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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Ithaca Energy | LSE:IAE | London | Ordinary Share | CA4656761042 | COM SHS NPV (DI) |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 110.75 | 0.00 | 01:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
From Apr 2019 to Apr 2024
TIDMIAE
RNS Number : 0294P
Ithaca Energy Inc
14 November 2016
Not for Distribution to U.S. Newswire Services or for Dissemination in the United States
Ithaca Energy Inc.
Third Quarter 2016 Financial Results
14 November 2016
Ithaca Energy Inc. (TSX: IAE, LSE AIM: IAE) ("Ithaca" or the "Company") announces its quarterly financial results for the three months ended 30 September 2016 ("Q3-2016" or the "Quarter") and the nine months ended 30 September 2016 ("YTD-2016").
Highlights
Solid cashflow generation in the first nine months of the year
-- Average production of 9,585 boepd - ahead of 9,000 boepd guidance
-- Further unit operating cost reductions - currently running at $23/boe, under the previously lowered full year guidance of $25/boe, and set to reduce further upon Stella start-up
-- $117 million cashflow from operations, driven by reduced operating costs and hedging (cashflow per share $0.28)
-- Earnings of $12 million excluding non-cash mark-to-market of future hedges and non-cash accounting tax charge resulting from reduction in UK tax rates(1)
Strong liquidity position
-- Additional commodity price hedging executed - extends and enhances the downside protection below $50/bbl while retaining upside exposure
-- Continued deleveraging ahead of Stella start up with net debt reduced from a peak of over $800 million in the first half of 2015 to $598 million at 30 September 2016
-- Completed semi-annual RBL redetermination in October 2016 with over $110 million of funding headroom - total debt availability in excess of $710 million
Exciting outlook - nearing material step-change in the business
-- Stella first hydrocarbons anticipated around the end of November 2016 - vessel hook-up programme completed and offshore commissioning and preparation for start-up well advanced
-- Production set to more than double to 20-25,000 boepd and unit operating costs to reduce to under $20/boe with start-up of production from the Stella field
-- Oil export pipeline laid and initial tie-in works completed, allowing switch from tanker loading to pipeline export during 2017 - reduces fixed operating costs, enhances operational uptime and improves reserves recovery
-- Completed additional acquisitions in the "Vorlich" discovery, increasing Ithaca's position to approximately 33%(2)
-- Acquired a 75% interest and operatorship in the nearby "Austen" discovery
-- Increasing financial flexibility - focus on delivering continued deleveraging of the business within a balanced capital investment programme
Les Thomas, Chief Executive Officer, commented:
"The business has continued to perform in line with the strong momentum achieved over recent quarters. Production is running ahead of guidance, operating costs are coming in lower than forecast and we continue deleveraging the business. Significant progress has been made with the offshore commissioning programme on Stella and we are fast approaching start-up of the field. As such, we remain sharply focused on ensuring all the commissioning tasks are fully completed as planned in order to deliver a safe and efficient ramp-up of production from the field."
Greater Stella Area Development
Significant progress has been made on the final stages of the Stella development programme since the FPF-1 floating production facility departed Poland in August 2016. The FPF-1 was safely towed to the field, moored on location and the dynamic risers and umbilical connecting the subsea infrastructure to the vessel installed. The subsea commissioning programme has recently been completed by Technip, with all the infield flowlines flushed and ready for the start-up of production. Connection and operational trials for the "Single Anchor Loading" system have also been completed for the fleet of shuttle tankers that are available for oil exports from the FPF-1.
The FPF-1 offshore commissioning programme is on-going, involving preparation of the topsides processing and utility systems for the introduction of hydrocarbons. This work is well advanced, with the operations team focused on completing the required inspections and associated readiness activities required to enable a safe and efficient start-up of the wells. It is anticipated that this work will be completed around the end of this month and enable start-up of Stella production.
As previously reported, significant progress has also been made during the Quarter on the work programme associated with switching from tanker loading to oil pipeline exports for the Greater Stella Area in 2017. Following installation of a connection point on the Norpipe system in summer 2016, a 44 kilometre spurline from the FPF-1 to the Norpipe system was successfully installed in September 2016. The key outstanding activities that now remain to be completed are the manufacture and installation of pipeline export pumps on the FPF-1 and the final subsea connections that need undertaking immediately prior to the switchover.
GSA Satellite Acquisitions
In October 2016 the Company completed the previously announced acquisition of 100% of licence P1588 (Block 30/1f) from ENGIE E&P UK Limited ("ENGIE E&P"), INEOS UK SNS Limited and Maersk Oil North Sea Limited.
Licence P1588 contains approximately 10-20% of the Vorlich discovery, with the balance of the discovery located in licence P363 (Block 30/1c). When taking into account the P363 licence interest acquired from TOTAL E&P UK Limited in January 2016, these transactions increase Ithaca's overall interest in the Vorlich discovery by around 16%, to approximately 33%.
Completion of the other satellite acquisition, ENGIE E&P's 75% interest and operatorship in the "Austen" discovery, is anticipated prior to the end of the year.
Production & Operations
The producing asset portfolio has performed well over YTD-2016, with production running ahead of guidance largely as a result of solid performance from the Cook field. Average YTD-2016 production was 9,585 boepd (92% oil).
It is anticipated that full year base production, excluding any contribution from the start-up of the Stella field during 2016, will be modestly ahead of the 9,000 boepd guidance range.
During the final quarter of the year base production volumes will be reduced compared to the previous quarters as a result of the planned maintenance shutdown of the Brent Pipeline System that serves the Company's Northern North Sea fields, which is now expected to take approximately four weeks.
Financials
Cashflow from Operations
Despite continued weakness in commodity prices over the period, the business has delivered YTD-2016 cashflow from operations of $117 million. This performance highlights the benefit of the commodity hedges the Company has in place and significant operating costs savings that have been secured through re-setting of the cost base.
Hedging
During the recent pick-up in Brent prices the Company extended its commodity hedging position by a further 1.5 million barrels of 2017 oil production. Of this volume half has been hedged using collars with a floor price of $46/bbl and a celling price of $60/bbl and the other half has been hedged using put options with a floor price of $53/bbl.
Taking into account the additional volumes, the Company now has 7,800 boepd (71% oil) hedged at an average floor price of $52/boe for the 15 months to December 2017. Full commodity price upside exposure has been retained on 50% of the volumes hedged and upside exposure to $60/boe has been retained on a further 20%.
Operating Expenditure
Over the course of 2016 operating costs have continued the downward trend established in 2015, with the business delivering a YTD-2016 unit operating expenditure of $23/boe. This is under the previously lowered full year guidance for the existing producing asset base of $25/boe and represents a substantial 23% saving on the $30/boe level originally forecast for the existing producing asset base at the start of the year. Following the start-up of production from the Stella field this cost is forecast to reduce to under $20/boe, reflecting the lower unit operating costs associated with the field.
Capital Expenditure
Total capital expenditure in 2016 is now forecast to increase from $50 million to $60 million. This increase is a result of the accelerated GSA oil export pipeline installation operations, the total project cost of which remains unchanged. Of the total 2016 expenditure approximately $50 million is expected to be paid this year, with the balance due in 2017.
Net Debt
The Company has continued to delever the business ahead of first hydrocarbons from the Stella field, with net debt reduced to $598 million at 30 September 2016; down $67 million since the start of the year and over $200 million since its peak in the first half of 2015.
During October 2016 the Company completed its semi-annual reserves based lending ("RBL") facilities review, resulting in an available RBL borrowing capacity of over $410 million. When combined with the $300 million senior unsecured notes that are in place, the business has a total debt capacity of over $710 million.
Tax
The Company had a UK tax allowances pool of over $1,750 million at 30 September 2016. At current commodity prices the pool is forecast to shelter the Company from the payment of corporation tax over the medium term.
During the year the UK government reduced Corporation Tax rates levied on E&P companies by 10% and effectively abolished Petroleum Revenue Tax charges. As a result of these changes, the last of which was enacted during the Quarter, a one-off non-cash deferred tax charge of $61.7 million is reflected in the YTD-2016 Income Statement.
Q3-2016 Financial Results Conference Call
A conference call and webcast for investors and analysts will be held today at 12.00 GMT (07.00 EST). Listen to the call live via the Company's website (www.ithacaenergy.com) or alternatively dial-in on one of the following telephone numbers and request access to the Ithaca Energy conference call: UK +44 203 059 8125; Canada +1 855 287 9927; US +1 855 442 0877. A short presentation to accompany the results will be available on the Company's website prior to the call.
Glossary
boe Barrels of oil equivalent boepd Barrels of oil equivalent per day RBL Reserves Based Lending facility
The unaudited consolidated financial statements of the Company for the three and nine month periods ended 30 September 2016 and the related Management Discussion and Analysis are available on the Company's website (www.ithacaenergy.com) and on SEDAR (www.sedar.com). All values in this release and the Company's financial disclosures are in US dollars, unless otherwise stated.
-S -
Enquiries:
Ithaca Energy
Les Thomas lthomas@ithacaenergy.com +44 (0)1224 650 261
Graham Forbes gforbes@ithacaenergy.com +44 (0)1224 652 151
Richard Smith rsmith@ithacaenergy.com +44 (0)1224 652 172
FTI Consulting
Edward Westropp edward.westropp@fticonsulting.com +44 (0)203 727 1521
Kim Camilleri kim.camilleri@fticonsulting.com +44 (0)203 727 1349
Cenkos Securities
Neil McDonald nmcdonald@cenkos.com +44 (0)207 397 1953
Nick Tulloch ntulloch@cenkos.com +44 (0)131 220 9772
Beth McKiernan bmckiernan@cenkos.com +44 (0)131 220 9778
RBC Capital Markets
Matthew Coakes matthew.coakes@rbccm.com +44 (0)207 653 4000
Notes
1. Year to date earnings loss of $64.4 million adjusted by the total loss on financial instruments of $25.3 million (less tax at 40%) and one-off non-cash deferred tax charges of $61.7 million arising from changes in UK tax rates during the year.
2. The Vorlich field interest reflects assumed unitisation across licences P1588 and P363.
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 and gas industry.
References herein to barrels of oil equivalent ("boe") are derived by converting gas to oil in the ratio of six thousand cubic feet ("Mcf") of gas to one barrel ("bbl") of oil. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy 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, utilising a conversion ratio at 6 Mcf: 1 bbl may be misleading as an indication of value.
About Ithaca Energy
Ithaca Energy Inc. (TSX: IAE, LSE AIM: IAE) is a North Sea oil and gas operator focused on the delivery of lower risk growth through the appraisal and development of UK undeveloped discoveries and the exploitation of its existing UK producing asset portfolio. Ithaca's strategy is centred on generating sustainable long term shareholder value by building a highly profitable 25kboe/d North Sea oil and gas company. For further information please consult the Company's website www.ithacaenergy.com.
