ABERDEEN, SCOTLAND--(Marketwire - Nov 12, 2012) -
TSX-V:IAE
Not for Distribution to U.S. Newswire Services or for Dissemination in
the United States
Ithaca Energy Inc.
Third Quarter 2012 Financial Results
Ithaca Energy Inc. (TSX: IAE, LSE AIM: IAE) announces its quarterly
financial results for the three months ended September 30, 2012.
HIGHLIGHTS
Financial
* Q3 profit before tax and unrealised gains/losses on financial
instruments of $14.9 million (Q3 2011: $15.6 million) representing an
increase of $10.5 million on Q2 2012 (Q2 2012: $4.4 million)
* Q3 net earnings of $4.9 million including $12.9 million
unrealised loss from financial instruments (Q3 2011: $16.0 million)
resulting in earnings per share of $0.02 (Q3 2011: $0.06)
* Q3 cashflow from operations of $30.1 million (Q3 2011: $18.1
million). Q3 cashflow per share of $0.12 (Q3 2011: $0.07)
* Q3 average realised oil price of $110.26 / bbl (Q3 2011: $111.24
/ bbl) plus an additional realized hedging gain of $2.56 / bbl in the
quarter
* Cash of $77.4 million, inclusive of $20.6 million restricted
cash, with senior debt facility remaining undrawn
* UK tax allowances pool of $387 million representing an increase
of $39 million on Q2 2012 (Q2 2012: $348 million)
Operational & Corporate
* Q3 export production of 5,061 barrels of oil equivalent per day
("boepd") (Q3 2011: 3,602 boepd). This represents an increase of
approximately 28% on the second quarter of 2012, reflecting the first
full quarter's production from the Athena field and a strong
performance from the Beatrice and Jacky fields compensating for the
anticipated reduction in Cook and Broom production during the quarter
due to planned maintenance shutdowns
* Production from the Athena field stabilised at a gross rate of
10,000 to 11,000 barrels of oil per day ("bopd"), 2,250 to 2,475 bopd
net to Ithaca, with the field continuing to produce "dry" oil
* Hurricane appraisal well successfully drilled, identifying
hydrocarbons in two reservoir intervals,with pressure and fluid
samples recovered from both intervals and a drill stem test performed
on the Andrew sand reservoir
* An Engineering, Procurement, Installation and Construction
("EPIC") contract was awarded to Technip UK Limited covering the major
subsea works that are to be conducted on the Greater Stella Area, with
installation of the subsea infrastructure scheduled for 2013
* Entered into further swaps of 503,800 barrels of oil at a
weighted average price of $108.67 and put options, at market price,
for 300,300 barrels of oil at a weighted average oil price floor of
$111.34 / bbl for the period October 2012 to December 2013.
POST QUARTER END EVENTS
* Entered into agreements with Noble Energy Capital Limited to
acquire corporate entities owning non-operated interests in two United
Kingdom ("UK") North Sea producing fields: a 12.885% interest in the
Cook field (increasing the Company's field interest in Cook to
41.345%) and a 14% interest in the MacCulloch field. The total
acquisition consideration is $38.5 million and is to be funded from
the Company's existing cash resources. The two fields are anticipated
to increase the Company's net proved and probable reserves by
approximately 3.4 mmboe based on the effective date of the
transaction of 1 January 2012.
* Closure of oversubscribed syndication of $430 million debt facility
with BNP Paribas and six other leading international banks working
in the oil and gas sector
* Offered two Blocks by the Department of Energy and Climate
Change in the 27th UK Licence Round - Block 29/5e in the vicinity of
the Company's existing Greater Stella Area ("GSA") interests and Block
15/17b in the Outer Moray Firth
* The Company has issued today a full update on the progress made on
the Greater Stella Area development.
Notes:
Unrealised gains/losses on financial instruments are non-cash mark to
market movements on derivative instruments that account for the fair
value of an asset or liability based on the current market price using
quoted market prices when available, or industry accepted third-party
models and valuation methodologies that utilise observable market data.
Further details on the above are provided in the Interim Consolidated
Financial Statements and Management's Discussion and Analysis for the
three and nine months ended September 30, 2012, which have been filed
with securities regulatory authorities in Canada. These documents are
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, John Horsburgh, BSc (Hons)
Geophysics (Edinburgh), MSc Petroleum Geology (Aberdeen) and Subsurface
Manager at Ithaca is the qualified person that has reviewed the
technical information contained in this press release. Mr Horsburgh has
over 15 years operating experience in the upstream oil industry.
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. Given the value ratio
based on the current price of crude oil as compared to natural gas is
significantly different from the energy equivalency of 6 Mcf: 1 bbl,
utilizing a conversion ratio at 6 Mcf: 1 bbl may be misleading as an
indication of value.
Enquiries:
Ithaca Energy Inc.
Iain McKendrick, CEO imckendrick@ithacaenergy.com +44 (0) 1224 650 261
Graham Forbes, CFO gforbes@ithacaenergy.com +44 (0) 1224 652 151
NOMAD and Joint Broker: Cenkos Securities plc
Jon Fitzpatrick jfitzpatrick@cenkos.com +44 (0) 207 397 8900
Ken Fleming kfleming@cenkos.com +44 (0) 131 220 6939
Joint Broker: RBC Capital Markets
Tim Chapman tim.chapman@rbccm.com +44 (0) 207 653 4641
Matthew Coakes matthew.coakes@rbccm.com +44 (0) 207 653 4871
Public Relations: FTI Consulting
Billy Clegg billy.clegg@fticonsulting.com +44 (0) 207 269 7157
Edward Westropp edward.westropp@fticonsulting.com +44 (0) 207 269 7230
Georgia Mann georgia.mann@fticonsulting.com +44 (0) 207 269 7212
About Ithaca Energy:
Ithaca Energy Inc. (TSX: IAE, LSE AIM: IAE) and its wholly owned
subsidiary Ithaca Energy (UK) Limited ("Ithaca" or "the Company"), is
an oil and gas operator focused on production, appraisal and
development activities on the United Kingdom Continental Shelf. 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
Reader Advisory
Forward-looking statements
This news release contains certain forward looking statements. The
reader is cautioned that all such forward looking statements involve
substantial risks and uncertainties and the assumptions used in their
preparation may not prove to be correct. Ithaca's actual results could
differ materially from those expressed in, or implied by, these forward
looking statements and accordingly, the forward looking statements are
qualified by reference to these cautionary statements. The forward
looking statements contained herein are made as at the date of this
news release. Ithaca undertakes no obligation to update or publicly
revise forward looking statements or information unless so required by
applicable securities laws.
TSX notifications
The TSX accepts no responsibility for the adequacy or accuracy of this
release.
Cenkos Securities plc, which is authorised and regulated in the United
Kingdom by the Financial Services Authority under FSA number 416932, is
acting exclusively as Nominated Adviser and Joint Broker to the Company
and is not acting for or advising any other person and accordingly will
not be responsible to any person other than the Company for providing
advice in relation to the contents of this announcement. Neither Cenkos
Securities plc nor any of its affiliates owes or accepts any duty,
liability or responsibility whatsoever (whether direct or indirect,
whether in contract, in tort, under statute or otherwise) to any person
who is not a customer of Cenkos Securities plc in connection with this
announcement, any statement contained herein or otherwise.
This announcement is not intended to, and does not, constitute or form
part of any offer, invitation or the solicitation of an offer to
purchase, otherwise acquire, subscribe for, sell or otherwise dispose
of, any securities whether pursuant to this announcement or otherwise.
ITHACA ENERGY INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS
FOR THE QUARTER ENDED SEPTEMBER 30, 2012
The following is management's discussion and analysis ("MD&A") of the
operating and financial results of Ithaca Energy Inc. (the
"Corporation" or "Ithaca" or the "Company") for the three and nine
months ended September 30, 2012. The information is provided as of
November 9, 2012. The third quarter 2012 results have been compared to
the results of the comparative period in 2011. This MD&A should be read
in conjunction with the Corporation's unaudited consolidated financial
statements as at September 30, 2012 and with the Corporation's audited
consolidated financial statements as at December 31, 2011 together with
the accompanying notes, MD&A and Annual Information Form ("AIF") for
the 2011 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.
BUSINESS OF THE CORPORATION
Ithaca is an oil and gas company focused on production, appraisal, and
development activities in the United Kingdom's Continental Shelf
("UKCS").
Ithaca's strategy is to:
* Fast track, appraise and develop oil and gas fields
* Acquire producing fields or undeveloped discoveries that:
o are not material for larger companies
o need technical or financial investment
o no longer fit with an existing company's strategy and business
model
* Use tried and tested development and production technologies
* Employ in-house technical excellence to generate development and
acquisition opportunities
* Participate in licensing rounds to gain acreage positions around
its core assets
* Lever its commercial and operator capability to establish solid
oil and gas field positions
* Prioritize capital investment to accretive projects with early
production and significant cash flow
The Corporation's common shares are traded on the Toronto Stock
Exchange in Canada under the symbol "IAE" and on AIM in the United
Kingdom under the symbol "IAE".
NON-IFRS MEASURES 'Cashflow from operations' referred
to in this MD&A is not prescribed
by IFRS. This non-IFRS 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
considers Cashflow from operations to be a key measure as it
demonstrates the Corporation's underlying 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 from operating
activities.'Profit before tax and unrealised gains/losses on financial
instruments' referred to in this MD&A is not prescribed by IFRS. This
non-IFRS 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, Profit
before tax and unrealised gains/losses on financial instruments should
not be considered as an alternative to, or more meaningful than, Profit
before tax as determined in accordance with IFRS. The Corporation
considers Profit before tax and unrealised gains/losses on financial
instruments to be a key measure as it demonstrates the Corporation's
underlying profitability, stripping out the effects of non cash
financial instrument gains / losses. Profit before tax and unrealised
gains/losses on financial instruments is determined by deducting /
adding back non-cash gains / losses on financial instruments.
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. Given the value ratio based on the current price of
crude oil as compared to natural gas is significantly different from
the energy equivalency of 6 mcf: 1 bbl, utilizing a conversion ratio at
6 mcf: 1 bbl may be misleading as an indication of value.
