ithaca had 258,535,295 common shares outstanding along
with 19,798,505 options to employees and directors to acquire common shares.
The total number of options outstanding is inclusive of 260,000 options granted
to employees in the quarter in accordance with the Corporation's stock option
plan. The options were approved by the Board of Directors at a range of prices
from C$1.80 to C$2.69. 200,000 of these options were reserved for issue in Q3
2010 in contemplation of hiring. Each of the options granted may be exercised
for a period of four years from the grant date. One third of the options will
vest at the end of each of the first, second and third years from the effective
date of grant.
As discussed above, on March 3, 2011, Gemini exercised the 2,500,000 warrants to
purchase common shares of the Corporation that were granted in Q3 2010.
As at June 9, 2011, Ithaca had 258,535,295 common shares outstanding along with
19,798,505 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. All leases have been treated as operating leases whereby
the lease payments are included in cost of sales or administrative expenses
depending on the nature of the lease. No asset or liability value has been
assigned to these leases on the balance sheet as at March 31, 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
Q1 2011 was $0.1 million (Q1 2010 - $Nil). 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 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 March 31, 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 International Financial Reporting
Standards ("IFRS") using a transition date of January 1, 2010. The financial
statements for the three months ended March 31, 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 March 31, 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, including production rates in respect to the workover
operation to replace the failed ESPs in the J01 production well at the
Corporation's Jacky well;
-- 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.
Ithaca Energy Inc. Q1 2011 Financial Statements
Q1 2011 CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Statement of Income
For the three months ended March 31, 2011 and 2010
(unaudited)
2011 2010
Note US$'000 US$'000
---------------------------------------------------------------------------
Revenue 4 31,050 30,767
Cost of Sales 6 (17,218) (13,078)
---------------------------------------------------------------------------
Gross Profit 13,832 17,689
Exploration and evaluation expenses 8 519 -
Administrative expenses 5 (1,060) (1,957)
---------------------------------------------------------------------------
Operating Profit 13,291 15,732
Foreign exchange 2,135 (1,576)
Gain / (Loss) on financial instruments 19 (2,287) (1,974)
---------------------------------------------------------------------------
Profit on ordinary activities Before Interest and
Tax 13,139 12,182
Finance costs (259) (76)
Interest income 157 2
---------------------------------------------------------------------------
Profit Before Tax 13,037 12,108
Taxation - Deferred tax 17 (6,426) -
---------------------------------------------------------------------------
Profit After Tax 6,611 12,108
Earnings per share
Basic 16 0.03 0.07
Diluted 16 0.03 0.07
No separate statement of comprehensive income has been prepared as all such
gains and losses have been incorporated in the income statement above.
The accompanying notes are an integral part of the financial statements.
Consolidated Balance Statement of Financial
Position
(unaudited)
March 31 December 31 January 1
2011 2010 2010
Note US$'000 US$'000 US$'000
---------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents 191,334 195,581 29,886
Restricted Cash 7 7,595 6,308 5,224
Accounts receivable 90,159 93,434 67,166
Deposits, prepaid expenses
and other 17,715 12,341 352
Inventory 1,192 - -
Derivative Financial
Instruments 20 2,003 - 685
Deferred Tax Asset - 3,745 -
---------------------------------------------------------------------------
309,998 311,409 103,313
Non current assets
Restricted Cash 7 - - 352
Exploration and evaluation
assets 8 17,254 17,522 15,500
Property, Plant & Equipment 9 266,055 249,968 189,975
---------------------------------------------------------------------------
283,309 267,490 205,827
Total assets 593,307 578,899 309,140
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables 75,312 75,564 43,613
Commodity hedge - 349 397
---------------------------------------------------------------------------
75,312 75,913 44,010
Non current liabilities
Decommissioning liabilities 11 23,556 23,652 8,751
Other long term liabilities 12 2,758 2,872 2,718
Contingent consideration 13 10,976 12,976 6,933
Derivative financial
instruments 20 4,735 4,378 -
Deferred Tax Liability 2,681 - -
---------------------------------------------------------------------------
44,706 43,878 18,402
---------------------------------------------------------------------------
Net assets 473,289 459,108 246,728
---------------------------------------------------------------------------
Equity attributable to
equity holders
Share Capital 14 428,817 422,373 277,075
Contributed surplus 15 12,864 11,427 6,860
Warrants issued 14 - 311 -
Retained Earnings /
(Deficit) 31,608 24,997 (37,207)
---------------------------------------------------------------------------
Shareholders' Equity 473,289 459,108 246,728
---------------------------------------------------------------------------
"John Summers", Director
"Jay Zammit", Director
The accompanying notes are an integral part of the financial statements.