Non-IFRS Measures
"Cashflow from operations" and "cashflow per share" referred to in this press release are not prescribed by IFRS. These non-IFRS financial measures do not have any standardised meanings and therefore are unlikely to be comparable to similar measures presented by other companies. The Company uses these measures to help evaluate its performance. As an indicator of the Company'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 Company considers cashflow from operations to be a key measure as it demonstrates the Company'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.
"Net debt" referred to in this press release is not prescribed by IFRS. The Company uses net drawn debt as a measure to assess its financial position. Net drawn debt includes amounts outstanding under the Company's debt facilities and senior notes, less cash and cash equivalents.
Forward-looking Statements
Some of the statements and information in this press release are forward-looking. Forward-looking statements and forward-looking information (collectively, "forward-looking statements") are based on the Company'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, drilling, construction and maintenance times, well completion times, risks associated with operations, required regulatory, partner and other third party approvals, commodity prices, future capital expenditures, continued availability of financing for future capital expenditures, future acquisitions and dispositions and cash flow. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. When used in this press release, the words and phrases like "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe", "could", "target", "in the process of", "on track" ,"set to" and similar expressions, and the negatives thereof, whether used in connection with operational activities, the planned activities and durations associated with the FPF-1 offshore commissioning and hook-up programme, the anticipated timing of Stella first hydrocarbons, production forecasts, projected operating costs, anticipated capital expenditures and capital programme, anticipated effects of securing access to the GSA oil export pipeline and the expected timing of securing such access, the anticipated timing of completion of the Austen license acquisition, assumed unitisation across licences P1588 and P363 containing the Vorlich discovery, portfolio investment opportunities, expected tax horizon of the Company, planned maintenance shutdowns and the effects thereof, or otherwise, are intended to identify forward-looking statements. Such statements are not promises or guarantees, and are subject to 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. The Company believes that the expectations reflected in those forward-looking statements 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 included in this press release should not be unduly relied upon. These forward-looking statements speak only as of the date of this press release. Ithaca Energy Inc. expressly disclaims any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement contained herein to reflect any change in its expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based except as required by applicable securities laws.
Additional information on these and other factors that could affect Ithaca's operations and financial results are included in the Company's Management Discussion and Analysis for the three and nine month periods ended 30 September 2016 and the Company's Annual Information Form for the year ended 31 December 2015 and in reports which are on file with the Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).
Hot Features
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2016 THIRD QUARTER HIGHLIGHTS
===================================================================
Solid cashflow
generation in * Average production for nine months to 30 September
the first 9 months 2016 ("YTD 2016") of 9,585 boepd - ahead of guidance
of the year
* Further unit operating cost reductions - currently
running at $23/boe, under the previously lowered full
year guidance of $25/boe prior to Stella start-up,
$20/boe post Stella start-up
* $117 million cashflow from operations, driven by
reduced operating costs and hedging (cashflow per
share $0.28)
* Earnings of $12 million excluding non-cash
mark-to-market of future hedges and non-cash
accounting tax charge resulting from reduction in UK
tax rates
-------------------------------------------------------------------
Strong liquidity
position * Additional commodity price hedging put in place,
extending and enhancing the downside protection below
$50/bbl while retaining upside exposure
* Continued deleveraging ahead of Stella start up with
net debt reduced from a peak of over $800 million in
the first half of 2015 to $598 million at 30
September 2016
* Completed semi-annual RBL redetermination in October
2016 with over $110 million of funding headroom -
total debt availability in excess of $710 million
-------------------------------------------------------------------
Exciting outlook
- nearing material * Stella first hydrocarbons anticipated around the end
step-change in of November 2016 - vessel hook-up programme completed
the business and offshore commissioning and preparation for
start-up well advanced
* Production set to more than double to 20-25,000 boepd
and unit operating costs to reduce to under $20/boe
with start-up of production from the Stella field
* Oil export pipeline laid and initial tie-in works
completed, allowing switch from tanker loading to
pipeline export during 2017 - reduces fixed operating
costs, enhances operational uptime and improves
reserves recovery
* Completed the additional acquisitions in the
"Vorlich" discovery, increasing Ithaca's position to
approximately 33%
* Acquired a 75% interest and operatorship in the
nearby "Austen" discovery
* Increasing financial flexibility - focus on
delivering continued deleveraging of the business
within a balanced capital investment programme
SUMMARY STATEMENT OF INCOME
============================================================================================
3-Months Ended 30 September 9-Months Ended 30 September
2016 2015 2016 2015
Average
Production kboe/d 10.0 11.9 9.6 12.4
Average
Realised Oil
Price(1) $/bbl 44 51 42 57
Revenue(2) M$ 39.0 46.8 107.7 163.2
Commodity
Hedging Cash
Gain M$ 18.1 35.1 76.1 145.2
Revenue(2)
(Incl. Cash
Hedging
Gain) M$ 57.1 81.9 183.8 308.4
Opex M$ (19.1) (25.8) (61.1) (83.4)
G&A M$ (0.8) (2.6) (3.8) (7.6)
Foreign
Exchange(3) M$ (2.1) 3.0 (2.3) (0.7)
Cashflow from
Operations M$ 35.1 56.6 116.8 216.8
DD&A M$ (21.7) (30.9) (59.1) (93.2)
Non-Cash
Hedging
(Loss)/Gain M$ (10.9) 39.1 (96.1) (52.4)
Finance Costs M$ (9.1) (9.5) (27.5) (30.4)
Other
Non-Cash
Costs M$ (0.2) 0.2 (1.3) (3.7)
Taxation -
Excluding
Rate Changes M$ 10.9 (12.7) 64.7 61.0
- Reduced Tax
Rates Impact M$ (74.7) - (61.7) (41.5)
Earnings M$ (70.7) 42.8 (64.4) 56.6
Adjusted
Earnings (4) M$ 2.3 (2.1) 12.4 41.6
Cashflow Per
Share $/Sh. 0.09 0.17 0.28 0.66
Earnings Per
Share $/Sh. (0.17) 0.13 (0.16) 0.17
Adjusted
Earnings Per
Share(4) $/Sh. 0.01 (0.01) 0.03 0.13
(1) Average realised price before hedging
(2) Revenue net of stock movements
(3) Foreign exchange net of related realised hedging
gains & losses
(4) Earnings per share adjusted to exclude impact of
reduced tax rates and mark-to-market of future hedges
SUMMARY BALANCE SHEET
============================================================================================
M$ 30 Sep. 31 Dec.
2016 2015
Cash & Equivalents 30 12
Other Current Assets 285 372
PP&E 1,120 1,113
Deferred Tax Asset 357 356
Other Non-Current
Assets 210 211
Total Assets 2,001 2,063
Current Liabilities (309) (283)
Borrowings (620) (666)
Asset Retirement Obligations (233) (227)
Other Non-Current
Liabilities (107) (93)
Total Liabilities (1,270) (1,270)
Net Assets 731 793
Share Capital 618 617
Other Reserves 25 23
Surplus 89 153
Shareholders' Equity 731 793
CORPORATE STRATEGY
=============================================================
Ithaca Energy Inc. ("Ithaca" or the "Company") is a
North Sea oil and gas operator focused on the delivery
of lower risk growth through the appraisal and development
of UK undeveloped discoveries and the exploitation
of its existing UK producing asset portfolio.
Ithaca's goal is to generate sustainable long term
shareholder value by building a highly profitable 25kboepd
North Sea oil and gas company.
Execution of the Company's strategy is focused on the
following core activities:
* Maximising cashflow and production from the existing
asset base
* Delivering first hydrocarbons from the Ithaca
operated Greater Stella Area development
* Delivery of lower risk, long term development led
growth through the appraisal of undeveloped
discoveries
* Continuing to grow and diversify the cashflow base by
securing new producing, development and appraisal
assets through targeted acquisitions and licence
round participation
* Maintaining capital discipline, financial strength
and a clean balance sheet, supported by lower cost
debt leverage
CORPORATE ACTIVITIES
------------------------------------------------------------
DEBT FACILITIES
Planned October In October 2016 the Company successfully completed
2016 RBL redetermination its routine semi-annual reserves based lending ("RBL")
successfully facilities review, maintaining in excess of $110 million
completed - over of funding headroom.
$110M of headroom The Company completes a semi-annual redetermination
in place process with its RBL bank syndicate, at the end of
April and October, to review the borrowing capacity
of its assets based on the technical and commodity
price assumptions applied by the syndicate. Following
the October 2016 redetermination, the Company's available
RBL borrowing capacity is over $410 million. When combined
with the $300 million senior unsecured notes the Company
has in place, the business has a total debt capacity
of over $710 million. This compares to net debt at
the end of Q3 2016 of $598 million.
The Company is focused on maintaining a solid liquidity
position, with substantial deleveraging having already
been delivered even before first hydrocarbons from
the GSA. Total RBL bank debt has been reduced by over
40% from a peak of over $500 million in the first half
of 2015 to $298 million at the end of Q3 2016. A robust
financial position has been retained during the current
period of lower and more volatile oil prices as a result
of various proactive measures taken to increase the
financial strength of the business and ensure that
the Company has sufficient flexibility to manage downside
risks.
As a consequence of the substantial deleveraging, the
Company elected to reduce the size of the debt facilities
from $650 million to $535 million in June 2016, saving
approximately $0.5 million in commitment fees for the
remainder of the year. This change has no effect on
the current RBL debt capacity of approximately $410
million, as this is below the reduced facility size
of $535 million.
Both RBL facilities are based on conventional oil and
gas industry borrowing base financing terms, neither
of which have historic financial covenant tests. The
Company's $300 million senior unsecured notes, due
July 2019, similarly have no historic financial covenant
tests.
PRODUCTION & OPERATIONS
-------------------------------------------------------------
The producing asset portfolio has performed well over
YTD 2016 production YTD 2016, with production running ahead of guidance
running ahead largely as a result of continuing solid performance
of full year from the Cook field. Average production for YTD 2016
guidance was 9,585 boepd, 92% oil (YTD 2015: 12,355 boepd),
which compares to full year base production guidance
of approximately 9,000 boepd.
When comparing YTD 2016 with the same period in 2015,
production has reduced by approximately 22%. This reflects
the specific steps taken in 2015 to reposition the
portfolio to meet the requirements of the lower Brent
price environment, namely the cessation of production
from the Athena and Anglia fields, and no significant
investment in the existing production portfolio as
a consequence of the prevailing uncertainty and volatility
in oil prices. Production rates were also restricted
on the Pierce field during the first half of 2016 due
to the requirement to complete remedial works on the
field's subsea gas injection flowline.
The majority of the planned 2016 operational programmes
on the producing asset portfolio have now been completed,
with only the Brent System maintenance shutdown that
is now scheduled for approximately four weeks commencing
in November 2016 remaining outstanding. This shutdown
will impact production from the Company's Northern
North Sea fields and result in a reduced base production
volumes compared to the previous nine months of the
year.
It is anticipated that full year base production, excluding
any contribution from the start-up of the Stella field
during 2016, will be modestly ahead of the 9,000 boepd
guidance. The additional production contribution resulting
from the start-up of Stella will depend on the exact
timing of first hydrocarbons from the field.