HIGHLIGHTS THIRD QUARTER 2012
Financial
* Q3 profit before tax and unrealised gains/losses on financial
instruments of $14.9 million (Q3 2011: $15.6 million)
* Q3 net earnings of $4.9 million including $12.9 million
unrealised loss from financial instruments (Q3 2011: $16.0 million)
resulting in earnings per share of $0.02 (Q3 2011: $0.06)
* Q3 cashflow from operations of $30.1 million (Q3 2011: $18.1
million). Q3 cashflow per share of $0.12 (Q3 2011: $0.07)
* Q3 average realized oil price of $110.26 / bbl (Q3 2011: $111.24
/ bbl) plus an additional realized hedging gain of $2.56 / bbl in the
quarter
* Cash of $77.4 million, inclusive of $20.6 million restricted
cash, with fully syndicated senior debt facility of $430 million
remaining undrawn
* UK tax allowances pool of $387 million
Operational & Corporate
* Q3 export production of 5,061 barrels of oil equivalent per day
("boepd") (Q3 2011: 3,602 boepd) - a 40% increase despite the planned
maintenance shutdown of the Cook field during the quarter
* Production from the Athena field stabilised at a gross rate of
10,000 to 11,000 barrels of oil per day ("bopd"), 2,250 to 2,475 bopd
net to Ithaca, with the field continuing to produce "dry" oil
* Hurricane appraisal well successfully drilled, identifying
hydrocarbons in two reservoir intervals, with pressure and fluid
samples recovered from both intervals and a highly successful drill
stem test performed on the Andrew sand reservoir
* An Engineering, Procurement, Installation and Construction
("EPIC") contract was awarded to Technip UK Limited covering the major
subsea works that are to be conducted on the Greater Stella Area, with
installation of the subsea infrastructure scheduled for 2013
* Entered into further swaps of 503,800 barrels of oil at a
weighted average price of $108.67 and put options, at market price,
for 300,300 barrels of oil at a weighted average oil price floor of
$111.34 / bbl for the period October 2012 to December 2013.
Post quarter end
* Entered into agreements with Noble Energy Capital Limited to
acquire corporate entities owning non-operated interests in two United
Kingdom ("UK") North Sea producing fields: a 12.885% interest in the
Cook field (increasing the Company's field interest in Cook to
41.345%) and a 14% interest in the MacCulloch field. The total
acquisition consideration is $38.5 million and is to be funded from
the Company's existing cash resources. The two fields are anticipated
to increase the Company's net proved and probable reserves by
approximately 3.4 mmboe based on the effective date of the
transaction of 1 January 2012
* Closure of an oversubscribed syndication of $430 million debt
facility (the "Facility") with BNP Paribas ("BNPP") and six other
leading international banks working in the oil and gas sector
* Offered two Blocks by the Department of Energy and Climate Change
("DECC") in the 27th UK Licence Round - Block 29/5e in the vicinity
of the Company's existing Greater Stella Area ("GSA")interests and
Block 15/17b in the Outer Moray Firth
* The Company has issued today a full update on the progress made on
the Greater Stella Area development.
KEY PROJECTS AND OPERATIONS UPDATE
Athena
Start up of oil production from the Athena field was achieved in late
May 2012. The early part of Q3 2012 was focused on completing and
optimising the post start-up activities required to deliver stable and
efficient operations from the wells and the BW Athena Floating
Production, Storage and Offloading vessel ("FPSO"). Well intervention
activities were performed on the "P1" well during the quarter to
attempt to eliminate a blockage in the production tubing of the P1
well. These operations, involving the pumping of fluids into the P1
well, were partially successful and the well was put onstream in
September at a gross production rate of approximately 700 to 800
barrels of oil gross per day ("bopd"). A decision was made by the
Athena co-venturers not to perform a rig based workover on P1 to fully
remove the blockage as the reserves associated with the well are
anticipated to be recovered by the existing wells on the field.
Production from the field has stabilised at a gross daily rate of
between 10,000 and 11,000 bopd, 2,250 to 2,475 bopd net to Ithaca.
Reservoir performance, including the continued production of dry oil,
provides a positive signal for the longer term potential of the field.
The timing of water breakthrough at the Athena wells, along with the
efficiency of the sweep of oil through the reservoir assisted by water
injection, will be key to predicting the ultimate field production
profile and will be built into a range of production forecasts by the
Company.
Greater Stella Area
Significant progress has been made with delivery of the Company's GSA
strategy and execution of the Stella and Harrier development project
since the Field Development Plan ("FDP") for the two fields was
approved by the DECC in April 2012.
An update on the progress made with the GSA development activities and
schedule has today been issued by the Company. The key points
contained in the release are:
o The modifications contract for the "FPF-1" floating production unit
has been awarded to the Remontowa shipyard in Gdansk, Poland. The
FPF-1 is now located In Gdansk.
o The Ensco 100 drilling rig is now forecast to commence the
development drilling campaign in Q1-2013, due to delays in the
completion of drilling programmes for other operators.
o Four initial Stella wells are to be drilled over a period of
approximately twelve months prior to the arrival of the FPF-1 for
hook-up and commissioning, currently anticipated in H1-2014.
o Detailed design has been completed for the subsea infrastructure
that is to be installed in 2013 by Technip, a world leader in the
execution of subsea projects. Fabrication of the required linepipe is
underway.
o A suite of gas transportation and processing agreements has been
executed for export of gas processed on the FPF-1 via the Central Area
Transmission System ("CATS") and Teeside Gas and Liquids Processing
("TGLP") terminal.
o The Company's net share of remaining capital expenditure prior to
first hydrocarbons from the GSA production hub is $395 million, which
will be funded from existing financial resources.
o The successful appraisal of the Hurricane discovery in Q3-2012 and
the offer of Block 29/5e, adjacent to Hurricane, in the 27th UK
Offshore License Round in October 2012 have further augmented the
opportunity set for the GSA hub.
Hurricane
During the quarter, the Company successfully completed drilling of the
Hurricane appraisal well in Block 29/10b, which lies within the GSA.
The well was drilled using the WilHunter semi-submersible rig, with
Applied Drilling Technologies International ("ADTI"), a subsidiary of
Transocean, used to manage drilling operations under "turnkey" contract
arrangements.
The well identified hydrocarbons in two reservoir intervals, the Eocene
Rogaland sandstone and the Palaeocene Andrew reservoir. Pressure data
and fluid samples were recovered from both intervals and a drill stem
test ("DST") was performed on the Andrew reservoir. During the main
DST flow period, lasting approximately 24 hours, the Andrew interval~
achieved an average gross flow rate of approximately 17 million
standard cubic feet of gas per day ("MMscf/d") with associated
condensate of 870 bopd (52degrees American Petroleum Institute "API"
Gravity) from a half inch choke. A gross maximum flow rate of
approximately 24 MMscf/d with associated condensate of 1,200 bopd from
a 44/64-inch fixed choke was also achieved with the full production
potential of the well being limited by surface equipment.
The appraisal well has been suspended for future potential use as a
production well for the Andrew reservoir, with the capability of also
being used for future production from the Rogaland reservoir.
The Company is in the process of completing a comprehensive work
programme to assess the ultimate recoverable volumes associated with
the field prior to integration of the data into the usual year end
reserves evaluation that will be performed by the Company's independent
reserves assessor, Sproule International Limited ("Sproule").
OTHER DEVELOPMENTS
Corporate events
In October, the Company announced that it had entered into agreements
with Noble Energy Capital Limited (a subsidiary of Noble Energy Inc.,
NYSE: NBL) to acquire two wholly owned UK subsidiary companies that
will hold non-operated interests in UK North Sea producing fields; a
12.885% interest in the Cook field and a 14% interest in the MacCulloch
field.
The acquisition will result in the Company increasing its existing Cook
field interest from 28.46% to 41.345%, furthering its position as the
field's largest owner.Based on the independent reserves assessment
performed by Sproule, effective as of 31 December 2011, remaining net
proved and probable reserves associated with the additional 12.885%
interest (as of that date) are 2.0 mmboe.
The MacCulloch oil field, currently operated by ConocoPhillips, lies in
Blocks 15/24b in the Central North Sea (transfer of field operatorship
to Endeavour Energy UK Limited is pending completion of a previously
announced transaction).The field is producing from four subsea wells
tied back to the North Sea Producer FPSO, with processed oil and gas
exported via pipelines to shore.Remaining net proved and probable
reserves effective as of 31 December 2011 are estimated by Ithaca to be
approximately 1.4 mmboe.An assessment of the field reserves will be
performed by Sproule as part of the normal year end reserves evaluation
exercise.
The total acquisition consideration is $38.5 million, to be funded from
the Company's existing cash resources.Completion of the transactions
is anticipated in early 2013 and is subject to normal regulatory and
joint venture approvals, including reaching agreement in respect of
decommissioning cost security.
Debt facility
In October 2012 the Company agreed and signed a $430 million Facility
with BNPP as Bookrunner and Mandated Lead Arranger. The syndication
process was oversubscribed, underlining the value of the Company's
existing asset portfolio and development execution strategy.
The seven banks participating in the facility syndicate are:
* BNPP and Lloyds TSB Bank plc (as Bookrunners and Mandated
Arrangers);
* Bank of America N.A., Deutsche Bank AG, The Bank of Nova Scotia
and The Royal Bank of Scotland (as Mandated Lead Arrangers); and,
* NIBC Bank N.V. (as Manager).
This Facility replaces the previous undrawn $140 million debt facility
and is on similar conventional oil and gas industry borrowing base
financing terms, with a loan term of up to five years. The Facility is
available to fund ongoing development activities and future asset
acquisitions.
27th Licensing Round
In October, Ithaca was offered two operated licenses as part of the
27th Licensing Round: Block 29/5e in the vicinity of the Company's
existing GSA interests and Block 15/17b in the Outer Moray Firth. The
license offers are based on the completion of technical studies,
leading to a drill or drop decision on each license within two years of
formal license award.
RESULTS OF OPERATIONS
Revenue
Three months ended September 30, 2012
Revenue increased by $15.2 million in Q3 2012 to $41.6 million (Q3 2011
$26.4 million). This movement mainly comprises an increase in oil sales
volumes, partially offset by a small decrease in average realized oil
prices and a reduction in gas sales.