Consolidated Statement of Changes in Equity
(unaudited)
Share Contributed Warrants Retained
Capital Surplus Issued E'ings/(Deficit) Total
US$'000 US$'000 US$'000 US$'000 US$'000
--------------------------------------------------------------------------
Balance, Jan
1 2010 277,075 6,860 - (37,207) 246,728
Stock based
compensation - 1,181 - - 1,181
Options
exercised 99 (47) - - 52
Net income
for the
period - - - 12,108 12,108
--------------------------------------------------------------------------
Balance,
March 31 2010 277,174 7,994 - (25,099) 260,069
--------------------------------------------------------------------------
Balance, Jan
1 2011 422,373 11,427 311 24,997 459,108
Stock based
compensation - 1,585 - - 1,585
Options
exercised 347 (148) - - 199
Warrants
exercised 6,097 - (311) - 5,786
Net income
for the year - - - 6,611 6,611
--------------------------------------------------------------------------
Balance,
March 31 2011 428,817 12,864 - 31,608 473,289
--------------------------------------------------------------------------
The accompanying notes are an integral part of the financial statements
Consolidated Statement of Cash Flow
For the three months ended March 31, 2011 and 2010
(unaudited)
2011 2010
US$'000 US$'000
---------------------------------------------------------------------------
CASH PROVIDED BY (USED IN):
Operating activities
Profit Before Tax 13,037 12,108
Adjustments for:
Depletion, Depreciation and Amortization 6,972 4,389
Exploration and evaluation expenses 1,481 -
Stock based compensation 591 1,181
Loan Fee amortization 78 -
Unrealized (gain) / loss on financial instruments 1,794 1,808
Revaluation of contingent consideration (2,000) -
Accretion 177 72
---------------------------------------------------------------------------
Cashflow from operations 22,130 19,558
---------------------------------------------------------------------------
Movement in working capital 5,629 (14,858)
---------------------------------------------------------------------------
Net cash from operating activities 27,759 4,700
---------------------------------------------------------------------------
Investing activities
Capital expenditure
Oil and gas assets (23,781) (14,566)
Non oil and gas assets (382) (99)
Movement in working capital (9,173) (3,856)
---------------------------------------------------------------------------
Net cash used in investing activities (33,336) (18,521)
---------------------------------------------------------------------------
Financing activities
Proceeds from issuance of shares 5,986 52
(Increase) / Decrease in Restricted Cash (1,287) 5,241
Derivatives (4,063) -
---------------------------------------------------------------------------
Net cash from financing activities 636 5,293
---------------------------------------------------------------------------
Currency translation differences relating to cash and
cash equivalents 694 (1,274)
---------------------------------------------------------------------------
Increase / (decrease) in cash and cash equivalents (4,247) (9,802)
---------------------------------------------------------------------------
Cash and cash equivalents, beginning of period 195,581 29,886
---------------------------------------------------------------------------
Cash and cash equivalents, end of period 191,334 20,084
---------------------------------------------------------------------------
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 22, 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 22 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 June 23, 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 are 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 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 ended March
31
2011 2010
US$'000 US$'000
-----------------------------------------------------------------
Oil Sales 25,133 30,102
Gas Sales 3,922 -
Condensate Sales 321 -
Other Income 1,674 665
-----------------------------------------------------------------
Total 31,050 30,767
5. ADMINISTRATIVE EXPENSES
Three months ended March
31
2011 2010
US$'000 US$'000
-----------------------------------------------------------------
General & administrative 469 776
Stock based compensation 591 1,181
-----------------------------------------------------------------
1,060 1,957
6. COST OF SALES
Three months ended March
31
2011 2010
US$'000 US$'000
-----------------------------------------------------------------
Operating costs 10,246 8,689
Depletion, Depreciation and Amortisation 6,972 4,389
-----------------------------------------------------------------
17,218 13,078
7. RESTRICTED CASH
March 31 Dec 31 Jan 1
2011 2010 2010
US$'000 US$'000 US$'000
---------------------------------------------------------------------------
Decommissioning security 7,239 5,956 -
Cash security - Crown Estate 356 352 352
Cash security - Foreign exchange
contract - - 5,224
---------------------------------------------------------------------------
7,595 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
and Topaz fields.