GREATER STELLA AREA DEVELOPMENT
-----------------------------------------------------------------
GSA "hub and Ithaca's focus on the GSA is driven by the monetisation
spoke" strategy of over 30MMboe of net 2P reserves within the existing
portfolio and the generation of additional value via
the wider opportunities provided by the range of undeveloped
discoveries surrounding the Ithaca operated production
hub.
The development involves the creation of a production
hub based on deployment of the FPF-1 floating production
facility located over the Stella field, with onward
export of oil and gas. To maximise initial oil and
condensate production and fill the gas processing facilities
on the FPF-1, the hub will start-up with five Stella
wells. It is anticipated that further wells will then
be drilled and tied back to the FPF-1 on the wider
GSA satellite portfolio to maintain the gas processing
facilities on plateau.
Stella Development Programme
GSA development Following the successful completion of the Stella drilling
activities are and subsea infrastructure installation programme in
at an advanced 2015, the focus of the development activities has been
stage of completion firmly centred on concluding the FPF-1 floating production
- Stella production facility modifications programme being undertaken by
start-up scheduled Petrofac in the Remontowa shipyard in Gdansk, Poland.
for around
end-November Since departing Poland in August 2016 the FPF-1 was
2016 safely towed to the field, moored on location and the
dynamic risers and umbilical connecting the subsea
infrastructure to the vessel installed. The subsea
commissioning programme has recently been completed
by Technip, with all the infield flowlines flushed
and ready for the start-up of production. Connection
and operational trials for the "Single Anchor Loading"
system have also been completed for the fleet of shuttle
tankers that are available for oil exports from the
FPF-1.
The FPF-1 offshore commissioning programme is on-going,
involving preparation of the topsides processing and
utility systems for the introduction of hydrocarbons.
This work is well advanced, with the operations team
focused on completing the required inspections and
associated readiness activities required to enable
a safe and efficient start-up of the wells. It is anticipated
that this work will be completed around the end of
November and enable start-up of Stella production.
The Stella field start-up process initially involves
the introduction of hydrocarbons to the FPF-1 from
one well in order to commission and stabilise the processing
systems on the vessel and commence the export of oil
to adjacent shuttle tanker. Gas will initially be flared
while the fuel gas system is commissioned and the switch
is made from diesel to gas powered generation on the
vessel. Following this, the processed gas will be directed
to the compressors for onward export into the CATS
pipeline. Upon concluding this start-up process, the
other wells on the field will be opened up, commencing
the production ramp-up phase over the following few
weeks and the ultimate optimisation of production across
the wells.
GSA OIL EXPORT PIPELINE
Access to oil Access to the Norpipe oil pipeline system has been
export pipeline secured for future GSA production, allowing a switch
secured from from tanker loading during 2017. This move will significantly
2017, reducing reduce the fixed operating costs of the GSA facilities
fixed operating and enhance operational uptime, resulting in improved
costs and increasing reserves recovery and increasing the long term value
the long term of the GSA as a production hub.
value of the The key work associated with creating a connection
GSA to the Norpipe system was successfully executed as
part of a fast-track operational programme undertaken
during the planned summer 2016 pipeline maintenance
shutdown. Following this, the 44 kilometre spurline
from the FPF-1 to the Norpipe system was installed
in September 2016. The key outstanding activities that
now remain to be completed are the manufacture and
installation of pipeline export pumps on the FPF-1
and the final subsea connections that need undertaking
immediately prior to the switchover.
Norpipe runs approximately 350 kilometres from the
Ekofisk offshore production facilities on the Norwegian
Continental Shelf to a dedicated oil processing facility
at Teesside in the UK, with various UK fields exporting
into the system via a spurline.
LICENCE PORTFOLIO ACTIVITIES
-----------------------------------------------------------------
GSA SATELLITE ACQUISITIONs
Strategic asset In line with Ithaca's strategic objective to increase
acquisitions value from the GSA infrastructure through the acquisition
close to GSA of interests in potential satellite fields, the Company
hub -opportunity has increased its interest in the Vorlich discovery
to leverage infrastructure from approximately 17% to 33% and entered into an agreement
value to acquire a 75% interest and operatorship of the Austen
discovery. The Vorlich acquisition increases the Company's
net proven and probable reserves by approximately 4
MMboe, based on the independent reserves evaluation
performed by Sproule International Limited ("Sproule")
as of 31 December 2015, with Austen resulting in the
addition of contingent resources into the portfolio.
See "Additional Information - Reserves". The total
acquisition cost including potential future contingent
payments is under $6 million.
VORLICH
In October 2016 the Company completed the acquisition
of 100% of licence P1588 (Block 30/1f) through three
purchases from ENGIE E&P UK Limited ("ENGIE E&P"),
INEOS UK SNS Limited and Maersk Oil North Sea Limited.
Licence P1588 contains approximately 10-20% of the
Vorlich discovery, with the balance of the discovery
located in licence P363 (Block 30/1c). When taking
into account the P363 licence interest acquired from
TOTAL E&P UK Limited in January 2016, these transactions
increase Ithaca's overall interest in the Vorlich discovery
by around 16%, to approximately 33%.
Vorlich was discovered and appraised in 2014 with exploration
well 30/1f-13A,Z and 13Z. The well encountered hydrocarbons
in a Palaeocene sandstone reservoir in Block 30/1c
and a subsequent side-track into Block 30/1f confirmed
the westerly extension of the discovery. The well was
flow tested at a maximum rate of 5,350 boepd (approximately
80% oil).
Vorlich is located approximately 10 kilometres north
of the Company's GSA production hub and was estimated
as of 31 December 2015 to contain gross proven and
probable undeveloped reserves of approximately 24 MMboe
by Sproule. Following completion of the Vorlich appraisal
programme in 2014, current activities are focused on
planning and preparation of a Field Development Plan
("FDP").
The overall Vorlich licence interests are as follows:
* Licence P363: BP (Operator), 80%; Ithaca, 20%
* Licence PL1588: Ithaca (Operator), 100%
AUSTEN
An SPA was executed with ENGIE E&P in July 2016 to
acquire a 75% interest and operatorship of Licence
P1823 (Block 30/13b), effective 1 May 2016. The licence
contains the Austen discovery, which is located approximately
30 kilometres south-east of the GSA hub. Austen is
an Upper Jurassic oil / gas-condensate accumulation
on which a number of wells have been drilled, the most
recent being appraisal well 30/1b-10,10Z drilled by
ENGIE E&P in 2012. It is planned for further subsurface
and development engineering studies to be completed
in order to advance preparation of an FDP for approval
prior to January 2019.
The licence acquisition is expected to complete later
in the year, subject to normal regulatory and partner
approvals, including approval for the transfer of operatorship.
Upon completion, the Austen licence interests will
be: Ithaca (Operator), 75%; Premier Oil, 25%.
COMMODITY HEDGING
--------------------------------------------------------------
Additional hedging As part of its overall risk management strategy, Ithaca's
put in place commodity hedging policy is centred on underpinning
- resulting in revenues from existing producing assets at the time
commodity price of major capital expenditure programmes and locking
protection of in paybacks associated with asset acquisitions. Any
7,800 boepd to hedging is executed at the discretion of the Company,
end-2017 with no minimum requirements stipulated in any of the
Company's debt finance facilities.
As at 1 October 2016 the Company's commodity hedges
were valued at $32.5 million, $18.9 million for oil
hedges and $13.6 million for gas hedges, based on valuations
relative to the respective oil and gas forward curves.
In mid-October 2016 the Company entered into additional
hedging contracts for 1.5 million barrels of 2017 oil
production. 750,002 barrels have been hedged using
collars with a floor price of $46/bbl and a celling
price of $60/bbl and 750,000 barrels have been hedged
using put options with a floor price of $53/bbl.
Incorporating the new hedging with the Company's existing
position at the end of the quarter, the Company has
7,800 boepd hedged at an average floor price of $52/boe
for the 15 months to December 2017. Full commodity
price upside exposure has been retained on 50% of the
volumes hedged and upside exposure to $60/boe has been
retained on a further 20%.
OPERATING EXPITURE
-----------------------------------------------------------
Opex running Continued operating cost savings secured in the third
under full year quarter of 2016 have further reduced YTD 2016 unit
guidance for operating costs to $23/boe. Unit costs are therefore
current producing currently running under the previously lowered full
asset base of year operating cost guidance of $25/boe prior to Stella
$25/boe start-up. This represents a substantial 23% saving
on the $30/boe level originally forecast for the existing
producing asset base at the start of the year. Cost
reductions have been achieved across the portfolio,
with the Cook, Pierce and Wytch Farm fields delivering
the most significant savings.
CAPITAL EXPITURE
------------------------------------------------------------------------
Forecast 2016 Total capital expenditure in 2016 is now forecast to
capital expenditure increase from $50 million to $60 million. This increase
increased to is a result of the accelerated GSA oil export pipeline
$60M to account installation operations, the total project cost of
for the accelerated which remains unchanged. Of the total 2016 expenditure
GSA oil export approximately $50 million is expected to be paid this
pipeline programme year, with the balance due in 2017. Over the first
nine months of this year $42 million has been incurred.
Beyond 2016 Ithaca forecasts an average underlying
capital expenditure of $10-25 million per annum on
its producing asset portfolio. This relates to facilities
maintenance and low cost production enhancement activities.
In addition to this, the Company has a diverse set
of further investment opportunities within its existing
portfolio and the flexibility to tailor its capital
programme to the economic outlook at the time. It is
anticipated that the average annual capital expenditure
required to develop these opportunities will be between
$25 -75 million.
The Company is in the process of finalising its investment
plans for 2017 and will set out the forecast capital
expenditure at the start of the year. Planning of the
Harrier development programme is well advanced and
work continues on assessing the options for drilling
infill wells on the Cook field and the Don NE licence
area. The nature of these programmes, being development
activities that take advantage of existing infrastructure,
and the opportunities to secure lower than previously
anticipated investment costs mean that these are expected
to represent high value targets in the current environment.
DEBT
------------------------------------------------------------------------
Further deleveraging DEBT SUMMARY (M$) 30 Sep. 31 Dec.
delivered in 2016 2015
2016 - net debt RBL Facility 327.9 376.8
reduced to $598M Senior Notes 300.0 300.0
at end Q3 2016 Total Debt 627.9 676.8
UK Cash and Cash Equivalents (29.8) (11.5)
Net Drawn Debt 598.1 665.3
Note this table shows debt repayable as opposed to
the reported balance sheet debt which nets off capitalised
RBL and senior note costs
Since net debt peaked as anticipated in the first half
of 2015 at over $800 million, the Company has significantly
delevered the business. Net debt was reduced by a further
$67 million in the first nine months of 2016 to $598
million at 30 September 2016. This reduction reflects
the benefit of continuing strong operating cashflow
generation from the base producing assets, delivered
as a result of solid production, reduced operating
costs and lower capital expenditures across the portfolio.
Deleveraging of the business remains a core priority
of the Company, with a step change in the debt reduction
profile forecast upon the start-up of Stella production.