Oil sales volumes increased primarily due to the inclusion of sales
from the Athena field along with Broom field liftings in Q3 2012
(acquired in Q4 2011). There was a small decrease in average realized
oil prices from $111.24 / bbl in Q3 2011 to $110.26 / bbl in Q3 2012 as
the Brent oil price benchmark weakened during the quarter. This
reduction in price was more than offset by a realized hedging gain of
$2.56/bbl.
The decrease in gas sales in Q3 2012 compared to Q3 2011 was due to a
reduction in Anglia and Topaz gas volumes due to maintenance shutdowns,
partly offset by a small increase in the average realized gas price.
Nine months ended September 30, 2012
Revenue increased by $43.8 million in the nine months to Q3 YTD 2012 to
$118.0 million (Q3 YTD 2011 $74.2 million). This movement mainly
comprises an increase in oil sales volumes, partially offset by a
reduction in gas sales.
The increase in oil sales volumes is primarily due to the inclusion of
production from Athena, Cook and Broom fields offset by natural
declines in the Beatrice and Jacky fields. The realized oil price was
relatively consistent at just over $112/bbl before hedging.
The increase in oil sales was partly offset by a decrease in gas sales
in the period. This was due to a reduction in Anglia and Topaz gas
volumes, partially offset by the addition of Cook gas sales.
Cost of Sales
Three months ended September 30, 2012
Cost of sales increased in Q3 2012 to $27.1 million (Q3 2011 $12.7
million) due to increases in operating costs and depletion,
depreciation and amortization ("DD&A"), partly offset by higher oil
inventory.
Operating costs increased in the period to $20.9 million (Q3 2011 $12.0
million) primarily due to the inclusion of Athena, Cook and Broom
operating costs in Q3 2012 (Cook was acquired midway through Q3 2011
and Broom in Q4 2011, with Athena commencing production in Q2 2012).
Operating costs per boe have increased to $44.89 for Q3 2012 (Q3 2011:
$36.11) primarily driven by maintenance shutdowns in the quarter on
Cook, Anglia and Topaz, along with natural declines in production on
Beatrice and Jacky.
DD&A expense for the quarter increased to $14.6 million (Q3 2011 $7.9
million). This was primarily due to the addition of the Athena and
Broom assets, as well as significant capital expenditure in the period
from Q3 2011 to Q3 2012 leading to increased DD&A rates on existing
assets. The blended DD&A rate for Q3 2012 is $31.07/boe (Q3 2011:
$23.50/boe) with Athena having a positive impact which partly mitigates
the increase from other fields.
An oil and gas inventory movement of $8.4 million was credited to cost
of sales in Q3 2012 (Q3 2011 credit of $7.2 million) primarily relating
to the build up of stock levels on Cook, Athena and Broom. Movements in
oil inventory arise due to differences between barrels produced and
sold with production being recorded as a credit to movement in oil
inventory through cost of sales until oil has been sold. In Q3 2012
more barrels of oil were produced (425k bbls) than sold (347k bbls)
with volumes accounting for $8.1m of the movement. The remainder of
the credit is due to the change in valuation of the opening inventory
barrels, which are valued to reflect each field's relevant sales
contract, such movements generally following the trend in Brent price,
with some skewing due to the mix by field.
Nine months ended September 30, 2012
Cost of sales increased in Q3 YTD 2012 to $83.1 million (Q3 YTD 2011
$46.4 million) due to increases in operating costs and DD&A.
Operating costs increased in the period to $52.0 million (Q3 YTD 2011
$33.8 million) primarily due to the inclusion of Athena, Cook and Broom
operating costs in 2012 as noted above. Operating costs per barrel have
increased to $42.73/boe in the period (Q3 YTD 2011: $41.04) due to
maintenance shutdown costs coupled with natural declines in production,
partially offset by the positive impact of Cook and Athena on the
blended rate per barrel.
DD&A expense for the period increased to $39.0 million (Q3 YTD 2011
$19.8 million). This was primarily due to the addition of the Athena,
Cook and Broom assets as well as significant capital expenditure in the
period from Q3 2011 to Q3 2012 leading to increased DD&A rates on
existing assets. The blended rate for the period has increased to
$31.82 (Q3 YTD 2011 $23.73), with Cook and Athena having a positive
impact which partly mitigates the increase from other fields.
An oil and gas inventory movement of $8.0 million was credited to cost
of sales in the period (Q3 YTD 2011 credit of $7.2 million). As noted
above, this is due to the build up of inventory representing the
difference between barrels of oil produced and sold in the period, with
more barrels being produced than sold YTD.
Administrative expenses and Exploration & Evaluation expenses
Three months ended September 30, 2012
Administrative expenses decreased in the quarter to $0.5 million (Q3
2011 $1.6 million) due to a reduction in share based payment expenses
as a result of no options being granted at the end of 2011, coupled
with a change in the timewriting profile, with more capitalized
timewriting in Q3 2012 primarily due to increased activities on the
development of the Stella and Harrier fields.
Exploration and evaluation expenses of $0.1 million were recorded in
the period (Q3 2011 $0.2 million) due to the expensing of previously
capitalized costs relating to areas where exploration and evaluation
activities have ceased.
Nine months ended September 30, 2012
Administrative expenses decreased in the period to $3.0 million (Q3 YTD
2011 $5.2 million) again due to no options being granted at the end of
2011 and a change in the timewriting profile, with more capitalized
timewriting in the nine months to September 2012.
Exploration and evaluation expenses of $0.2 million (Q3 YTD 2011 $0.2
million) were recorded in the period.
Foreign exchange and Financial Instruments
Three months ended September 30, 2012
A foreign exchange gain of $0.7 million was recorded in Q3 2012 (Q3
2011 $2.4 million loss). The majority of the Corporation's revenue is
US dollar driven whilst costs are primarily incurred in British pounds.
As such, general volatility in the USD:GBP exchange rate is the driver
behind the foreign exchange gains and losses, particularly on the
revaluation of GBP bank accounts. This volatility was partly offset by
foreign exchange hedges as described in the "Risks and Uncertainties"
section below.
The Corporation recorded a $12.0 million loss on financial instruments
for the three months ended September 30, 2012 (Q3 2011 $0.4 million
gain). The loss was predominantly due to a $13.6 million revaluation of
oil swaps and put options as a result of the September 30, 2012 oil
spot price of $111.03 compared to the much lower price at June 30, 2012
of $94.50 offset by a $0.9 million realized gain on oil swaps and $0.7
million gain on the revaluation of other instruments. This loss
partially reversed a gain recognized in Q2 2012 of $19.3 million as a
result of the lower oil price in Q2.
Nine months ended September 30, 2012
A foreign exchange gain of $0.9 million was recorded in Q3 YTD 2012 (Q3
YTD 2011 $0.1 million gain). As above, general volatility in the
USD:GBP exchange rate was the driver behind the foreign exchange gains
(USD:GBP at January 1, 2012: 1.55. USD:GBP at September 30, 2012: 1.62
with fluctuations between 1.52 and 1.63 during the period).
The Corporation recorded a $6.6 million gain on financial instruments
for the nine months ended September 30, 2012 (Q3 YTD 2011 $2.2 million
loss). The gain was predominantly due to a $3.2 million revaluation of
oil swaps and put options and a $2.6 million realized gain on commodity
hedges, along with a $2.0 million gain on the revaluation of other
instruments, partially offset by a $1.3 million loss on revaluation of
contingent consideration liabilities, triggered by FDP approval,
relating to the acquisition of the Stella field and Challenger Minerals
(North Sea) Limited ("CMNSL").
Taxation
Three months ended September 30, 2012
A deferred tax credit of $2.9 million was recognized in the quarter
ended September 30, 2012 (Q3 2011: less than $0.1 million credit). This
credit is a product of adjustments to the tax charge primarily relating
to the UK Ring Fence Expenditure Supplement and share based payments.
As a result of the above factors, profit after tax increased to $4.9
million (Q3 2011 $16.0 million).
Nine months ended September 30, 2012
A deferred tax credit of $10.6 million was recognized in the nine
months ended September 30, 2012 (Q3 YTD 2011 $3.6 million charge). This
credit is a product of adjustments to the tax charge primarily relating
to the UK Ring Fence Expenditure Supplement, share based payments, and
relief claimed for the reinvestment of disposal proceeds relating to
the sale of assets to Petrofac GSA Limited and Dyas UK Limited.
As a result of the above factors, profit after tax increased to $48.1
million (Q3 YTD 2011 $22.5 million).
No tax is expected to be paid in the mid-term future relating to
upstream oil and gas activities.
SUMMARY OF QUARTERLY RESULTS
The following table provides a summary of the quarterly results of the
Corporation for the eight most recently completed quarters:
Restated
30/09/ 30/06/ 31/03/ 31/12/ 30/09/ 30/06/ 31/03/ 31/12/
12 2012 2012 2011 2011 2011 2011 2010
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
Revenue 41,579 35,779 40,553 54,870 26,415 16,724 31,050 34,260
Profit
after tax 4,894 30,238 12,916 13,378 16,016 2,743 3,789 17,650
Earnings per share
Basic 0.02 0.12 0.05 0.05 0.06 0.01 0.01 0.07
Diluted 0.02 0.11 0.05 0.05 0.06 0.01 0.01 0.07
The most significant factors to have affected the Corporation's results
during the above quarters are fluctuation in underlying commodity
prices and movement in production volumes. The Corporation has utilized
forward sales contracts and foreign exchange contracts to take
advantage of higher commodity prices while reducing the exposure to
price volatility. These contracts can cause volatility in profit after
tax as a result of unrealized gains and losses due to movements in the
oil price and USD : GBP exchange rate.
Each of the quarters from Q4 2010 to Q3 2011 has been restated
following the Corporation's election to present all acquisitions since
the IFRS transition date as business combinations in accordance with
IFRS 3®. Refer to the "Changes in Accounting Policies" below for more
details.