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
----------------------------------------------------
Cost
At January 1, 2010 15,500
Additions 3,141
Write offs/relinquishments (1,119)
----------------------------------------------------
At December 31, 2010 17,522
Additions 1,213
Write offs/relinquishments (1,481)
----------------------------------------------------
At March 31, 2011 17,254
Following completion of geotechnical evaluation activity, certain licences were
declared unsuccessful and certain prospects were declared non-commercial and
therefore the related expenditures of $1.5 million were expensed in the three
months to March 31, 2011. $2 million of associated contingent consideration
relating to those licences and prospects was also released to the consolidated
statement of income to give a total credit of $0.5 million. See note 13 for
details.
9. PROPERTY, PLANT AND EQUIPMENT
Development &
Production
Oil and Gas Other fixed
Assets assets Total
US$'000 US$'000 US$'000
---------------------------------------------------------------------------
Cost
At January 1, 2010 189,458 1,274 190,732
Additions 82,879 313 83,192
Disposals - - -
Write offs/relinquishments - - -
---------------------------------------------------------------------------
At December 31, 2010 272,337 1,587 273,924
Additions 22,677 382 23,059
Disposals - - -
Write offs/relinquishments - - -
---------------------------------------------------------------------------
At March 31, 2011 295,014 1,969 296,983
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 Quarter (6,885) (87) (6,972)
---------------------------------------------------------------------------
At March 31, 2011 (29,737) (1,191) (30,928)
NBV at January 1, 2010 189,458 517 189,975
NBV at January 1, 2011 249,485 483 249,968
---------------------------------------------------------------------------
NBV at March 31, 2011 265,277 778 266,055
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 have been
incurred in the year ended December 31, 2010 and are being amortized over the
period of the loan (approx $0.2 million amortized in the year ended December 31,
2010).
The Corporation is subject to financial and operating covenants related to the
Facility. Failure to meet the terms of one or more of these covenants may
constitute an event of default as defined in the Facility agreement, potentially
resulting in accelerated repayment of the debt obligations.
The Corporation is in compliance with its financial and operating covenants.
No funds are currently drawn down under the Facility.
11. DECOMMISSIONING LIABILITIES
March 31 Dec 31
2011 2010
US$'000 US$'000
-----------------------------------------------------------------
Balance, beginning of period 23,652 8,751
Additions - 12,772
Accretion 177 283
Revision to estimates (273) 1,846
-----------------------------------------------------------------
Balance, end of period 23,556 23,652
The total future decommissioning liability was calculated by management based on
its net ownership interest in all wells and facilities, estimated costs to
reclaim and abandon wells and facilities and the estimated timing of the costs
to be incurred in future periods. The Corporation uses a risk free rate of 3.3
percent and an inflation rate of 2 percent over the varying lives of the assets
to calculate the present value of the decommissioning liabilities. These costs
are expected to be incurred at various intervals over the next 9 years. The
economic life and the timing of the obligations are dependent on Government
legislation, commodity price and the future production profiles of the
respective production and development facilities. Note that upon the acquisition
of the Beatrice Field in November 2008, the Corporation did not assume the
decommissioning liabilities.
The addition to the liability in 2010 was due to the liabilities assumed as part
of the GDF acquisition.
12. OTHER LONG TERM LIABILITIES March 31 Dec 31
2011 2010
US$'000 US$'000
---------------------------------------------------------------
Balance, beginning of period 2,872 2,718
Revaluation in the period (114) 154
---------------------------------------------------------------
Balance, end of period 2,758 2,872
On completion of the acquisition of the Beatrice Facilities on November 10, 2008
there were 75,000 barrels of oil in an oil storage tank at the Nigg Terminal.
This volume of oil is required to be in the storage tank when the Beatrice
Facilities are re-transferred. This volume of oil is valued at the price on the
forward oil price curve at the expected date of re-transfer and discounted. The
liability is subject to revaluation at each financial period end. The expected
date of re-transfer is likely to be more than three years in the future.
13. CONTINGENT CONSIDERATION
March 31 Dec 31
2011 2010
US$'000 US$'000
---------------------------------------------------------------
Balance, beginning of period 12,976 6,933
Additions - 2,000
Revision to estimates (2,000) 4,043
---------------------------------------------------------------
Balance, end of period 10,976 12,976
The contingent consideration at the end of the period relates to the acquisition
of the Stella field.