TRADING ENVIRONMENT
-----------------------------------------------------------------
COMMODITY PRICES
-----------------------------------------------------------------
3-Months Ended 9-Months Ended
30 September 30 September
2016 2015 2016 2015
Average Brent
Price $/bbl 46 51 42 55
The Q3 2016 financial results reflect the impact of
the reduction in Brent prices that has dominated the
sector since the middle of 2014. On a year-on-year
basis, the average annual Brent price has decreased
by $5/bbl or 10% between Q3 2015 and Q3 2016. When
comparing YTD 2016 with the same period in 2015, this
fall increases to $13/bbl or 24%. While this has had
a significant negative impact on revenues, the fall
in Brent has been materially mitigated during the period
by the significant oil and gas price hedging protection
the Company had put in place.
FOREIGN EXCHANGE RATES
-----------------------------------------------------------------
3-Months Ended 9-Months Ended
30 September 30 September
2016 2015 2016 2015
GBP : USD average 1.31 1.55 1.39 1.53
GBP : USD period
end spot 1.30 1.52 1.30 1.52
The company seeks to minimise currency volatility through
active hedging of pounds sterling. Ahead of the introduction
of gas sales from the Stella field the majority of
the Company's revenue is US dollar denominated oil
sales, while approximately 80% of costs are incurred
in pounds sterling. The sharp fall in GBP vs USD, following
the result of the UK referendum to leave the European
Union, is however not expected to have a material net
effect on the results of the business in 2016 as a
result of the Company's active hedging programme (refer
below).
Q3 2016 RESULTS OF OPERATIONS
------------------------------------------------------------------------
REVENUE
------------------------------------------------------------------------
THREE MONTHSED 30 SEPTEMBER 2016
Revenue increased by $2.5 million in Q3 2016 to $44.6
million (Q3 2015: $42.1 million) as a consequence of
a 12% rise in sales volumes, partially offset by a
$6/bbl or 12% decrease in the realised oil price prior
to taking into account hedging. While produced volumes
decreased by 16% in Q3 2016 compared to Q3 2015, primarily
driven by the cessation of production from the Athena
and Anglia fields and natural decline in the Causeway
Area, sales volumes increased due to lifting schedules.
In particular, the increase in sales volumes was attributable
to the fact there were oil liftings from both the Cook
and Pierce fields in Q3 2016, in addition to the monthly
liftings on the Dons fields.
The reduction in realised price for the period was
offset to a significant extent by realised oil and
gas hedging gains of $17 per sales barrel of oil equivalent
in the quarter, resulting in an $18.1 million gain
on commodities being reported through Foreign Exchange
and Financial Instruments (see below).
While realised oil prices for each of the fields in
the Company's portfolio do not strictly follow the
Brent price pattern, with some fields sold at a discount
or premium to Brent and under contracts with differing
timescales for pricing, the average realised price
for all the fields trades broadly in line with Brent.
NINE MONTHSED 30 SEPTEMBER 2016
Revenue decreased by $69.3 million in YTD 2016 to $102.3
million (YTD 2015: $171.6 million). This 40% reduction
was driven by a decrease of $15/bbl or 27% in the pre-hedging
realised oil price associated with the fall in Brent
during the period, coupled with a 24% decrease in underlying
sales volumes.
Sales volumes decreased in YTD 2016 primarily due to
the 22% reduction in produced volumes, due to the cessation
of production from the Athena, Anglia and Causeway
fields as well as reduced production on the Pierce
field.
In terms of average realised oil prices, there was
a decrease to $42/bbl in YTD 2016 (YTD 2015: $57/bbl)
compared to an average Brent price for the nine months
ended 30 September 2016 of $42/bbl (YTD 2015: $55/bbl).
The decrease in realised oil price was more than offset
by a realised hedging gain of $29 per sales barrel
of oil equivalent in the period.
3-Months Ended 9-Months Ended
30 September 30 September
Average Realised 2016 2015 2016 2015
Price
Oil Pre-Hedging $/bbl 44 51 42 57
Oil Post-Hedging $/bbl 54 94 59 86
COST OF SALES
-----------------------------------------------------------------
3-Months Ended 9-Months Ended
30 September 30 September
$'000 2016 2015 2016 2015
Operating Expenditure 19,112 25,760 61,145 83,383
DD&A 21,705 30,946 59,088 93,205
Movement in Oil &
Gas Inventory 5,586 (4,676) (5,404) 8,447
Total 46,403 52,030 114,829 185,035
THREE MONTHSED 30 SEPTEMBER 2016
Cost of sales decreased in Q3 2016 by approximately
11% to $46.4 million (Q3 2015: $52.0 million). This
was attributable to decreases in operating costs, depletion,
depreciation and amortisation ("DD&A") offset by movement
in oil and gas inventory.
OPERATING EXPITURE
Reported operating costs decreased by 26% in the quarter
to $19.1 million (Q3 2015: $25.8 million). Cost reductions
were achieved across the portfolio, with the Cook and
Wytch Farm fields in particular delivering the most
significant savings. This continued focus on driving
down costs delivered a unit operating cost of $21/boe
for Q3 2016, representing a reduction of 24% compared
to the equivalent rate of $28/boe for Q3 2015. This
reduced rate incorporates a significant benefit ($2/boe
compared to the first half of 2016) relating to movements
in the US$:GBP exchange rate, as underlying costs are
primarily incurred in GBP.
DD&A
The unit DD&A rate for the quarter decreased to $24/boe
(Q3 2015: $28/boe), resulting in a total DD&A expense
for the period of $21.7 million (Q3 2015: $30.9 million).
This reduction in expense was due to a combination
of lower production in the quarter compared to the
same period in 2015 and impairment write downs booked
in Q4 2015 as a result of the change in the oil price
environment, which also lowered average DD&A/boe rates.
MOVEMENT IN INVENTORY
An oil and gas inventory movement of $5.6 million was
charged to cost of sales in Q3 2016 (Q3 2015: credit
of $4.7 million). This charge arose as a result of
an overlift in the quarter, predominantly due to historic
build-up of inventory on the Cook and Pierce fields,
which both had oil liftings in the quarter.
NINE MONTHSED 30 SEPTEMBER 2016
Cost of sales decreased in YTD 2016 to $114.8 million
(YTD 2015: $185.0 million) due to decreases in operating
costs, DD&A and the movement in oil and gas inventory.
OPERATING EXPITURE
Operating costs decreased in the period to $61.1 million
(YTD 2015: $83.4 million) primarily as a result of
the previously noted effect of cost savings achieved
across the portfolio as a consequence of supply chain
cost reduction initiatives. This results in a YTD 2016
unit rate of $23/boe (YTD 2015: $33/boe), ahead of
the lowered 2016 guidance levels of $25/boe prior to
first oil from the Stella field.
DD&A
DD&A for the period decreased to $59.1 million (YTD
2015: $93.2 million). As noted above, this decrease
was primarily due to a combination of lower production
and the impact of the write downs booked in 2015 as
a consequence of the change in oil price environment.
MOVEMENT IN INVENTORY
An oil and gas inventory movement of $5.4 million was
credited to cost of sales in YTD 2016 (YTD 2015: charge
of $8.4 million). In YTD 2016 more barrels of oil were
produced (2,411 kbbls) than sold (2,374 kbbls), mainly
due to the timing of Cook, Dons and Pierce field liftings,
resulting in a small underlift position. The majority
of the movement, however, is driven by an increase
in the value of the inventory due to a rise in underlying
Brent prices between the end of 2015 and 30 September
2016.
Movement in Operating Oil Gas Total
Oil & Gas Inventory kbbls kboe kboe
Opening inventory 472 (3) 469
Production 2,411 215 2,626
Liftings/sales (2,374) (215) (2,589)
Transfers/other (3) - (3)
Closing volumes 506 (3) 503
ADMINISTRATION EXPENSES AND EXPLORATION & EVALUATION
EXPENSES
-------------------------------------------------------------------
3-Months Ended 9-Months Ended
30 September 30 September
$'000 2016 2015 2016 2015
General & Administration
("G&A") 841 2,509 3,801 7,611
Share Based Payments
("SBP") 170 238 501 627
Total Administration
Expenses 1,011 2,747 4,303 8,238
Exploration & Evaluation
("E&E") write off 20 620 839 29,720
Administration
expenses reduced THREE MONTHSED 30 SEPTEMBER 2016
through on-going ADMINISTRATION EXPENSES
cost saving measures Total administration expenses were reduced by 63% to
$1.0 million in Q3 2016 (Q3 2015: $2.7 million). This
was largely attributable to a continued focus on cost
saving initiatives across the business, coupled with
one-off non-recurring costs in Q3 2015. Costs incurred
in the quarter reflect further reductions in contractor
rates and a decrease in both employee and contractor
numbers from Q3 2015.
E&E EXPENSES
A minor write off of E&E assets was made at the period
end relating to non-commercial prospects.
NINE MONTHSED 30 SEPTEMBER 2016
Total administrative expenses decreased in the period
to $4.3 million (YTD 2015: $8.2 million) primarily
due to the cost saving drive initiated as a result
of the lower oil price environment as well as the absence
of Norwegian expenses following the sale of Norwegian
operations in July 2015.
FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS
----------------------------------------------------------------------------------
3-Months Ended 9-Months Ended
30 September 30 September
$'000 2016 2015 2016 2015
Gain / (Loss) on Foreign Exchange 2,130 2,354 3,036 (1,656)
------------------------------------ --------- -------- --------- ---------
Total Gain/(Loss) on Foreign
Exchange 2,130 2,354 3,036 (1,656)
------------------------------------ --------- -------- --------- ---------
Revaluation Forex Forward
Contracts 2,955 (3,254) (2,322) 1,785
Revaluation of Interest Rate
Swaps 102 614 144 349
Revaluation of Other Liability - - - 307
Revaluation of Commodity Hedges (14,001) 41,769 (93,919) (54,529)
------------------------------------ --------- -------- --------- ---------
Total Revaluation (Loss) /
Gain (10,944) 39,129 (96,097) (52,088)
------------------------------------ --------- -------- --------- ---------
Realised (Loss)/Gain on Forex
Contracts (4,076) 614 (5,027) 1,221
Realised Gain on Commodity
Hedges 18,104 35,132 76,091 145,238
Realised (Loss)/Gain on Interest
Rate swaps (78) 19 (235) (186)
Total Realised Gain 13,950 35,765 70,829 146,273
------------------------------------ --------- -------- --------- ---------
Total Foreign Exchange & Financial
Instruments 5,136 77,248 (22,232) 92,529
------------------------------------ --------- -------- --------- ---------
THREE MONTHSED 30 SEPTEMBER 2016
FOREIGN EXCHANGE
While the majority of the Company's revenue is US dollar
denominated, expenditures are predominantly incurred
in British pounds (some US dollar and Euro denominated
costs are also incurred). Consequently, general volatility
in the GBP:USD exchange rate is the primary factor
underlying foreign exchange gains and losses.