LIQUIDITY AND CAPITAL RESOURCES
As at September 30, 2012, Ithaca had working capital of $57.9 million
including a free cash balance of $56.8 million. Available cash has
been, and is currently, invested in money market deposit accounts with
Lloyds Banking Group ("Lloyds"). Management has received confirmation
from the financial institution that these funds are available on
demand. The restricted cash of $20.6 million comprises $20.5 million
currently held by BNPP as decommissioning security provided as part of
the acquisitions of the Anglia and Cook fields (with release / renewal
dates of: February 28, 2013 ($10.9 million), and December 31, 2012
($9.6 million)).
At September 30, 2012, Ithaca has unused credit facilities currently
totalling $430 million.
During the three months ended September 30, 2012 there was a cash
outflow from operating, investing and financing activities of $55.0
million (Q3 2011 outflow of $70.3 million). The net outflow was due to
a cash outflow of $75.9 from investing activities, a cash outflow of
$2.8 million from financing activities, partially offset by a cash
inflow from operating activities of $22.8 million. The remainder of the
movement was due to foreign exchange on non US Dollar denominated cash
deposits. This overall free cash inflow is predominantly the product of
cash generated from Athena, Beatrice, Jacky, Anglia, Topaz, Cook and
Broom operations offset by development capital expenditure on the
Greater Stella Area, including modification of the FPF-1, subsea design
and fabrication works and appraisal well drilling on the Hurricane
field.
A significant proportion of Ithaca's accounts receivable balance is
with customers in the oil and gas industry and is subject to normal
industry credit risks. The Corporation assesses partners' credit
worthiness before entering into joint venture agreements. The
Corporation regularly monitors all customer receivable balances
outstanding in excess of 90 days. As at September 30, 2012 over 99% of
the accounts receivable is current, being defined as less than 90 days.
In the past, the Corporation has not experienced credit loss in the
collection of accounts receivable.
The Corporation continues to be fully funded, with more than sufficient
financial resources to cover the anticipated level of development
capital expenditure commitments and to continue the pursuit of
additional asset acquisition opportunities and exploration and
appraisal activities on existing and newly acquired licenses through
its existing cash balance, forecast cashflow from operations and its
undrawn debt facility. No unusual trends or fluctuations are expected
outside the ordinary course of business.
COMMITMENTS
The Corporation has the following financial commitments:
1 year 2-5 years More than 5 years
$'000 $'000 $'000
Office lease 259 1,035 129
Exploration license fees 665 - -
Engineering 86,462 20,208 -
Rig commitments 19,416 - -
Total 106,802 21,243 129
The engineering financial commitments relate to pre-development
committed capital expenditure on the Stella and Harrier fields, as well
as ongoing capital and operating expenditure on existing producing
fields. As stated above, these commitments are expected to be funded
through the Corporation's existing cash balance, forecast cashflow from
operations and its undrawn debt facility.
OUTSTANDING SHARE INFORMATION
As at September 30, 2012 Ithaca had 259,346,128 common shares
outstanding along with15,276,839 options outstanding to employees and
directors to acquire common shares.
In October 2012, the Board of Directors approved the grant of 5,645,000
options at a price of C$1.99. Each of the options granted may be
exercised over a period of four years from the grant date. One third of
the options will vest at the end of the first, second and third years
from the effective date of grant. A number of officers and employees
also exercised 573,875 options at a price of C$1.80 per share in
October.
As at November 9, 2012, Ithaca had 259,920,003 common shares
outstanding along with20,347,964 options outstanding 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 Statement of Income.
Goodwill is tested annually for impairment and also when circumstances
indicate that the carrying value may be at risk of being impaired.
Impairment is determined for goodwill by assessing the recoverable
amount of each CGU to which the goodwill relates. Where the recoverable
amount of the CGU is less than its carrying amount, an impairment loss
is recognized in the Statement of Income. Impairment losses relating to
goodwill cannot be reversed in future periods.
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, other than those designated as effective
hedging 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, 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 share based payment 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 and rig commitments which
were entered into in the normal course of operations, all of which are
disclosed under the heading "Commitments", above. Leases are treated
as either operating leases or finance leases based on the extent to
which risks and rewards incidental to ownership lie with the lessor or
the lessee under IAS 17. No asset or liability value has been assigned
to any leases on the balance sheet as at September 30, 2012.
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 Q3 2012 was $nil (Q3 2011 $0.1 million). These
transactions are in the normal course of business and are conducted on
normal commercial terms with consideration comparable to those charged
by third parties.
As at September 30, 2012 the Corporation had a loan receivable from
FPF-1 Ltd, an associate of the Corporation, for $21.6 million (Q3 2011
$Nil) as a result of the completion of the GSA transactions.
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 April 2012, the
Corporation entered into two put options: to sell 190,000 bbls of the
Corporation's May 2012 - February 2013 forecast production at a fixed
price of $120.50/bbl and 200,000 bbls at a fixed price of $120/bbl. In
February 2012, the Corporation entered into two swap options: to sell
268,800 bbls of the Corporation's March 2012 - December 2012 forecast
production at a fixed price of $121.32/bbl; and to sell 500,000 bbls
of the Corporation's forecast July 2012 - June 2013 production at
$113.25 / bbl.
In August 2012 the Corporation entered into further derivatives for the
period October 2012 to December 2013, being swaps of 503,800 bbls of
oil at a weighted average price of $108.67 and put options, at market
price, for 300,300 bbls of oil at a weighted average oil price floor of
$111.34 / bbl.
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 November 2011,
the Corporation entered into a forward extra plus contract with Lloyds
to hedge part of its forecast GBP 2012 operating costs, including
general and administrative expenses. The hedge amounts to $4 million
per month (total $48 million) at a USD:GBP rate of no worse than $1.60/
GBP1.0 while benefiting in any improvement of the rate down to a trigger
rate of $1.40/GBP1.00. If the trigger rate is reached in any month the
conversion rate realized for that month is $1.58/GBP1.00.
A further risk relates to the Corporation's ability to meet the
conditions precedent for a full drawdown on the Corporation's Facility
with BNPP. Ability to drawdown the Facility is based on the Corporation
meeting certain covenants 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 Facility, however at
present the Corporation believes that there are no circumstances
present that result in failure to meet those tests and can therefore
draw down upon its Facility.
In addition, the Facility contains the aforementioned 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 ever deemed 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 Facility may be impaired.
At present the Corporation believes that there are no circumstances
present that result in 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 Energy (UK) Limited's ("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 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. All of the Corporation's oil production from the Beatrice,
Jacky and Athena fields is sold to BP Oil International Limited. Oil
production from Cook and Broom is sold to Shell Trading International
Ltd. Anglia and Topaz gas production is sold through contracts to RWE
NPower PLC and Hess Energy Gas Power (UK) Ltd. Cook gas is sold to
Shell UK Ltd. and Esso Exploration & Production 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.
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
Ithaca has established disclosure controls, procedures and corporate
policies so that its consolidated financial results are presented
accurately, fairly and on a timely basis. The Chief Executive Officer
and Chief Financial Officer have designed, or have caused such internal
controls over financial reporting to be designed under their
supervision, to provide reasonable assurance regarding the reliability
of financial reporting and preparation of the Company's financial
statements in accordance with IFRS with no material weaknesses
identified.
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.
As of September 30, 2012, there were no changes in our internal control
over financial reporting that occurred during the period ended
September 30, 2012 that have materially affected, or are reasonably
likely to materially affect, our internal control over financial
reporting.
CHANGES IN ACCOUNTING POLICIES
On January 1, 2011, the Corporation adopted IFRS using a transition
date of January 1, 2010. The financial statements for the three months
ended September 30, 2012, including required comparative information,
have been prepared in accordance with IFRS and with International
Accounting Standard ("IAS") 34, Interim Financial Reporting, as issued
by the International Accounting Standards Board ("IASB").
Following the introduction of IFRS the Corporation initially accounted
for the acquisitions of the non-operated interests in the Cook field
and of CMNSL as asset acquisitions. In Q4 2011 the Company subsequently
elected to present all acquisitions since the IFRS transition date as
business combinations in accordance with IFRS 3®. This has resulted
in a restatement of the original accounting for the Cook acquisition
(in Q3 2011) and the acquisition of gas assets from GDF (in Q4 2010) as
shown in previous interim statements during 2011.
One impact of accounting for acquisitions as business combinations is
the recognition of asset values, upon which the DD&A rate is calculated
as pre-tax fair values and the recognition of a deferred tax liability
on estimated future cash flows. With current tax rates at 62% this
increases the DD&A charge for such assets. A partially offsetting
reduction is recognized in the deferred tax charged through the
consolidated statement of income.
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
decided not to early adopt any of the new requirements.
FINANCIAL INSTRUMENTS AND OTHER INSTRUMENTS
All financial instruments, other than those designated as effective
hedging 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 until the hedged
transaction is recognized in net earnings.
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 September 30, 2012.
The table below presents the total gain / (loss) on financial
instruments that has been disclosed through the statement of
comprehensive income:
Three months ended Sept 30 Nine months ended Sept 30
2012 2011 2012 2011
$'000 $'000 $'000 $'000
Revaluation forex 166 - 707 -
forward contracts
Revaluation of 610 2,315 1,368 3,339
gas contract
Revaluation of (86) 332 (115) 478
other long
term liability
Revaluation of (13,617) (2,250) 3,241 (5,477)
commodity hedges
Total revaluation (12,927) 397 5,201 (1,660)
gain / (loss)
Realized gain/ 888 - 2,597 (493)
(loss)on commodity
hedges
Realized gain on 50 - 118 -
forex forward
contracts
Total realized 938 - 2,715 (493)
gain/(loss)
Total realize (11,989) 397 7,916 (2,153)
/ revaluation
gain/(loss)
Contingent - - (1,295) -
consideration
Total gain/ (11,989) 397 6,621 (2,153)
(loss) on financial
instruments
FORWARD-LOOKING INFORMATION
This MD&A and any documents incorporated by reference herein contain
certain forward-looking statements and forward-looking information
which are based on the Corporation's internal expectations, estimates,
projections, assumptions and beliefs as at the date of such statements
or information, including, among other things, assumptions with respect
to production, future capital expenditures and cash flow. The reader
is cautioned that assumptions used in the preparation of such
information may prove to be incorrect. The use of any of the words
"anticipate", "continue", "estimate", "expect", "may", "will",
"project", "plan", "should", "believe", "could", "scheduled",
"targeted" and similar expressions are intended to identify
forward-looking statements and forward-looking information. These
statements are not guarantees of future performance and involve known
and unknown risks, uncertainties and other factors that may cause
actual results or events to differ materially from those anticipated in
such forward-looking statements or information. The Corporation
believes that the expectations reflected in those forward-looking
statements and information are reasonable but no assurance can be given
that these expectations, or the assumptions underlying these
expectations, will prove to be correct and such forward-looking
statements and information included in this MD&A and any documents
incorporated by reference herein should not be unduly relied upon.