The revaluation in the period relates to the reassessment of the Opal and Garnet
prospects which have been determined uncommercial, resulting in a release of the
associated contingent consideration.
14.SHARE CAPITAL
(a) Issued
The issued share capital is as follows:
Issued
Number of
common shares Amount US$'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 245,831 199
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 March 31, 2011 258,535,295 428,817
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 March 31, 2011, 19,798,505 stock options to purchase
common shares were outstanding, having an exercise price range of $0.23 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:
March 31, 2011 December 31, 2010
---------------------------------------------------------------------------
Wt. Avg Wt. Avg
Exercise Price Exercise Price
No. of Options (i) No. of Options (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 (361,667) $2.00 (231,667) $1.28
Exercised (245,831) $0.77 (765,205) $0.33
---------------------------------------------------------------------------
Options 19,798,505 $1.74 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 March 31, 2011
Options Outstanding Options Exercisable
------------------------------------- --------------------------------------
Wt. Avg. Wt. Avg. Wt. Avg. Wt. Avg.
Range of Life Exercise Range of Life Exercise
Exercise No. of Exercise No. of
Price Options (Years) Price(i) Price Options (Years) Price(i)
------------------------------------- --------------------------------------
$3.65 $3.65
(C$3.65) 2,365,000 0.9 $3.65 (C$3.65) 2,331,667 0.9 $3.65
$2.22- $2.22-
$2.86 $2.86
(C$2.25- (C$2.25-
C$3.00) 6,335,000 3.1 $2.25 C$3.00) 1,185,000 0.2 $2.33
$1.49- $1.49-
$1.76 $1.68
(C$1.54- (C$1.54-
C$1.85) 5,411,667 2.6 $1.55 C$1.80) 1,711,664 2.6 $1.53
$0.23- $0.20-
$0.80 $0.81
(C$0.25- (C$0.25-
C$0.87) 5,686,838 2.5 $0.55 C$0.87) 2,411,919 2.6 $0.45
------------------------------------- --------------------------------------
19,798,505 2.6 $1.74 7,640,250 1.7 $1.96
------------------------------------- --------------------------------------
The following is a summary of stock options as at December 31, 2010
Options Outstanding Options Exercisable
------------------------------------- --------------------------------------
Wt. Avg. Wt. Avg. Wt. Avg. Wt. Avg.
Range of Life Exercise Range of Life Exercise
Exercise No. of Exercise No. of
Price Options (Years) Price(i) Price Options (Years) Price(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- $2.29-
$2.86 $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- $1.49-
$1.76 $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- $0.20-
$0.80 $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
------------------------------------- --------------------------------------
(d) Stock based compensation
Options granted are accounted for using the fair value method. The compensation
cost during the three months ended March 31, 2011 for total stock options
granted was $1.6 million (Q1 2010: $1.2 million). $0.6 million was charged
through the income statement for stock based compensation for the three months
ended March 31, 2011, 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 three months
ended For the year ended
March 31, 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 $0.3 million.
15. CONTRIBUTED SURPLUS
March 31, Dec 31, 2010
US$'000 US$'000
---------------------------------------------------------------------------
Balance, beginning of period 11,427 6,860
Stock based compensation cost 1,585 4,840
Transfer to share capital on exercise of options (148) (273)
---------------------------------------------------------------------------
Balance, end of period 12,864 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 ended March
31,
2011 2010
---------------------------------------------------------------------------
Weighted average number of common shares (basic) 256,839,092 162,555,640
Weighted average number of common shares
(diluted) 262,744,370 165,518,118
17. TAXATION
Three months ended March
31,
2011 2010
US$000 US$000
---------------------------------------------------------------------------
Deferred tax 6,426 -
Current corporation tax payable of $18k is related to tax on interest income
from cash held on deposit. No corporation tax is payable in relation to upstream
oil and gas activities.