In Q3 2016, a foreign exchange gain of $2.1 million
was recorded (Q3 2015: $2.4 million gain). This was
driven by the GBP:USD exchange rate moving from 1.34
at 1 July 2016 to 1.30 at 30 September 2016 with fluctuations
throughout the quarter of between 1.29 and 1.34.
FINANCIAL INSTRUMENTS
The Company recorded an overall gain of $3.0 million
on financial instruments for the quarter ended 30 September
2016 (Q3 2015: $74.9 million gain).
A $13.9 million realised gain was made in Q3 2016.
This comprised a $9.3 million gain on oil hedges maturing
during the quarter (at an average exercise price of
$68/bbl compared to an average Brent price of $46/bbl)
and an $8.8 million gain on gas hedges (at an average
price of 58p/therm compared to an average NBP price
of 31p/therm), partially offset by a $4.2million loss
on foreign exchange and interest rate instruments.
The total realised gain of $13.9 million in the period
was partially offset by a $10.9 million negative revaluation
of instruments as at 30 September 2016. This resulted
from a negative revaluation of oil hedges of $6.7 million
and gas hedges of $7.3 million, partially offset by
a positive revaluation of other hedges of $3.1 million.
This fair value accounting for financial instruments
by its nature leads to volatility in the results due
to the impact of revaluing the financial instruments
at the end of each reporting period.
The $6.7 million negative revaluation of oil hedges
was due to the realisation of hedged oil volumes during
the quarter (i.e. the transfer of previously unrealised
gains to realised gains), partially offset by an increase
in the value of the remaining oil hedges at the end
of Q3 2016 as a result of a minor decrease in the oil
price forward curve from 30 June 2016 to 30 September
2016. The $7.3 million negative revaluation of gas
hedges arises in the same way, being a combination
of realisations during the quarter and a positive revaluation
of the remaining gas hedges at the end of Q3 2016 due
to a small decrease in the gas forward curve in the
three months to 30 September 2016.
NINE MONTHSED 30 SEPTEMBER 2016
FOREIGN EXCHANGE
A foreign exchange gain of $3.0 million was recorded
in YTD 2016 (YTD 2015: $1.7 million loss) primarily
due to volatility in the GBP:USD exchange rate, with
fluctuations between 1.29 and 1.48 during the period
and a closing rate of 1.30 on 30 September 2016.
FINANCIAL INSTRUMENTS
The Company recorded an overall $25.3 million loss
on financial instruments for the nine month period
ended 30 September 2016 (YTD 2015: $94.2 million gain).
A $70.8 million gain was recorded in respect of realised
hedges, comprising $41.4 million on oil hedges and
$34.7 million on gas hedges maturing during the period,
partially offset by a $5.3 million realised loss on
foreign exchange and interest rate instruments.
Offsetting the realised gain was the revaluation of
instruments as at 30 September 2016, which values instruments
still held at quarter end. This $96.1 million revaluation
related to a negative revaluation of oil hedges of
$49.7 million and a negative revaluation of gas hedges
of $44.2 million combined with a revaluation of foreign
exchange and interest rate instruments of $2.2 million.
The loss on commodity instruments was primarily due
to the realisation of the amounts noted above (i.e.
where they are no longer still held at the period end),
combined with a decrease in value of the remaining
hedges based on the movement in the forward curve from
the start of the year to the end of the reporting period.
As of 1 October 2016, the Company's commodity hedges
were valued at $32.5 million, $18.9 million for oil
hedges and $13.6 million for gas hedges, based on valuations
relative to the respective oil and gas forward curves.
This asset is partly offset by a liability relating
to the value of foreign exchange and interest rate
hedging instruments held at the period end of $2.2
million.
FINANCE COSTS
---------------------------------------------------------------------------
3-Months Ended 9-Months Ended
30 September 30 September
$'000 2016 2015 2016 2015
Reducing finance Bank interest and charges (946) (1,630) (3,228) (6,258)
cost profile Senior notes interest (3,830) (3,830) (11,489) (11,179)
driven by decreasing Finance lease interest (247) (260) (751) (791)
net debt Non-operated asset finance
fees (9) (11) (21) (61)
Prepayment interest (706) (181) (2,110) (963)
Loan fee amortisation (1,040) (1,267) (3,119) (4,324)
Accretion (2,316) (2,285) (6,883) (6,784)
Total Finance Costs (9,094) (9,464) (27,601) (30,360)
THREE MONTHSED 30 SEPTEMBER 2016
Finance costs decreased to $9.1 million in Q3 2016
(Q3 2015: $9.5 million). This reduction is primarily
attributable to the decrease in RBL bank interest resulting
from the deleveraging of the business over the last
twelve months, with drawn bank debt having fallen from
$462 million at 30 September 2015 to $328 million at
30 September 2016. All other finance costs have remained
relatively stable quarter on quarter.
NINE MONTHSED 30 SEPTEMBER 2016
Finance costs decreased to $27.6 million in YTD 2016
(YTD 2015: $30.4 million). As noted above, this reduction
primarily reflects lower RBL interest costs as a result
of the reduced drawn debt.
TAXATION
---------------------------------------------------------------------------
3-Months Ended 9-Months Ended
30 September 30 September
$'000 2016 2015 2016 2015
UK & Norway Corporation
Tax - excluding Rate
Changes 10,854 (12,343) 64,665 63,351
Impact of Change in
Tax Rates (74,749) - (61,712) (41,501)
Petroleum Revenue
Tax - (385) - (2,375)
Total Taxation (63,895) (12,728) 2,953 19,475
THREE MONTHSED 30 SEPTEMBER 2016
No UK tax anticipated A tax charge of $63.9 million was recognised in the
to be payable three months ended 30 September 2016 (Q3 2015: $12.7
prior to 2020 million charge). This includes a charge of $74.7 million
relating to the impact of the change in the Supplementary
Charge in respect of ring fence trades ("SCT") which
was reduced from 20% to 10%. This change was enacted
in September 2016 and is effective from 1 January 2016.
The remaining tax credit of $10.9 million includes
significant adjustments of $12.4 million credit relating
to the UK Ring Fence Expenditure Supplement and $9.0
million in respect of additional capital allowances
recognised in relation to Stella for expenditure incurred
by Ithaca but paid by Petrofac (refer to note 24 in
the Q3 2016 Consolidated Financial Statements).
NINE MONTHSED 30 SEPTEMBER 2016
A tax credit of $3.0 million was recognised in the
nine months ended 30 September 2016 (Q3 YTD 2015: $19.5
million credit). This comprises a charge relating to
rate changes of $61.7 million offset by a credit of
$64.7 million. Significant components of the $64.7
million Corporation Tax ("CT") credit include a $36.6
million credit relating to the UK Ring Fence Expenditure
Supplement and $18.3 million in respect of additional
capital allowances recognised in relation to Stella
for expenditure incurred by Ithaca but paid by Petrofac
(refer to note 24 in the Q3 2016 Consolidated Financial
Statements).
The charge of $61.7 million comprises the impact of
rate changes on CT of $85.9 million offset by a credit
of $24.2 million relating to PRT.
It was announced in the UK Budget on 16 March 2016
that Petroleum Revenue Tax ("PRT") was effectively
abolished from 1 January 2016 with the introduction
of a 0% rate. This eliminated the Company's future
PRT tax charge from 1 January 2016. The PRT rate change
has been enacted and therefore the deferred PRT provision
was fully released through the Q1 2016 results giving
rise to a credit of $24.2 million.
Further, it was also announced in the UK Budget that
the SCT rate would be reduced from 20% to 10% with
effect from 1 January 2016. This will reduce the Company's
future SCT charge accordingly. The impact of the 10%
reduction in the Supplementary Charge was to reduce
the net deferred tax assets by $74.7 million, coupled
with the CT impact of the PRT rate change of $11.2
million, giving an overall rate change driven CT charge
for the YTD 2016 of $85.9 million.
Note that the Q3 YTD 2015 comparative contains a charge
of $41.5 million relating to the previous changes in
the SCT and PRT rates enacted in Q1 2015.
CAPITAL INVESTMENTS
=================================================================
$'000 Additions
2016 capital YTD 2016
investment programme Development & Production
primarily focused ("D&P") 60,323
on GSA development Exploration & Evaluation
activities ("E&E") 6,498
Other Fixed Assets 3
Total 66,824
Capital additions in YTD 2016 totalled $66.8 million,
with the major component being additions to development
and production ("D&P") assets.
Excluding capitalised interest costs, non-cash additions
relating to decommissioning and Vorlich acquisition
costs paid at completion capital expenditure was approximately
$42 million. This mainly related to activities on the
GSA and includes work carried out on the oil export
pipeline committed to post issuance of original guidance
of $50 million. As previously advised, although the
majority of the oil export pipeline work is to be carried
out in 2016 it will only become a cash spend in the
first half of 2017.
WORKING CAPITAL
---------------------------------------------------------------------------
$'000 30 Sep. 31 Dec. Increase
2016 2015 / (Decrease)
Cash & Cash Equivalents 29,772 11,543 18,229
Trade & Other Receivables 225,975 223,749 2,226
Inventory 26,162 20,900 5,262
Derivative Financial
Instruments (current) 30,374 126,887 (96,513)
Trade & Other Payables (298,578) (275,907) (22,671)
Net Working Capital* 13,705 107,172 (93,467)
*Working capital being total current assets less trade
and other payables
As at 30 September 2016 Ithaca had a net working capital
balance of $13.7 million, including an unrestricted
cash balance of $29.8 million held with BNP Paribas.
Substantially all of the accounts receivable are current,
being defined as less than 90 days. The Company regularly
monitors all receivable balances outstanding in excess
of 90 days. No credit loss has historically been experienced
in the collection of accounts receivable.
Working capital movements are driven by the timing
of receipts and payments of balances and fluctuate
in any given quarter. A significant proportion of Ithaca's
accounts receivable balance is with customers and co-venturers
in the oil and gas industry and is subject to normal
joint venture/industry credit risks.
Net working capital has decreased over the nine month
period to 30 September 2016 mainly as a result of a
reduction in the commodity hedging instrument asset
values of $96.5 million noted above.
CAPITAL RESOURCES
--------------------------------------------------------------
DEBT FACILITIES
As at 30 September 2016 the Company has debt facilities
Over $110 million totalling $535 million ($475 million senior RBL Facility
funding headroom and $60 million junior RBL), following the voluntary
with net debt reduction in the facilities size from a total of $650
reduced to $598 million. The Company has funding headroom of over $110
million million following the completion of the October 2016
RBL redetermination process, where bank debt capacity
was set at over $410 million. The RBL facilities are
both due September 2018. The Company also has $300
million senior unsecured notes, due July 2019.
The Company's debt facilities are expected to be sufficient
to ensure that adequate financial resources are available
to cover anticipated future commitments when combined
with existing cash balances and forecast cashflow from
operations. As noted above, the bank debt facilities
are subject to semi-annual redeterminations of available
debt capacity using forward looking assumptions, of
which future oil and gas prices are a key component.
Movements in forecast commodity prices can therefore
have a significant impact on available debt capacity
and limit the Company's ability to borrow.
The Company was in compliance with all its relevant
financial and operating covenants during the quarter.