Such forward-looking statements and information speak only as of the
date of this MD&A and any documents incorporated by reference herein
and the Corporation does not undertake any obligation to publicly
update or revise any forward-looking statements or information, except
as required by applicable laws.
In particular, this MD&A and any documents incorporated by reference
herein, contains specific forward-looking statements and information
pertaining to the following:
- the quality of and future net revenues from the Corporation's
reserves;
- oil, natural gas liquids ("NGLs") and natural gas production
levels;
- commodity prices, foreign currency exchange rates and interest
rates;
- capital expenditure programs and other expenditures;
- the sale, farming in, farming out or development of certain
exploration properties using third party resources;
- supply and demand for oil, NGLs and natural gas;
- the Corporation's ability to raise capital;
- the Corporation's acquisition strategy, the criteria to be
considered in connection therewith and the benefits to be derived
therefrom;
- the Corporation's ability to continually add to reserves;
- schedules and timing of certain projects and the Corporation's
strategy for growth;
- the Corporation's future operating and financial results;
- the ability of the Corporation to optimize operations and reduce
operational expenditures;
- treatment under governmental and other regulatory regimes and
tax, environmental and other laws;
- production rates;
- targeted production levels; and
- timing and cost of the development of the Corporation's reserves.
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;
- FDP 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 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;
- 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 any
increase in UK taxes;
- adverse regulatory rulings, orders and decisions; and
- risks associated with the nature of the common shares.
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 .
Consolidated Statement of Income
For the three and nine months ended 30 September 2012 and 2011
(unaudited)
Restated Restated
Three months ended Nine months ended
30 Sept 30 Sept
2012 2011 2012 2011
Note US$'000 US$'000 US$'000 US$'000
Revenue 4 41,579 26,415 117,912 74,189
Cost of Sales 5 (27,096) (12,603) (83,082) (46,292)
Gross Profit 14,483 13,812 34,830 27,897
Exploration and evaluation 10 (112) (174) (191) (140)
expenses
Administrative expenses 6 (524) (1,648) (2,967) (5,161)
Operating Profit 13,847 11,990 31,672 22,596
Foreign Exchange 748 (2,415) 851 147
(Loss) / gain on financial 23 (11,989) 397 6,621 (2,153)
instruments
Gain on asset disposal 11 - - 205 -
Negative goodwill - 6,647 - 6,467
Profit Before Interest and 2,606 16,439 39,349 27,057
Tax
Finance costs 7 (697) (527) (2,068) (1,275)
Interest income 61 89 195 362
Profit Before Tax 1,970 16,001 37,476 26,144
Taxation - Deferred tax 21 2,924 15 10,575 (3,597)
Profit After Tax 4,894 16,016 48,051 22,547
Earnings per share
Basic 20 0.02 0.06 0.19 0.09
Diluted 20 0.02 0.06 0.18 0.09
The accompanying notes on pages 7 to 25 are an integral part of the
financial statements.
Consolidated Statement of Financial Position
(unaudited)
30 September 31 December
2012 2011
US$'000 US$'000
ASSETS
Current assets
Cash and cash equivalents 56,843 95,545
Restricted cash 8 20,560 16,510
Accounts receivable 147,349 80,960
Deposits, prepaid expenses and other 6,593 8,793
Inventory 9 17,274 8,836
Derivative financial instruments 24 8,580 -
257,199 210,644
Non current assets
Long-term receivable 26 21,551 -
Investment in associate 13 18,337 -
Exploration and evaluation assets 10 41,440 22,689
Property, plant & equipment 11 591,774 570,356
Goodwill 12 985 985
674,087 594,030
Total assets 931,286 804,674
LIABILITIES AND EQUITY
Current liabilities
Trade and other payables 199,334 102,136
199,334 102,136
Non current liabilities
Decommissioning liabilities 15 51,702 39,382
Other long term liabilities 16 2,901 2,785
Contingent consideration 17 4,000 24,580
Derivative financial instruments 24 - 1,846
Deferred tax liability 115,345 126,534
173,948 195,127
Net assets 558,004 507,411
Equity attributable to shareholders
Share capital 18 429,752 429,502
Share based payment reserve 19 19,610 17,318
Retained earnings 108,642 60,591
Shareholders' equity 558,004 507,411
The financial statements were approved by the Board of Directors on 9
November 2012 and signed on its behalf by:"Jay Zammit"
Director"John Summers"
Director
The accompanying notes on pages 7 to 25 are an integral part of the
financial statements.
Consolidated Statement of Changes in Equity
(unaudited)
Share Share Warrants Retained Total
Capital Based Issue Earnings
Payment
Reserve
US$'000 US$'000 US$'000 US$'000 US$'000
Balance, 1 Jan 2011 422,373 11,427 311 24,997 459,108
Net income for the - - - 22,547 22,547
period
Total comprehensive 422,373 11,427 311 47,544 481,655
income
Share based payment - 4,833 - - 4,833
Options exercised 1,032 (460) - - 572
Warrants exercised 6,097 - (311) - 5,786
Balance, 30 September 429,502 15,800 - 47,544 492,846
2011
Balance, 1 Jan 2012 429,502 17,318 - 60,591 507,411
Net income for the - - - 48,051 48,051
Period
Total comprehensive 429,502 17,318 - 108,642 555,642
income
Share based payment - 2,399 - - 2,399
Options exercised 250 (107) - - 143
Balance, 30 September 429,752 19,610 - 108,642 558,004
2012
The accompanying notes on pages 7 to 25 are an integral part of the
financial statements.
Consolidated Statement of Cash Flow
For the three and nine months ended 30 September 2012 and 2011
(unaudited)
Three months ended Nine months ended
30 Sept 30 Sept
2012 2011 2012 2011
US$'000 US$'000 US$'000 US$'000
CASH PROVIDED BY (USED IN):
Operating activities
Profit Before Tax 1,970 16,001 37,476 26,144
Adjustments for:
Depletion, depreciation and 14,563 7,861 39,040 19,790
amortisation
Exploration and evaluation 112 174 191 2,140
expenses
Share based payment 62 603 401 1,132
Loan fee amortisation - 78 494 746
Revaluation of financial 12,927 (397) (5,201) 1,851
instruments
Revaluation of contingent - - 1,295 (2,000)
consideration
Gain on disposal - - (205) -
Movement in goodwill - (6,467) - (6,467)
Accretion 453 217 1,272 571
Cashflow from operations 30,087 18,070 74,763 43,907
Changes in inventory, debtors (7,255) (6,709) 3,092 669
and creditors relating to
operating activities
Net cash from operating 22,832 11,361 77,855 44,576
activities
Investing activities
Capital expenditure (60,456) (88,469) (114,745) (154,891)
Investment in associate - - (18,337) -
Expenditure on - (358) - (358)
decommissioning
Loan to associate - - (21,551) -
Proceeds on disposal - - 44,878 -
Settlement of contingent - - (15,700) -
consideration
Changes in debtors and (15,409) 17,580 15,444 25,050
creditors relating
investing activities
Net cash used in investing (75,865) (71,247) (110,011) (130,199)
activities
Financing activities
Proceeds from issuance of - 371 143 6,357
shares
(Increase) / decrease in (340) (9,082) (4,049) (10,370)
restricted cash
Derivatives (2,485) - (2,485) (6,508)
Net cash used in financing (2,825) (8,711) (6,391) (10,521)
activities
Currency translation 816 (1,705) (155) (769)
differences relating to cash
Increase / (decrease) in cash (55,042) (70,302) (38,702) (96,913)
and cash equiv.
Cash and cash equivalents, 111,885 168,970 95,545 195,581
beginning of period
Cash and cash equivalents, 56,843 98,668 56,843 98,668
end of period
The accompanying notes on pages 7 to 25 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 27 April 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. As of 1
November 2011 the Corporation's shares have traded on the Toronto Stock
Exchange in Canada (previously the TSX Venture Exchange). The
Corporation's shares continue to trade on AIM in the United Kingdom
under the symbol "IAE". Ithaca has three wholly-owned subsidiaries,
Ithaca Energy (Holdings) Limited ("Ithaca Holdings"), incorporated in
Bermuda, Ithaca Energy (UK) Limited ("Ithaca UK") and Ithaca Minerals
(North Sea) Limited ("Ithaca Minerals"), which was acquired on 19
October 2011, both incorporated in Scotland. Ithaca also has two
associates, FPU Services Limited ("FPU Services") and FPF-1 Limited
("FPF-1"), both incorporated in Jersey.
2. BASIS OF PREPARATION
These interim consolidated financial statements have been prepared in
accordance with International Financial Reporting Standards (IFRS)
applicable to the preparation of interim financial statements,
including IAS 34 Interim Financial Reporting. These interim
consolidated financial statements do not include all the necessary
annual disclosures in accordance with IFRS.
The Company has elected to present all acquisitions since the IFRS
transition date as business combinations in accordance with IFRS 3®.
This has resulted in a restatement of the acquisition of gas assets
from GDF (in 4Q 2010) as shown in previous interim statements during
2011.
The policies applied in these condensed interim consolidated financial
statements are based on IFRS issued and outstanding as of 9 November
2012, 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 31
December 2012 could result in restatement of these interim consolidated
financial statements.
The condensed interim consolidated financial statements should be read
in conjunction with the Corporation's annual financial statements for
the year ended 31 December 2011.
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.
Basis of consolidation
The consolidated financial statements of the Corporation include the
accounts of Ithaca Energy Inc. and the wholly-owned subsidiaries Ithaca
Energy (UK) Ltd, Ithaca Minerals (North Sea) Ltd and Ithaca Energy
(Holdings) Ltd. All inter-company transactions and balances have been
eliminated on consolidation.