18. COMMITMENTS
Subsequent
Year ended to
2011 2012 2013 2014 2014
US$'000 US$'000 US$'000 US$'000 US$'000
---------------------------------------------------------------------------
Office lease 192 257 257 257 834
Exploration 876 1,249 1,603 - -
Engineering 19,149 12,266 20,666 12,266 -
---------------------------------------------------------------------------
Total 20,218 13,772 22,526 12,523 834
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 March 31, 2011:
Total
Fair
Level 1 Level 2 Level 3 Value
US$'000 US$'000 US$'000 US$'000
---------------------------------------------------------------------------
Derivative financial instrument
asset - 2,003 - 2,003
Long term liability on Beatrice
acquisition - - (2,758) (2,758)
Contingent Consideration - (10,976) - (10,976)
Derivative financial instrument
liability - (4,735) - (4,735)
---------------------------------------------------------------------------
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 ended March 31,
2011 2010
US$'000 US$'000
---------------------------------------------------------------------------
Unrealized (loss) / gain on foreign exchange
forward contracts - (2,389)
Realized (loss) / gain on foreign exchange
forward contracts - (251)
Revaluation of gas contract (197) -
Revaluation of other long term liability 114 184
Unrealized gain / (loss) on commodity hedges (1,711) 86
Realized (loss) / gain on commodity hedges (493) 396
---------------------------------------------------------------------------
Total (loss) / gain on derivatives (2,287) (1,974)
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 three months ended March 31, 2011.
If the oil price had been lower by $1 per barrel in 2011 then the profit for the
three months to March 31, 2011 would have been lower by $0.3 million.
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 as at March 31, 2011
resulted in an unrealized loss of $2.1 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 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 March 31, 2011 over 99% of accounts receivables are
current, being defined as less than 90 days. The Corporation has no allowance
for doubtful accounts as at March 31, 2010 (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 March 31, 2011, exposure is $2 million (December 31, 2010: $Nil).
The Corporation also has credit risk arising from cash and cash equivalents held
with banks and financial institutions. The maximum credit exposure associated
with financial assets is the carrying values.
v) Liquidity Risk
Liquidity risk includes the risk that as a result of its operational liquidity
requirements the Corporation will not have sufficient funds to settle a
transaction on the due date. The Corporation manages liquidity risk by
maintaining adequate cash reserves, banking facilities, and by considering
medium and future requirements by continuously monitoring forecast and actual
cash flows. The Corporation considers the maturity profiles of its financial
assets and liabilities. As at March 31, 2011, substantially all accounts payable
are current.
The following table shows the timing of cash outflows relating to trade and
other payables.
Within 1 year 1 to 5 years
US$'000 US$'000
--------------------------------------------------------------
Accounts payable and
accrued liabilities 75,312 -
Other long term
liabilities - 2,758
--------------------------------------------------------------
Total 75,312 2,758
20. DERIVATIVE FINANCIAL INSTRUMENTS
March 31 December 31 January 1
2011 2010 2010
US$'000 US$'000 US$'000
--------------------------------------------------------------
Oil put premium 2,003 - -
Embedded Derivative (4,735) (4,378) -
Foreign exchange
forward contract - - 685
In Q1 2011 the Corporation entered into a 'put' option to sell 804,500 barrels
of the Corporation's 2011 forecast production at $105 / bbl. This is recognized
at its fair value in the financial statements. Fair value represents the market
price for the instrument, measured as at March 31, 2011.
In Q4 2010, the Corporation acquired an embedded derivative within an Anglia gas
sales contract. This is recognized at its fair value in the financial
statements. Fair value represents the difference between the contract price and
the period end market price for the contracted volumes.
21. FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES
Financial instruments of the Corporation consist mainly of cash and cash
equivalents, receivables, payables, loans and financial derivative contracts,
all of which are included in these financial statements. At December 31, 2010,
the classification of financial instruments and the carrying amounts reported on
the balance sheet and their estimated fair values are as follows:
March 31, 2011 December 31, 2010
US$'000 US$'000
---------------------------------------------------------------------------
Classification Carrying Carrying
Amount Fair Value Amount Fair Value
---------------------------------------------------------------------------
Cash and cash equivalents
(Held for trading) 191,334 191,334 195,581 195,581
Restricted cash 7,595 7,595 6,308 6,308
Derivative financial
instruments (Held for
trading) 2,003 2,003 - -
Accounts receivable (Loans
and Receivables) 90,159 90,159 93,434 93,434
Deposits 257 257 248 248
Loan fees - current 273 273 286 286
Loan fees - non-current 456 456 521 521
Commodity hedge (Held for
trading) - - 397 397
Contingent consideration 10,976 10,976 12,976 12,976
Derivative financial
instruments (Held for
trading) 4,735 4,735 4,378 4,378
Other long term liabilities 2,758 2,758 2,872 2,872
Accounts payable (Other
financial liabilities) 75,312 75,312 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 quarter ended March 31, 2011 was $0.1 million (March 31, 2010 - $Nil). The
balance outstanding at March 31, 2011 was $Nil (March 31, 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 first 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 first three months ended March
31, 2011, the comparative information for the three months ended March 31, 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 March 31, 2010
CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
---------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents 20,084 - 20,084
Accounts receivable 81,194 - 81,194
Deposits, prepaid expenses and other 4,589 - 4,589
---------------------------------------------------------------------------
105,867 - 105,867
Non current assets
Restricted cash 335 - 335
Exploration and evaluation assets (note a) - 16,087 16,087
Property, Plant & Equipment (notes a, b, c) 208,616 (9,382) 199,234
---------------------------------------------------------------------------
208,951 6,705 215,656
Total assets 314,818 6,705 321,523
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables 43,164 - 43,164
---------------------------------------------------------------------------
43,164 - 43,164
Non current liabilities
Long term liability 2,534 - 2,534
Decommissioning liabilities (note d) 8,110 713 8,823
Contingent consideration (e) - 6,933 6,933
Derivative financial instruments - - -
---------------------------------------------------------------------------
10,644 7,646 18,290
---------------------------------------------------------------------------
Net assets 261,010 (941) 260,069
---------------------------------------------------------------------------
Equity attributable to equity holders
Share Capital 277,174 - 277,174
Contributed surplus (note f) 8,916 (922) 7,993
Retained earnings (notes b, d, e and f) (25,080) (19) (25,099)
---------------------------------------------------------------------------
Shareholders' Equity 261,010 (941) 260,069
---------------------------------------------------------------------------
Reconciliation of equity as at December 31,
2010
CGAAP IFRS Adj IFRS
US$'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
Brought Forward Deficit (notes b, d, e and f) 23,606 1,391 24,997
---------------------------------------------------------------------------
Shareholders' Equity 457,820 1,288 459,107
---------------------------------------------------------------------------
Reconciliation of total comprehensive income for the three months
ended March 31, 2010
CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
Revenue 30,767 - 30,767
Cost of Sales (note b) (19,783) 6,705 (13,078)
---------------------------------------------------------------------------
Gross Profit 10,984 6,705 17,689
Admin expenses (note f) (1,927) (30) (1,956)
---------------------------------------------------------------------------
Operating Profit 9,057 6,675 15,733
Foreign exchange (1,576) - (1,576)
Gain / (Loss) on financial instruments (1,974) - (1,974)
---------------------------------------------------------------------------
Profit on ordinary activities Before Interest
and Tax 5,507 6,675 12,182
Finance costs (note d) (158) 82 (76)
Interest Income 2 - 2
---------------------------------------------------------------------------
Profit Before Tax 5,351 6,757 12,108
Taxation - - -
---------------------------------------------------------------------------
Profit After Tax 5,351 6,757 12,108
Reconciliation of total comprehensive income for the
year ended December 31, 2010
CGAAP IFRS Adj IFRS
US$'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 cashflows 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 three months ended March 31, 2010, the Corporation has
recognized depletion, depreciation and amortization expense of $4.4 million
under IFRS when compared to $11.1 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
$189.5m, 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 three
months ended March 31, 2010, the Corporation recorded accretion of less than
$0.1 million compared to $0.2 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 an decrease in retained earnings relating to a contingent
consideration on the Stella acquisition.
As at December 31, 2010, the Corporation recognized a further $6 million of
contingent consideration, being $4m adjustment to the Stella acquisition
(opposite side recognised in the income statement) and the recognition of $2
million 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
an decrease in contributed surplus with an offset in an 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
In April 2011 the Corporation entered into an agreement to acquire a 28.46%
non-operated interest in the Cook oil field and a 7.41% non-operated interest in
the Maclure oil field from Hess Limited ("Hess") for a consideration of $74.5
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
acquisition of Maclure was subject to pre-emption within 30 days of notification
to other parties in the Maclure field. In May 2011, the Corporation was notified
an exercising notice had been received in relation to the right of pre-emption.
Subject to completed documentation being executed by Hess and any pre-empting
parties, the interest in the Maclure field will be removed from the acquisition
and the consideration will be adjusted to $62.5 million. The transaction is
expected to complete in Q3 2011 with an effective date of January 1, 2011.
In April 2011 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.
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