The key covenants in the senior and junior RBL facilities,
which are available on the Company's SEDAR profile
at www.sedar.com, are:
* A corporate cashflow projection showing total sources
of funds must exceed total forecast uses of funds for
the later of the following 12 months or until
forecast first oil from the Stella field.
* The ratio of the net present value of cashflows
secured under the RBL for the economic life of the
fields to the amount drawn under the facility must
not fall below 1.15:1.
* The ratio of the net present value of cashflows
secured under the RBL for the life of the debt
facility to the amount drawn under the facility must
not fall below 1.05:1.
There are no financial maintenance covenant tests associated
with the senior notes.
Further cash Q3 YTD 2016 CASHFLOW MOVEMENTS
inflow and reduction During the nine months ended 30 September 2016 there
in net debt delivered was a cash inflow from operating, investing and financing
in Q3 YTD 2016 activities of approximately $11.5 million (YTD 2015
inflow of $19.4 million).
Cashflow from operations
Cash generated from operating activities was $116.7
million. Revenues from the producing asset portfolio
were bolstered by the substantial hedging programme
in place, while operating costs reduced by 26% period
on period.
Cashflow from financing activities
Cash used in financing activities was $57.6 million,
being primarily repayments of the debt facilities during
the period combined with interest and bank charges
on the RBL and Senior Notes.
Cashflow from investing activities
Cash used in investing activities was $65.6 million,
primarily associated with further capital expenditure
on the GSA development (including capitalised interest).
COMMITMENTS
--------------------------------------------------------------
$'000 1 Year 2-5 Years 5+ Years
Office Leases 240 120 -
Licence Fees 607 - -
Engineering 15,149 - -
Total 15,996 120 -
The Company's commitments relate primarily to completion
of the capital investment programme on the GSA development,
along with other on-going operational commitments across
the portfolio. Given the highly advanced status of
the GSA development, these commitments are relatively
modest and are forecast to be funded from the operating
cashflows of the business.
FINANCIAL INSTRUMENTS
------------------------------------------------------------------------------
All financial instruments are initially measured in
the balance sheet at fair value. Subsequent measurement
of the financial instruments is based on their classification.
The Company has classified each financial instrument
into one of these categories:
Financial Instrument Ithaca Classification Subsequent Measurement
Category
Held-for-trading Cash, cash equivalents, Fair Value with changes
restricted cash, recognised in net
derivatives, income
commodity hedges,
long-term liability
---------------------- ------------------------ --------------------------
Held-to-maturity - Amortised cost using
effective interest
rate method.
Transaction costs
(directly attributable
to acquisition or
issue of financial
asset/liability) are
adjusted to fair value
initially recognised.
These costs are also
expensed using the
effective interest
rate method and recorded
within interest expense.
---------------------- ------------------------ --------------------------
Loans and Receivables Accounts receivable
---------------------- ------------------------ --------------------------
Other financial Accounts payable,
liabilities operating bank
loans, accrued
liabilities
---------------------- ------------------------ --------------------------
The classification of all financial instruments is
the same at inception and at 30 September 2016.
COMMODITIES
The following table summarises the commodity hedges
in place at 30 September 2016.
Derivative Term Volume Average
bbl Price
$/bbl
October 2016 - June
Oil Swaps 2017 1,037,744 69
Derivative Term Volume Average
Therms Price
p/therm
October 2016 - June
Gas Puts 2017 59,200,000 63
October 2016 - March
Gas Swaps 2017 3,065,288 47
In mid-October 2016, the Company entered into hedging
contracts for a further 1.5 million barrels of 2017
oil production. 750,002 barrels have been hedged using
collars with a floor price of $46/bbl and a celling
price of $60/bbl and 750,000 barrels have been hedged
using put options with a floor price of $53/bbl.
Incorporating the new hedging noted above, the Company
has 7,800 boepd hedged at an average price of $52/boe
(net of premiums) for the 15 months to December 2017.
This total is comprised of:
* 2,300 bopd of swap contracts at average price of
$69/bbl
* 1,600 bopd of collars with a floor price of $46/bbl
and a ceiling price of $60/bbl
* 1,600 bopd of put options with a floor price of
$53/bbl
* 130,000 therms/d of put options with a floor price of
63p/therm
* 7,000 therms/d of swap contracts at an average price
of 47p/therm
FOREIGN EXCHANGE
The Company enters into forward contracts as a means
of hedging its exposure to foreign exchange rate risks.
As at the end of the quarter, the Company had the following
hedged position:
Instrument Value Rate Term
Forward contracts GBP9.6 1.47 Oct - Dec
million 2016
Forward contracts GBP12 million 1.33 October
2016
------------------ -------------- ----- ----------
In October 2016, the Company entered into a further
forward contract to purchase GBP5 million at a GBP:USD
exchange rate of 1.24.
INTEREST RATES
The Company enters into interest rate swaps as a means
of hedging its exposure to interest rate risks on the
loan facilities. As at the end of the quarter, the
Company had hedged interest payments on $50 million
of drawn debt at 1.24% for the period to December 2016.
QUARTERLY RESULTS SUMMARY
--------------------------------------------------------------------------------------------------------
$'000 30 Sep 30 Jun 31 Mar 31 Dec 30 30 Jun 31 Mar 31 Dec
2016 2016 2016 2015 Sep 2015 2015 2014
2015
Revenue 44,585 24,511 33,250 35,340 42,108 59,125 70,375 88,928
Profit/(Loss)
After Tax (70,694) (11,468) 17,712 (177,625) 42,812 39,888 (26,078) (49,517)
Earnings
per share
"EPS" -
Basic(1) (0.17) (0.03) 0.04 (0.35) 0.13 0.12 (0.08) (0.15)
EPS -
Diluted(1) (0.17) (0.03) 0.04 (0.35) 0.13 0.12 (0.08) (0.15)
Common shares
outstanding
(000) 411,784 411,784 411,384 411,384 329,519 329,519 329,519 329,519
--------------- --------- --------- -------- ---------- -------- -------- --------- ---------
(1) Based on weighted average number of shares
The most significant factors to have affected the Company's
results during the above quarters are fluctuations
in underlying commodity prices and movement in production
volumes. The Company has utilised hedging and foreign
exchange contracts to take advantage of higher commodity
prices and beneficial exchange rates and reduce its
exposure to volatility associated with these key factors.
However, these contracts can cause volatility in profit
after tax as a result of unrealised gains and losses
due to movements in the oil price and GBP:USD exchange
rate. In addition, the significant reduction in underlying
commodity prices over the period has resulted in impairment
write downs in Q4 2014 and Q4 2015.
OUTSTANDING SHARE INFORMATION
-------------------------------------------------------------------------
The Company's common shares are traded on the Toronto
Stock Exchange ("TSX") in Canada and on the Alternative
Investment Market ("AIM") in the United Kingdom, both
under the symbol "IAE".
As at 30 September 2016 Ithaca had 411,784,045 common
shares outstanding along with 28,746,470 options outstanding
to employees and directors to acquire common shares.
30 September
2016
Common Shares Outstanding 411,784,045
Share Price((1) $0.85 / Share
Total Market Capitalisation $350,016,438
(1) Represents the TSX close price (CAD$1.12) on 30
September 2016. US$:CAD$ 0.76 on 30 September 2016
CONSOLIDATION
=============================================================
The consolidated financial statements of the Company
and the financial data contained in this management's
discussion and analysis ("MD&A") are prepared in accordance
with IFRS.
The consolidated financial statements include the accounts
of Ithaca and its wholly--owned subsidiaries, listed
below, and its associates FPU Services Limited ("FPU")
and FPF--1 Limited ("FPF--1").
Wholly owned subsidiaries:
* Ithaca Energy (Holdings) Limited
* Ithaca Energy (UK) Limited
* Ithaca Minerals North Sea Limited
* Ithaca Energy Holdings (UK) Limited
* Ithaca Petroleum Limited
* Ithaca Causeway Limited
* Ithaca Exploration Limited
* Ithaca Alpha (NI) Limited
* Ithaca Gamma Limited
* Ithaca Epsilon Limited
* Ithaca Delta Limited
* Ithaca North Sea Limited
* Ithaca Petroleum Norge AS*
* Ithaca Petroleum Holdings AS
* Ithaca Technology AS
* Ithaca AS
* Ithaca Petroleum EHF
* Ithaca SPL Limited
* Ithaca SP UK Limited
* Ithaca Dorset Limited
* Ithaca Pipeline Limited
All inter--company transactions and balances have been
eliminated on consolidation. A significant portion
of the Company's North Sea oil and gas activities are
carried out jointly with others. The consolidated financial
statements reflect only the Company's proportionate
interest in such activities.
* Following the sale of the Company's Norwegian operations
in Q2 2015, Ithaca Petroleum Norge AS has been divested
and as of Q3 2015, no longer features in the financial
results of the Company.
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 Company 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 Company might realize different results
from the application of new accounting standards promulgated,
from time to time, by various rule-making bodies.
Capitalised 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 Company's
D&P and E&E assets may be impaired. For 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 Company'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 of disposal 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 recognised 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 are initially recognised
at fair value on the balance sheet. The Company's financial
instruments consist of cash, accounts receivable, deposits,
derivatives, accounts payable, accrued liabilities,
contingent consideration and borrowings. Measurement
in subsequent periods is dependent on the classification
of the respective financial instrument.
In order to recognise share based payment expense,
the Company 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 Company'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 Company 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.
CONTROL ENVIRONMENT
--------------------------------------------------------------
The Chief Executive Officer and Chief Financial Officer
evaluated the effectiveness of the Company's disclosure
controls and procedures as at 30 September 2016, and
concluded that such disclosure controls and procedures
are effective to ensure that information required to
be disclosed by the Company in its annual filings,
interim filings and other reports filed or submitted
under securities legislation is recorded, processed,
summarised and reported within the time periods specified
in the securities legislation and such information
is accumulated and communicated to the Company's management,
including its certifying officers, as appropriate to
allow timely decisions regarding required disclosures.
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 for external
purposes in accordance with IFRS including those policies
and procedures that:
(a) pertain to the maintenance of records that in reasonable
detail accurately and fairly reflect the transactions
and dispositions of the Company's assets;
(b) are designed to provide reasonable assurance that
transactions are recorded as necessary to permit preparation
of financial statements in accordance with IFRS, and
that receipts and expenditures of the Company are being
made only in accordance with authorisations of management
and directors of the Company; and
(c) are designed to provide reasonable assurance regarding
prevention or timely detection of unauthorised acquisition,
use or disposition of the Company's assets that could
have a material effect on the annual financial statements
or interim financial statements.
The Chief Executive Officer and Chief Financial Officer
performed an assessment of internal control over financial
reporting as at 30 September 2016, based on the criteria
established in Internal Control - Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations
of the Treadway Commission ("COSO"), and concluded
that internal control over financial reporting is effective
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 30 September 2016, there were no changes in the
Company's internal control over financial reporting
that occurred during the quarter ended 30 September
2016 that have materially affected, or are reasonably
likely to materially affect, our internal control over
financial reporting.