A subsidiary is an entity (including special purpose entities) which
the Corporation controls by having the power to govern the financial
and operating policies. The existence and effect of potential voting
rights that are currently exercisable or convertible are considered
when assessing whether Ithaca controls another entity. A subsidiary is
fully consolidated from the date on which control is obtained by Ithaca
and is de-consolidated from the date that control ceases.
Investments
Interests in entities over which Ithaca has significant influence, but
not control or joint control, are accounted for using the equity
method. Ithaca's share of equity investments is recorded in the
consolidated statement of income.
Business Combinations
Business combinations are accounted for using the acquisition method.
The cost of an acquisition is measured as the fair value of the assets
acquired, equity instruments issued and liabilities incurred or assumed
at the date of completion of the acquisition. Acquisition costs
incurred are expensed and included in administrative expenses.
Identifiable assets acquired and liabilities and contingent liabilities
assumed in a business combination are measured initially at their fair
values at the acquisition date. The excess of the cost of acquisition
over the fair value of the Corporation's share of the identifiable net
assets acquired is recorded as goodwill. If the cost of the acquisition
is less than the Corporation's share of the net assets required, the
difference is recognised directly in the statement of income.
Goodwill
Capitalisation
Goodwill acquired through business combinations is initially measured
at cost, being the excess of the aggregate of the consideration
transferred and the amount recognised as the fair value of the
Corporation's share of the identifiable net assets acquired and
liabilities assumed. If this consideration is lower than the fair value
of the identifiable assets acquired, the difference is recognised in
the statement of income.
Impairment
Goodwill is tested annually for impairment and also when circumstances
indicate that the carrying value may be at risk of being impaired.
Impairment is determined for goodwill by assessing the recoverable
amount of each cash generating unit ("CGU") to which the goodwill
relates. Where the recoverable amount of the CGU is less than its
carrying amount, an impairment loss is recognised in the statement of
income. Impairment losses relating to goodwill cannot be reversed in
future periods.
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 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 recognised in the statement of income.
Share based payments
The Corporation has a share based payment plan as described in note 18
(c). The Corporation's proportionate share of expense is recorded in
the statement of income or capitalised for all options granted in the
year, with the gross increase recorded in the share based payment
reserve. Compensation costs are based on the estimated fair values at
the time of the grant and the expense or capitalised amount is
recognised over the vesting period of the options. Upon the exercise of
the stock options, consideration paid together with the amount
previously recognised in the share based payment reserve is recorded as
an increase in share capital. In the event that vested options
expire unexercised, previously recognised compensation expense
associated with such stock options is not reversed. In the event that
unvested options are forfeited or expired, previously recognised
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, other than those designated as effective
hedging instruments, are initially recognised at fair value in the
statement of financial position. The Corporation's financial
instruments consist of cash, restricted cash, accounts
receivable, deposits, derivatives, accounts payable, accrued
liabilities, contingent consideration and the long term liability on
the Beatrice acquisition. The Corporation classifies its financial
instruments into one of the following categories: held-for-trading
financial assets and financial liabilities; held-to-maturity
investments; loans and receivables; and other financial liabilities.
All financial instruments are required to be measured at fair value on
initial recognition. Measurement in subsequent periods is dependent on
the classification of the respective financial instrument.
Held-for-trading financial instruments are subsequently measured at
fair value with changes in fair value recognised in net earnings. All
other categories of financial instruments are measured at amortised
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 amortised to consolidated net
earnings over the life of the financial instrument using the effective
interest method.
The Corporation may designate financial instruments as a hedging
instrument for accounting purposes. Hedge accounting requires the
designation of a hedging relationship, including a hedged and a hedging
item, identification of the risk exposure being hedged and an
expectation that the hedging relationship will be highly effective
throughout its term.
The Corporation assesses, both at the hedge's inception and on an
ongoing basis, whether the derivative financial instruments designated
as hedges are highly effective in offsetting changes in cash flows of
the hedged items. The effective portion of the gains and losses on cash
flow hedges is recorded in Other Comprehensive Income until the hedged
transaction is recognised in net earnings. Any hedge ineffectiveness is
immediately recognised in net earnings. When the hedged transaction is
recognised in net earnings, the fair value of the associated cash flow
hedging item is reclassified from other reserves into net earnings.
Hedge accounting is discontinued on a prospective basis when the
hedging relationship no longer qualifies for hedge accounting.
Analysis of the fair values of financial instruments and further
details as to how they are measured are provided in notes 23 to 25.
Inventory
Inventories of materials and product inventory supplies, other than oil
and gas inventories, are stated at the lower of cost and net realisable
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
statement of income 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 statement
of income 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 statement of income.
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. The obligation generally arises when the
asset is installed or the ground/environment is disturbed at the field
location. 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 the statement of income or in other
comprehensive income in accordance with IAS 39.
Taxation
Current income tax
Current income tax assets and liabilities are measured at the amount
expected to be recovered from or paid to the taxation authorities. The
tax rates and tax laws used to compute the amounts are those that are
enacted or substantively enacted by the reporting date.
Deferred income tax
Deferred tax is recognised 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
realisation 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
1 January 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, share based payment, 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 30 Sept Nine months ended 30 Sept
2012 2011 2012 2011
US$'000 US$'000 US$'000 US$'000
Oil sales 38,227 23,006 107,328 61,385
Gas sales 2,040 2,780 6,620 9,543
Condensate sales 98 223 405 799
Other income 1,214 406 3,559 2,462
Total 41,579 26,415 117,912 74,189
5. COST OF SALES
Restated Restated
Three months ended Nine months ended
30 Sept 30 Sept
2012 2011 2012 2011
US$'000 US$'000 US$'000 US$'000
Operating costs (20,903) (11,925) (52,031) (33,723)
Movement in oil and gas 8,370 7,183 7,989 7,221
inventory
Depletion, depreciation and (14,563) (7,861) (39,040) (19,790)
amortisation
(27,096) (12,603) (83,082) (46,292)
The above includes 2011 business combination restatements in accordance
with IFRS 3®. Refer to note 2 for further details.
6. ADMINISTRATIVE EXPENSES
Three months ended 30 Nine months ended 30
Sept Sept
2012 2011 2012 2011
US$'000 US$'000 US$'000 US$'000
General & (462) (1,045) (2,566) (3,324)
administrative
Share based payment (62) (603) (401) (1,837)
(524) (1,648) (2,967) (5,161)
7. FINANCE COSTS
Three months ended 30 Nine months ended 30
Sept Sept
2012 2011 2012 2011
US$'000 US$'000 US$'000 US$'000
Accretion (453) (217) (1,272) (572)
Bank charges (219) (232) (264) (470)
Non-operated asset finance (25) - (38) -
fees
Loan fee amortisation - (78) (494) (233)
(697) (527) (2,068) (1,275)
8. RESTRICTED CASH
30 Sept 31 Dec
2012 2011
US$'000 US$'000
Decommissioning security 20,560 16,167
Other security - 343
20,560 16,510
Restricted cash of $20.6 million is held by Bank BNP Paribas ("BNPP")
as decommissioning security in respect of the Corporation's interests
in the Anglia and Cook fields with release dates of 28 February 2013
($11.0 million) and 31 December 2012 ($9.6 million).
9. INVENTORY
30 Sept 31 Dec
2012 2011
US$'000 US$'000
Crude oil inventory 17,260 8,823
Materials inventory 14 13
17,274 8,836
10. EXPLORATION AND EVALUATION ASSETS
US$'000
At 1 January 2011 17,832
Additions 7,752
Write offs/relinquishments (2,791)
Disposals (104)
At 31 December 2011 22,689
Additions 28,168
Disposals (9,226)
Write offs/relinquishments (191)
At 30 September 2012 41,440
Following completion of geotechnical evaluation activity, certain
licences were declared unsuccessful and certain prospects were declared
non-commercial and therefore the related expenditure of $0.2 million
was expensed in the three and nine months to 30 September 2012.
Disposals in the period reflect the sale of assets to Petrofac GSA
Limited and Dyas UK Limited as detailed per note 11.
The above includes 2011 business combination restatements in accordance
with IFRS 3®. Refer to note 2 for further details.
11. PROPERY, PLANT AND EQUIPMENT
Development & Production Other fixed
Oil and Gas Assets assets Total
US$'000 US$'000 US$'000
Cost
At 1 January 2011 281,411 1,587 282,998
Additions 342,138 705 342,843
At 31 December 2011 623,549 2,292 625,841
Additions 98,311 60 98,371
Disposals (37,912) - (37,912)
At 30 September 2012 683,948 2,352 686,300
DD&A
At 1 January 2011 (22,934) (1,104) (24,038)
Charge for the period (31,054) (393) (31,447)
At 31 December 2011 (53,988) (1,497) (55,485)
Charge for the period (38,743) (298) (39,041)
At 30 September 2012 (92,731) (1,795) (94,526)
NBV at 1 January 2011 258,477 483 258,960
NBV at 1 January 2012 569,561 795 570,356
NBV at 30 September 2012 591,217 557 591,774
Disposals in the period reflect the sale of assets to Petrofac GSA
Limited ("Petrofac") and Dyas UK Limited ("Dyas") on completion of the
Sale and Purchase Agreements ("SPAs") relating to the Greater Stella
Area.
An overall pre-tax gain on disposal of $205k is shown through the
consolidated statement of income for the nine months ended 30 September
2012.
The above includes 2011 business combination restatements in accordance
with IFRS 3®. Refer to note 2 for further details.
12. GOODWILL
US$'000
Cost
At 1 January 2011, 31 December 2011 & 30 September 2012 985
$1.0 million represents goodwill recognised on the acquisition of gas
assets from GDF in December 2010.
13. INVESTMENT IN ASSOCIATES
30 Sept 31 Dec
2012 2011
US$'000 US$'000
Investments in FPF-1 and FPU services 18,337 -
Investment in associates comprises shares, acquired by Ithaca Holdings,
in FPF-1 and FPU Services as part of the completion of the Greater
Stella Area transactions.
14. LOAN FACILITY
On 29 June 2012, the Corporation executed a Senior Secured Borrowing
Base Facility agreement (the "Facility") for up to $430 million, being
provided by BNPP as Lead Arranger. The loan term is up to five years
and will attract interest at LIBOR plus 3-4.5%. This Facility replaces
the previous undrawn $140 million debt facility with Lloyds Banking
Group.
The Corporation is subject to financial and operating covenants related
to the Facility. Failure to meet the terms of one or more of these
covenants may constitute an event of default as defined in the Facility
agreement, potentially resulting in accelerated repayment of the debt
obligations.
The Corporation is in compliance with its financial and operating
covenants.
No funds were drawn down under the Facility as at 30 September 2012.
15. DECOMMISSIONING LIABILITIES
30 Sept 31 Dec
2012 2011
US$'000 US$'000
Balance, beginning of period 39,382 23,652
Additions 9,613 15,250
Accretion 1,272 858
Revision to estimates 1,435 (20)
Utilisation - (358)
Balance, end of period 51,702 39,382
The total future decommissioning liability was calculated by management
based on its net ownership interest in all wells and facilities,
estimated costs to reclaim and abandon wells and facilities and the
estimated timing of the costs to be incurred in future periods. The
Corporation uses a risk free rate of 3.9 percent (31 December 2011: 3.9
percent) and an inflation rate of 2 percent (31 December 2011: 2
percent) over the varying lives of the assets to calculate
the present value of the decommissioning liabilities. These costs
are expected to be incurred at various intervals over the next 15
years.
The economic life and the timing of the obligations are dependent on
Government legislation, commodity price and the future production
profiles of the respective production and development facilities. Note
that upon the acquisition of the Beatrice Field in November 2008, the
Corporation did not assume the decommissioning liabilities.
16. OTHER LONG TERM LIABILITIES
30 Sept 31 Dec
2012 2011
US$'000 US$'000
Balance, beginning of period 2,785 2,872
Revaluation in the period 116 (87)
Balance, end of period 2,901 2,785
On completion of the acquisition of the Beatrice Facilities on 10
November 2008 there were 75,000 barrels of oil in an oil storage tank
at the Nigg Terminal. This volume of oil is required to be in the
storage tank when the Beatrice Facilities are retransferred. This
volume of oil is valued at the price on the forward oil price curve at
the expected date of re-transfer and discounted. The liability is
subject to revaluation at each financial period end. The expected date
of re-transfer is likely to be more than three years in the future.
17. CONTINGENT CONSIDERATION
30 Sept 31 Dec
2012 2011
US$'000 US$'000
Balance, beginning of period 24,580 12,976
Additions - 13,604
Revision to estimates 1,295 (2,000)
Release (21,875) -
Balance, end of period 4,000 24,580
The contingent consideration at the end of the period relates to the
acquisition of the Stella field and is payable upon first oil.
The release of $21.9m reflects the consideration paid upon Stella and
Harrier Field Development Plan approval as well as a transfer of part
of the liability to Petrofac on completion of the Greater Stella Area
transactions (see note 11).
18. SHARE CAPITAL
No. of ordinary Amount
Authorised share capital 000 US$'000
At 31 December 2011 and 30 September 2012 Unlimited -
(a) Issued
The issued share capital is as follows:
Issued Number of common Amount
shares US$'000
Balance 1 January 2011 255,789,464 422,373
Issued for cash - options exercised 874,997 572
Issued for cash - warrants exercised 2,500,000 5,786
Transfer from Share based payment reserve on - 460
options exercised
Transfer from Warrants issued on warrants - 311
exercised
Balance 1 January 2012 259,164,461 429,502
Issued for cash - options exercised 181,667 250
Balance 30 September 2012 259,346,128 429,752
Capital Management
The Corporation's objectives when managing capital are:
- to safeguard the Corporation's ability to continue as a going
concern;
- to maintain balance sheet strength and optimal capital structure,
while ensuring the Corporation's strategicobjectives are met; and
- to provide an appropriate return to shareholders relative to the risk
of the Corporation's underlying assets.
Capital is defined as shareholders' equity. Shareholders' equity
includes share capital, share based payment reserve, warrants issued,
retained earnings or deficit and other comprehensive income.
30 Sept 31 Dec
2012 2011
US$'000 US$'000
Share capital 429,752 429,502
Share based payment reserve 19,610 17,318
Warrants issued - -
Retained earnings 108,642 60,591
Shareholders' Equity 558,004 507,411
The Corporation maintains and adjusts its capital structure based on
changes in economic conditions and the Corporation's planned
requirements. The Board of Directors reviews the Corporation's capital
structure and monitors requirements. The Corporation may adjust its
capital structure by issuing new equity and/or debt, selling and/or
acquiring assets, and controlling capital expenditure programs.
The Corporation monitors its capital structure using the debt-to-equity
ratio and other benchmark measures at the consolidated group level.
30 Sept 31 Dec
2012 2011
US$'000 US$'000
Debt - -
Equity 558,004 507,411
Debt as a % of equity N/A N/A
(b) Stock options
In the quarter ended 30 September 2012, the Corporation's Board of
Directors did not grant any new options.
In the quarter ended 31 March 2012, the Corporation's Board of
Directors granted 400,000 options at a weighted average exercise price
of $2.28 (C$2.31).
The Corporation's stock options and exercise prices are denominated in
Canadian Dollars when granted. As at 30 September 30 2012, 15,276,839
stock options to purchase common shares were outstanding, having an
exercise price range of $0.20 to $2.70 (C$0.25 to C$2.69) per share and
a vesting period of up to 3 years in the future.
Changes to the Corporation's stock options are summarised as follows:
30 September 2012 31 December 2011
Wt. Avg Wt. Avg
No. of Exercise No. of Exercise
Options Price* Options Price*
Balance, beginning of 17,506,839 $1.66 20,146,003 $1.61
period
Granted 400,000 $2.28 260,000 $1.99
Forfeited / expired (2,448,333) $3.42 (2,024,167) $2.29
Exercised (181,667) $0.75 (874,997) $0.61
Options 15,276,839 $2.52 17,506,839 $1.66
* 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 30 September 2012
Options Outstanding
Range of Exercise No. of Wt. Avg Wt. Avg
Price Options Life Exercise
(Years) Price*
$2.22-$2.70 (C$2.25-C$2.69)5,350,0002.3 $2.23
$1.49-$1.80 (C$1.54-C$1.85)5,136,6671.3 $1.55
$0.20-$0.81 (C$0.25-C$0.87)4,790,1721.0 $0.55
15,276,839 1.6 $1.48
Options Exercisable
Range of Exercise No. of Wt. Avg Wt. Avg
Price Options Life Exercise
(Years) Price*
$2.22-$2.70 (C$2.25-C$2.69)1,649,9972.2$2.23
$1.49-$1.80 (C$1.54-C$1.85)3,496,6701.2$1.54
$0.20-$0.81 (C$0.25-C$0.87)4,720,1721.0$0.49
9,866,8391.3$1.22
The following is a summary of stock options as at 31 December 2011
Options Outstanding
Range of Exercise No. of Wt. Avg Wt. Avg
Price Options Life Exercise
(Years) Price*
$3.65 (C$3.65)
$2.22-$2.70 2,165,000 0.1$3.65
(C$2.25-C$2.69)
$1.49-$1.79 5,050,000 3.0$2.23
(C$1.54-C$1.85)
$0.20-$0.81 5,311,667 2.0$1.55
(C$0.25-C$0.87) 4,980,172 1.8$0.56
17,506,839 0.5$1.72
Options Exercisable
Range of Exercise No. of Wt. Avg Wt. Avg
Price Options Life Exercise
(Years) Price*
$3.65 (C$3.65) 2,165,000 0.1 $3.65
$2.22-$2.86 1,663,330 3.0 $2.22
(C$2.25-C$2.70)
$1.49-$1.79 2,048,329 1.8 $1.57
(C$1.54-C$1.85)
$0.20-$0.81 3,904,548 1.8 $0.49
(C$0.25-C$0.87)
9,781,207 1.6 $1.71
(c) Share based payments
Options granted are accounted for using the fair value method. The
compensation cost during the three months and nine months ended 30
September 2012 for total stock options granted was $0.8 million and
$2.4 million respectively (Q3 2011: $1.6 million, Q3 YTD: $4.8
million). $0.1 million and $0.4 million were charged through the income
statement for share based payment for the three and nine months ended
30 September 2012 respectively, being the Corporation's share of share
based payment chargeable through the income statement. The remainder of
the Corporation's share of share based payment has been capitalised.
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 30 For the year ended 31
September 2012 December 2011
Risk free 0.50% 1.20%
interest rate
Expected stock 81% 97%
volatility
Expected life of 3 years 3 years
options
Weighted Average $1.22 $1.68
Fair Value
(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 20 September 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 3 March 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 $0.3
million.
19. SHARE BASED PAYMENT RESERVE
30 Sept 31 Dec
2012 2011
US$'000 US$'000
Balance, beginning of period 17,318 11,427
Share based payment cost 2,399 6,351
Transfer to share capital on exercise of options (107) (460)
Balance, end of period 19,610 17,318
20. EARNINGS PER SHARE
The calculation of basic earnings per share is based on the profit
after tax and the weighted average number of common shares in issue
during the period. The calculation of diluted earnings per share is
based on the profit after tax and the weighted average number of
potential common shares in issue during the period.
Three months ended 30 Nine months ended 30
Sept Sept
2012 2011 2012 2011
Weighted average number 259,346,128 258,535,295 259,236,730 257,691,879
of common shares
(basic)
Weighted average 264,573,365 263,211,406 264,632,244 262,979,178
numbers of common
shares (diluted)
21. TAXATION
Restated Restated
Three months ended 30 Sept Nine months ended 30 Sept
2012 2011 2012 2011
US$'000 US$'000 US$'000 US$'000
Deferred tax 2,924 15 10,575 (3,597)
The above includes 2011 business combination restatements in accordance
with IFRS 3®. Refer to note 2 for further details.
22. COMMITMENTS
Operating lease commitments 30 Sept 31 Dec
2012 2011
US$'000 US$'000
Within one year 259 247
Two to five years 1,035 989
More than five years 129 309
Capital commitments 30 Sept 31 Dec
2012 2011
US$'000 US$'000
Capital commitments incurred jointly with other 126,751 82,521
ventures (Ithaca's share)
23. 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 utilise observable market data.