CHANGES IN ACCOUNTING POLICIES
--------------------------------------------------------------
New and amended standards and interpretations need
to be adopted in the first financial statements issued
after their effective date (or date of early adoption).
There are no new IFRSs of IFRICs that are effective
for the first time for this period that would be expected
to have a material impact on the Company.
ADDITIONAL INFORMATION
-------------------------------------------------------------------
Non-IFRS Measures "Cashflow from operations" and "cashflow per share"
referred to in this MD&A are not prescribed by IFRS.
These non-IFRS financial measures do not have any standardised
meanings and therefore are unlikely to be comparable
to similar measures presented by other companies. The
Company uses these measures to help evaluate its performance.
As an indicator of the Company'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
Company considers cashflow from operations to be a
key measure as it demonstrates the Company'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.
"Net working capital" referred to in this MD&A is not
prescribed by IFRS. Net working capital includes total
current assets less trade & other payables. Net working
capital may not be comparable to other similarly titled
measures of other companies, and accordingly Net working
capital may not be comparable to measures used by other
companies.
"Net debt" referred to in this MD&A is not prescribed
by IFRS. The Company uses net drawn debt as a measure
to assess its financial position. Net drawn debt includes
amounts outstanding under the Company's debt facilities
and senior notes, less cash and cash equivalents.
-------------------------------------------------------------------
Off Balance Sheet The Company has certain lease agreements and rig commitments
Arrangements 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. Where appropriate, finance
leases are recorded on the balance sheet. As at 30
September 2016, finance lease assets of $28.9 million
and related liabilities of $30.2 million are included
on the balance sheet.
-------------------------------------------------------------------
Related Party A director of the Company is a partner of Burstall
Transactions Winger Zammit LLP who acts as counsel for the Company.
The amount of fees paid to Burstall Winger Zammit LLP
in Q3 2016 was $0.0 million (Q3 2015: $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 30 September 2016 the Company had loans receivable
from FPF-1 Limited and FPU Services Limited, associates
of the Company, for $60.1 million and $0.0 million,
respectively (30 September 2015: $58.6 million and
$0.2 million, respectively) as a result of the completion
of the GSA transactions.
-------------------------------------------------------------------
BOE Presentation The calculation of 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, utilising a conversion ratio at 6
mcf: 1 bbl may be misleading as an indication of value.
-------------------------------------------------------------------
Reserves The estimates of reserves stated herein for individual
properties may not reflect the same confidence level
as estimates of reserves for all properties, due to
the effects of aggregation.
The Company's total net proved and probable reserves
at 31 December 2015 plus the estimated net proved and
probable reserves associated with the Vorlich licence
acquisitions were 57 MMboe (see "Licence Portfolio
Activities"). These reserves were independently assessed
by Sproule, a qualified reserves evaluator, as of December
31, 2015 in accordance with the Canadian Oil and Gas
Evaluation Handbook maintained by the Society of Petroleum
Engineers (Calgary Chapter), as amended from time to
time. The Vorlich field interest and estimated reserves
reflect assumed unitisation across licences P1588 and
P363.
-------------------------------------------------------------------
Well Test Results Certain well test results disclosed in this MD&A represent
short-term results, which may not necessarily be indicative
of long-term well performance or ultimate hydrocarbon
recovery therefrom. Full pressure transient and well
test interpretation analyses have not been completed
and as such the flow test results contained in this
MD&A should be considered preliminary until such analyses
have been completed.
-------------------------------------------------------------------
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 Company
is dependent upon the production rates and oil price
to fund the current development program.
For additional detail regarding the Company's risks
and uncertainties, refer to the Company's Annual Information
Form for the year ended 31 December 2015, (the "AIF")
filed on SEDAR at www.sedar.com.
Commodity Price RISK: The Company's performance is significantly impacted
Volatility by prevailing oil and natural gas prices, which are
primarily driven by supply and demand as well as economic
and political factors.
MITIGATIONS: To mitigate the risk of fluctuations in
oil and gas prices, the Company routinely executes
commodity price derivatives, predominantly in relation
to oil production, as a means of establishing a floor
in realised prices.
--------------------------------------------------------------------
Foreign Exchange RISK: The Company is exposed to financial risks including
Risk financial market volatility and fluctuation in various
foreign exchange rates.
MITIGATIONS: Given the proportion of development capital
expenditure and operating costs incurred in currencies
other than the US Dollar, the Company routinely executes
hedges to mitigate foreign exchange rate risk on committed
expenditure and/or draws debt in pounds sterling to
settle sterling costs which will be repaid from surplus
sterling generated revenues derived from Stella gas
sales.
--------------------------------------------------------------------
Interest Rate RISK: The Company is exposed to fluctuation in interest
Risk rates, particularly in relation to the debt facilities
entered into.
MITIGATIONS: To mitigate the fluctuations in interest
rates, the Company routinely reviews the associated
cost exposure and periodically executes hedges to lock
in interest rates.
--------------------------------------------------------------------
Debt Facility RISK: The Company is exposed to borrowing risks relating
Risk to drawdown of its debt facilities (the "Facilities").
The available debt capacity and ability to drawdown
on the Facilities is based on the Company meeting certain
covenants including coverage ratio tests, liquidity
tests and development funding tests. The available
debt capacity is redetermined semi-annually, using
a detailed economic model of the Company and forward
looking assumptions of which future oil and gas prices,
costs and production profiles are key components. Movements
in any component, including movements in forecast commodity
prices can therefore have a significant impact on available
debt capacity and limit the Company's ability to borrow.
There can be no assurance that the Company will satisfy
such tests in the future in order to have access to
adequate Facilities.
The Facilities include covenants which restrict, among
other things, the Company's ability to incur additional
debt or dispose of assets.
As is standard to a credit facility, the Company's
and Ithaca Energy (UK) Limited's assets have been pledged
as collateral and are subject to foreclosure in the
event the Company or Ithaca Energy (UK) Limited defaults
on the Facilities.
The Facilities are available on the Company's SEDAR
profile at www.sedar.com. Also refer to "Capital resources
- Debt Facilities" herein.
MITIGATIONS: The financial tests necessary to draw
down upon the Facilities needed were met during the
period.
The Company routinely produces detailed cashflow forecasts
to monitor its compliance with the financial and liquidity
tests of the Facilities and maintain the ability to
execute proactive debt positive actions such as additional
commodity hedging.
--------------------------------------------------------------------
Financing Risk RISK: To the extent cashflow from operations and the
Facilities' resources are ever deemed not adequate
to fund Ithaca's cash requirements, external financing
may be required. Lack of timely access to such additional
financing, or access on unfavourable terms, could limit
Ithaca's ability to make the necessary capital investments
to maintain or expand its current business and to make
necessary principal payments under the Facilities may
be impaired.
A failure to access adequate capital to continue its
expenditure program may require that the Company meet
any liquidity shortfalls through the selected divestment
of all or a portion of its portfolio or result in delays
to existing development programs.
MITIGATIONS: The Company has established a business
plan and routinely monitors its detailed cashflow forecasts
and liquidity requirements to ensure it will continue
to be fully funded.
The Company believes that there are no circumstances
that exist at present which require forced divestments,
significant value destroying delays to existing programs
or will likely lead to critical defaults relating to
the Facilities.
Third Party Credit RISK: The Company is and may in the future be exposed
Risk 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 Company extends unsecured credit to these and certain
other parties, and therefore, the collection of any
receivables may be affected by changes in the economic
environment or other conditions affecting such parties.
MITIGATIONS: Where appropriate, a cash call process
is implemented with partners to cover high levels of
anticipated capital expenditure thereby reducing any
third party credit risk.
The majority of the Company's oil production is sold
to Shell Trading International Ltd. Gas production
is sold through contracts with Hartree Partners Power
and Gas Company (UK) Limited, Shell UK Ltd. and Esso
Exploration & Production UK Ltd. Each of these parties
has historically demonstrated their ability to pay
amounts owing to Ithaca.
---------------------------------------------------------------
Property Risk RISK: The Company's properties will be generally held
in the form of licences, concessions, permits and regulatory
consents ("Authorisations"). The Company's activities
are dependent upon the grant and maintenance of appropriate
Authorisations, which may not be granted; may be made
subject to limitations which, if not met, will result
in the termination or withdrawal of the Authorisation;
or may be otherwise withdrawn. Also, in the majority
of its licences, the Company is a joint interest-holder
with other third parties over which it has no control.
An Authorisation 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 Authorisation will be met. Although the Company
believes that the Authorisations will be renewed following
expiry or granted (as the case may be), there can be
no assurance that such authorisations will be renewed
or granted or as to the terms of such renewals or grants.
The termination or expiration of the Company's Authorisations
may have a material adverse effect on the Company's
results of operations and business.
MITIGATIONS: The Company has routine ongoing communications
with the UK oil and gas regulatory body, the Department
of Energy and Climate Change ("DECC") as well as Norwegian
authorities. Regular communication allows all parties
to an Authorisation to be fully informed as to the
status of any Authorisation and ensures the Company
remains updated regarding fulfilment of any applicable
requirements.
---------------------------------------------------------------
Operational Risk RISK: The Company is subject to the risks associated
with owning oil and natural gas properties, including
environmental risks associated with air, land and water.
All of the Company's operations are conducted offshore
on the United Kingdom Continental Shelf and 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 Company has interests. As a
result, the Company 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 Company's control.
There are numerous uncertainties in estimating the
Company's reserve base due to the complexities in estimating
the magnitude and timing of future production, revenue,
expenses and capital.
MITIGATIONS: The Company acts at all times as a reasonable
and prudent operator and has non-operated interests
in assets where the designated operator is required
to act in the same manner. The Company takes out market
insurance to mitigate many of these operational, construction
and environmental risks. The Company uses experienced
service providers for the completion of work programmes.
The Company uses the services of Sproule International
Limited to independently assess the Company's reserves
on an annual basis.
---------------------------------------------------------------
Development Risk RISK: The Company is executing development projects
to produce reserves in offshore locations. These projects
are long term, capital intensive developments. Development
of these hydrocarbon reserves involves an array of
complex and lengthy activities. As a consequence, these
projects, among other things, are exposed to the volatility
of oil and gas prices and costs. In addition, projects
executed with partners and co-venturers reduce the
ability of the Company to fully mitigate all risks
associated with these development activities. Delays
in the achievement of production start-up may adversely
affect timing of cash flow and the achievement of short-term
targets of production growth.
MITIGATIONS: The Company places emphasis on ensuring
it attracts and engages with high quality suppliers,
subcontractors and partners to enable it to achieve
successful project execution. The Company seeks to
obtain optimal contractual agreements, including using
turnkey and lump sum incentivised contracts where appropriate,
when undertaking major project developments so as to
limit its financial exposure to the risks associated
with project execution.
----------------------------------------------------------------
Competition Risk RISK: In all areas of the Company's business, there
is competition with entities that may have greater
technical and financial resources.