In addition to market information, the Corporation incorporates
transaction specific details that market participants would utilise in
a fair value measurement, including the impact of non-performance risk.
The Corporation characterises inputs used in determining fair value
using a hierarchy that prioritises 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 realised 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 utilises the most observable
inputs available for valuation purposes. If a fair value measurement
reflects inputs of different levels within the hierarchy, the
measurement is categorised 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
categorised as Level 2.
The following table presents the Corporation's material financial
instruments measured at fair value for each hierarchy level as of 30
September 2012:
Total Fair
Level 1 Level 2 Level 3 Value
US$'000 US$'000 US$'000 US$'000
Derivative financial instrument - 8,580 - 8,580
assets
Long term liability on Beatrice - - (2,901) (2,901)
acquisition
Contingent consideration - (4,000) - (4,000)
The table below presents the total gain / (loss) on financial
instruments that has been disclosed through the statement of net and
comprehensive income:
Three months ended Nine months ended
30 Sept 30 Sept
2012 2011 2012 2011
US$'000 US$'000 US$'000 US$'000
Revaluation of forex forward 166 - 707 -
contracts
Revaluation of gas contract 610 2,315 1,368 3,339
Revaluation of other long term (86) 332 (115) 478
liability
Revaluation of commodity hedges (13,617) (2,250) 3,241 (5,477)
(12,927) 397 5,201 (1,660)
Realised gain/(loss) on 888 - 2,597 (493)
commodity hedges
Realised gain on forex forward 50 - 118 -
contracts
938 - 2,715 (493)
Contingent consideration - - (1,295) -
Total gain/(loss) on financial (11,989) 397 6,621 (2,153)
instruments
The Corporation has identified that it is exposed principally to these
areas of market risk.
i) Commodity Risk
The table below presents the total gain / (loss) on commodity hedges
that has been disclosed through the statement of net and comprehensive
income:
Three months ended 30 Sept
2012 2011
US$'000 US$'000
Revaluation of commodity hedges (13,617) (2,250)
Realised gain on commodity hedges 888 -
Total (loss) on commodity hedges (12,729) (2,250)
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 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.
In Q2 2011 the Corporation purchased a put option with a floor price of
$115 / barrel for 300,000 barrels of 2011 production. The option
delivers a minimum price on the specified volume of oil and allows the
Corporation to benefit from any upside above $115 / barrel.
In February 2012, the Corporation entered into two swap options: to
sell 268,800 bbls of the Corporation's March 2012 -December 2012
forecast production at a fixed price of $121.32/bbl; and to sell
500,000 bbls of the Corporation's forecast July 2012 - June 2013
production at $113.25 per barrel.
In April 2012, the Corporation entered into two put options: to sell
190,000 bbls of the Corporation's May 2012 - February 2013 forecast
production at a fixed price of $120.50/bbl and 200,000 bbls at a fixed
price of $120/bbl.
In August 2012 the Corporation entered into further derivatives for the
period October 2012 to December 2013, being swaps of 503,800 bbls of
oil at a weighted average price of $108.67 and put options, at market
price, for 300,300 bbls of oil at a weighted average oil price floor of
$111.34 / bbl.
ii) Interest Risk
Calculation of interest payments for the Senior Secured Borrowing Base
Facility agreement with BNP Paribas that was signed on 29 June 2012
incorporates LIBOR. The Corporation will therefore be exposed to
interest rate risk to the extent that LIBOR may fluctuate. The
Corporation will evaluate its annual forward cash flow requirements on
a rolling monthly basis. No funds are currently drawn down under the
facility.
iii) Foreign Exchange Rate Risk
The table below presents the total (loss) on foreign exchange financial
instruments that has been disclosed through the statement of net and
comprehensive income:
Three months ended 30 Sept
2012 2011
US$'000 US$'000
Revaluation of foreign exchange forward contracts 166 -
Realised gain on foreign exchange forward contracts 50 -
Total gain on forex forward contracts 216 -
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 29 November 2011, the Corporation entered into a contract with
Lloyds Banking Group to hedge its forecast British Pounds Sterling 2012
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/GBP1.0 and a trigger rate of USD1.40/GBP1.
00. The contract expires in December 2012.
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.
All of its oil production from the Beatrice, Jacky and Athena fields is
sold to BP Oil International Limited. Oil production from Cook and
Broom is sold to Shell Trading International Ltd. Anglia and Topaz gas
production is currently sold through three contracts to RWE NPower PLC
and Hess Energy Gas Power (UK) Ltd. Cook gas is sold to Shell UK Ltd
and Esso Exploration & Production 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 30 September 2012 99% of
accounts receivables are current, being defined as less than 90 days.
The Corporation has no allowance for doubtful accounts as at 30
September 2012 (31 December 2011: $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 30 September 2012, exposure is $8.6
million (31 December 2011: $Nil).
The Corporation also has credit risk arising from cash and cash
equivalents held with banks and financial institutions. The maximum
credit exposure associated with financial assets is the carrying
values.
v) Liquidity Risk
Liquidity risk includes the risk that as a result of its operational
liquidity requirements the Corporation will not have sufficient funds
to settle a transaction on the due date. The Corporation manages
liquidity risk by maintaining adequate cash reserves, banking
facilities, and by considering medium and future requirements by
continuously monitoring forecast and actual cash flows. The Corporation
considers the maturity profiles of its financial assets and
liabilities. As at 30 September substantially all accounts payable are
current.
The following table shows the timing of cash outflows relating to trade
and other payables.
Within 1 year 1 to 5 years
US$'000 US$'000
Accounts payable and accrued liabilities 199,334 -
Other long term liabilities - 2,901
199,334 2,901
24. DERIVATIVE FINANCIAL INSTRUMENTS
30 Sept 31 December
2012 2011
US$'000 US$'000
Oil swaps 2,054 -
Put options 6,338 -
Embedded derivative - (1,336)
Foreign exchange forward contract 188 (510)
8,580 (1,846)
In August 2012 the Corporation entered into derivatives for the period
October 2012 to December 2013, being swaps of 503,800 bbls of oil at a
weighted average price of $108.67 and put options, at market price, for
300,300 bbls of oil at a weighted average oil price floor of $111.34 /
bbl.
In February 2012, the Corporation entered into two swap options: to
sell 268,800 bbls of the Corporation's March 2012 -December 2012
forecast production at a fixed price of $121.32/bbl; and to sell
500,000 bbls of the Corporation's forecast July 2012 - June 2013
production at $113.25 per barrel.
In April 2012, the Corporation entered into two put options: to sell
190,000 bbls of the Corporation's May 2012 - February 2013 forecast
production at a fixed price of $120.50/bbl and 200,000 bbls at a fixed
price of $120/bbl.
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 recognised 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.
In Q2 2011 the Corporation entered into a further 'put' option to sell
300,000 barrels of the Corporation's 2011 forecast production at $115 /
bbl. This is recognised at its fair value in the financial statements.
Fair value represents the difference between the contract price and the
period end market price for the contracted volumes.
In Q4 2010, the Corporation acquired an embedded derivative within an
Anglia gas sales contract. This is recognised at its fair value in the
financial statements. Fair value represents the difference between the
contract price and the period end market price for the contracted
volumes.
25. FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES
Financial instruments of the Corporation consist mainly of cash and
cash equivalents, receivables, payables, loans and financial derivative
contracts, all of which are included in these financial statements. At
30 September 2012, the classification of financial instruments and the
carrying amounts reported on the balance sheet and their estimated fair
values are as follows:
30 September 2012 31 December 2011
US$'000 US$'000
Classification Carrying Fair Carrying Fair
Amount Value Amount Value
Cash and cash equivalents (Held for 56,843 56,843 95,545 95,545
trading)
Restricted cash 20,560 20,560 16,510 16,510
Derivative financial instruments 8,580 8,580 - -
(Held for trading)
Accounts receivable (Loans and 147,349 147,349 80,960 80,960
Receivables)
Deposits 6,593 6,593 8,793 8,793
Contingent consideration 4,000 4,000 24,580 24,580
Derivative financial instruments - - 1,846 1,846
(Held for trading)
Other long term liabilities 2,901 2,901 2,785 2,785
Accounts payable (Other financial 199,334 199,334 102,136 102,136
liabilities)
26. RELATED PARTY TRANSACTIONS
The consolidated financial statements include the financial statements
of Ithaca Energy Inc and the subsidiaries listed in the following
table:
Country of % equity interest at
incorporation 30 Sept
2012 2011
Ithaca Energy (UK) Limited Scotland 100% 100%
Ithaca Minerals (North Sea) Scotland 100% Nil
Limited
Ithaca Energy (Holdings) Bermuda 100% Nil
Limited
Transactions between subsidiaries are eliminated on consolidation.
The following table provides the total amount of transactions that have
been entered into with related parties during the nine month period
ending 30 September 2012 and 30 September 2011, as well as balances
with related parties as of 30 September 2012 and 31 December 2011:
Sales Purchases Accounts Accounts
receivable payable
US$'000 US$'000 US$'000 US$'000
Burstall Winger 2012 - 138 - -
LLP
2011 - 186 - -
Loans to related parties Amounts owed from related parties
30 Sept 31 Dec
2012 2011
US$'000 US$'000
FPF-1 Limited 2012 21,551 -
27. SEASONALITY
The effect of seasonality on the Corporation's financial results for
any individual quarter is not material.
28. POST BALANCE SHEET EVENTS
In October the Company announced that it had entered into agreements
with Noble Energy Capital Limited (a subsidiary of Noble Energy Inc.,
NYSE: NBL) to acquire two wholly owned UK subsidiary companies that
will hold non-operated interests in UK North Sea producing fields; a
12.885% interest in the Cook field and a 14% interest in the MacCulloch
field.
Completion of the transactions is anticipated in early 2013 and is
subject to normal regulatory and joint venture approvals, including
reaching agreement in respect of decommissioning cost security.
The Company anticipates that the resulting net cash consideration
payable at completion will be under $30 million, based on the January
1, 2012 effective date and assuming completion occurs in early 2013.
This information is provided by RNS
The company news service from the London Stock Exchange
END
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