MITIGATIONS: The Company places appropriate emphasis
on ensuring it attracts and retains high quality resources
and sufficient financial resources to enable it to
maintain its competitive position.
----------------------------------------------------------------
Weather Risk RISK: In connection with the Company's offshore operations
being conducted in the North Sea, the Company is especially
vulnerable to extreme weather conditions. Delays and
additional costs which result from extreme weather
can result in cost overruns, delays and, ultimately,
in certain operations becoming uneconomic.
MITIGATIONS: The Company takes potential delays as
a result of adverse weather conditions into consideration
in preparing budgets and forecasts and seeks to include
an appropriate buffer in its all estimates of costs,
which could be adversely affected by weather.
----------------------------------------------------------------
Reputation Risk RISK: In the event a major offshore incident were to
occur in respect of a property in which the Company
has an interest, the Company's reputation could be
severely harmed
MITIGATIONS: The Company's operational activities are
conducted in accordance with approved policies, standards
and procedures, which are then passed on to the Company's
subcontractors. In addition, Ithaca regularly audits
its operations to ensure compliance with established
policies, standards and procedures.
----------------------------------------------------------------
FORWARD-LOOKING INFORMATION
-----------------------------------------------------------------
Forward-Looking This MD&A and any documents incorporated by reference
Information Advisories herein contain certain forward-looking statements and
forward-looking information which are based on the
Company'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,
future acquisitions and dispositions 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 "forecasts", "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 Company 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 Company 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
Company'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;
* Future operating costs;
* 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 Company's ability to raise capital and the
potential sources thereof;
* The continued availability of the Facilities;
* Funding requirements prior to Stella start up;
* The sufficiency of the Facilities, cash balances and
forecast cash flow to cover anticipated future
commitments;
* Expected future net debt and continued deleveraging;
* The anticipated completion time of the FPF-1 offshore
commissioning programme, the anticipated Stella
start-up process steps, and Stella production ramp up
timings;
* The timing of Stella first hydrocarbons;
* Stella production ramp up time following first
hydrocarbons;
* Stella commissioning, offshore hook up and drilling
plans;
* The Company's acquisition and disposition strategy,
the criteria to be considered in connection therewith
and the benefits to be derived therefrom;
* The realisation of anticipated benefits from
acquisitions and dispositions;
* The anticipated effects of securing access to the GSA
oil export pipeline;
* The remaining work activities in respect of the GSA
oil export pipeline and the timing thereof;
* The anticipated timing for completion of licence
acquisitions;
* Expected future payments associated with licence
acquisitions;
* Statements related to reserves and resources other
than reserves;
* Development plans associated with pending licence
acquisitions, including field development plans and
the anticipated timing thereof;
* Anticipated benefits of development programmes;
* Anticipated cost to develop portfolio investment
opportunities;
* Potential investment opportunities and the expected
development costs thereof;
* The Company's ability to continually add to reserves;
* Schedules and timing of certain projects and the
Company's strategy for growth;
* The Company's future operating and financial results;
* The ability of the Company to optimise operations and
reduce operational expenditures;
* Treatment under governmental and other regulatory
regimes and tax, environmental and other laws;
* Production rates;
* The ability of the Company to continue operating in
the face of inclement weather;
* Targeted production levels;
* Timing and cost of the development of the Company's
reserves and resources other than reserves;
* Estimates of production volumes and reserves in
connection with acquisitions and certain projects;
* Estimated decommissioning liabilities;
* The timing and effects of planned maintenance
shutdowns;
* The expected impact on the Company's financial
statements resulting from changes in tax rates;
* The Company's expected tax horizon;
* Expected effects of fluctuations in foreign currency
exchange rates; and,
* Anticipated cost exposure resulting from third party
circumstances.
With respect to forward-looking statements contained
in this MD&A and any documents incorporated by reference
herein, the Company 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, both by the Company and its business
partners, is obtained within expected timeframes;
* Ithaca's ability to receive necessary regulatory and
partner approvals in connection with acquisitions and
dispositions;
* The Company's development plan for its properties
will be implemented as planned;
* The market for potential opportunities from time to
time and the Company's ability to successfully pursue
opportunities;
* The Company's ability to keep operating during
periods of harsh weather;
* The timing of anticipated shutdowns;
* Reserves volumes assigned to Ithaca's properties;
* Ability to recover reserves volumes assigned to
Ithaca's properties;
* Revenues do not decrease significantly 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 Company's ability to access
the Facilities;
* The continued ability of the Company to collect
amounts receivable from third parties who Ithaca has
provided credit to;
* 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 Company'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 risks of inclement weather and
the unavailability of 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 Company to fund its substantial
capital requirements and operations and the terms of
such funding;
* Risks associated with ensuring title to the Company's
properties;
* Changes in environmental, health and safety or other
legislation applicable to the Company's operations,
and the Company'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 Company's exploration and development drilling
and estimated decline rates;
* The Company's success at acquisition, exploration,
exploitation and development of reserves and
resources other than reserves;
* Risks associated with satisfying conditions to
closing acquisitions and dispositions;
* Risks associated with realisation of anticipated
benefits of acquisitions and dispositions;
* Risks related to changes to government policy with
regard to offshore drilling;
* The Company's reliance on key operational and
management personnel;
* The ability of the Company to obtain and maintain all
of its required permits and licences;
* 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 or Norwegian taxes;
* Adverse regulatory or court rulings, orders and
decisions; and,
* Risks associated with the nature of the common
shares.
Additional Reader The information in this MD&A is provided as of 11 November
Advisories 2016. The Q3 2016 results have been compared to the
results of the comparative period in 2015. This MD&A
should be read in conjunction with the Company's unaudited
consolidated financial statements as at 30 September
2016 and 2015 together with the accompanying notes
and Annual Information Form ("AIF") for the year ended
31 December 2015. These documents, and additional information
regarding Ithaca, are available electronically from
the Company's website (www.ithacaenergy.com) or SEDAR
profile at www.sedar.com.
-----------------------------------------------------------------
Consolidated Statement of Income
For the three and nine months ended 30 September
2016 and 2015
(unaudited)
Three months ended Nine months ended
30 September 30 September
2016 2015 2016 2015
Note US$'000 US$'000 US$'000 US$'000
-------------------------------------- ----- ---------- --------- ---------- ----------
Revenue 5 44,585 42,108 102,345 171,635
- Operating costs (19,112) (25,760) (61,145) (83,383)
- Movement in oil and gas
inventory (5,586) 4,676 5,404 (8,447)
- Depletion, depreciation
and amortisation (21,705) (30,946) (59,088) (93,205)
-------------------------------------- ----- ---------- --------- ---------- ----------
Cost of sales (46,403) (52,030) (114,829) (185,035)
Gross (Loss) (1,818) (9,922) (12,484) (13,400)
Exploration and evaluation
expenses 10 (20) (620) (839) (29,720)
Gain on disposal - 1,034 - 26,271
Gain/(Loss) on financial instruments 26 3,006 74,894 (25,268) 94,185
Administrative expenses 6 (1,011) (2,747) (4,303) (8,238)
Foreign exchange 2,130 2,354 3,036 (1,656)
Finance costs 7 (9,094) (9,464) (27,601) (30,360)
Interest income 8 11 58 62
-------------------------------------- ----- ---------- --------- ---------- ----------
(Loss)/Profit Before Tax (6,799) 55,540 (67,401) 37,144
Taxation 24 (63,895) (12,728) 2,953 19,475
-------------------------------------- ----- ---------- --------- ---------- ----------
(Loss)/ Profit After Tax (70,694) 42,812 (64,448) 56,619
Earnings per share
Basic 23 (0.17) 0.13 (0.16) 0.17
Diluted 23 (0.17) 0.13 (0.16) 0.17
No separate statement of comprehensive income has been prepared as all such gains and losses have been incorporated in the consolidated statement of income above.
The accompanying notes on pages 6 to 23 are an integral part of the financial statements.
Consolidated Statement of Financial
Position
(unaudited)
30 September 31 December
2016 2015
US$'000
------------------------------------------------ ---------------------------
Note US$'000
-------------- ------------ --- ------------- ----------- ---------- ----------- ------------
ASSETS
Current assets
Cash and cash equivalents 29,772 11,543
Accounts receivable 8 224,229 223,006
Deposits, prepaid expenses and
other 1,747 743
Inventory 9 26,162 20,900
Derivative financial instruments 27 32,549 126,887
314,459 383,079
Non current assets
Long-term receivable 29 60,136 61,052
Long-term inventory 9 7,908 7,908
Investment in associate 13 18,337 18,337
Exploration and evaluation assets 10 16,883 11,223
Property, plant & equipment 11 1,103,284 1,102,046
Deferred tax assets 356,757 355,726
Goodwill 12 123,510 123,510
------------------------------------------------ ----------- --------------------------- ------------
1,686,815 1,679,802
Total assets 2,001,274 2,062,881
LIABILITIES AND EQUITY
Current liabilities
Trade and other payables 15 (298,578) (275,907)
Exploration obligations 16 (4,000) (4,000)
Contingent consideration 20 (4,000) (4,000)
Derivative financial instruments 27 (2,175) -
--------------------------- ------------
(308,753) (283,907)
Non current liabilities
Borrowings 14 (620,427) (666,130)
Decommissioning liabilities 17 (233,200) (226,915)
Other long term liabilities 18 (107,473) (92,543)
Derivative financial instruments 27 - (197)
(961,100) (985,785)
Net Assets 731,421 793,189
------------------------------------------------ ----------- --------------------------- ------------
Shareholders' equity
Share capital 21 617,721 617,375
Share based payment reserve 22 25,012 22,678
Retained earnings 88,688 153,136
------------
Total equity 731,421 793,189
------------------------------------------------ ----------- --------------------------- ------------
The financial statements were approved by the Board of Directors
on 11 November 2016 and signed on its behalf by:
"Les Thomas"
------------------------------------------------
Director
"Alec Carstairs"
------------------------------------------------
Director
The accompanying notes on pages 6 to 23 are an integral
part of the financial statements.
Consolidated Statement of Changes
in Equity
(unaudited)
Share Share based Retained Total
Capital payment Earnings
reserve
US$'000 US$'000 US$'000 US$'000
---------------------------------- ------------- --------------- ---------- -----------
Balance, 1 Jan 2015 551,632 19,234 274,141 845,007
Share based payment - 3,089 - 3,089
Profit for the period - - 56,619 56,619
Balance, 30 September
2015 551,632 22,323 330,760 904,715
---------------------------------- ------------- --------------- ---------- -----------
Balance, 1 Jan 2016 617,375 22,678 153,136 793,189
Share based payment - 2,234 - 2,334
Shares exercised 346 - - 346
(Loss) for the period - - (64,448) (64,448)
Balance, 30 September
2016 617,721 25,012 88,688 731,421
---------------------------------- ------------- --------------- ---------- -----------
The accompanying notes on pages 6 to 23 are an integral part of the financial statements.
Consolidated Statement of Cash Flow
For the three and nine months ended 30 September
2016 and 2015
(unaudited)
Three months ended Nine months ended
30 Sept 30 Sept
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
------------------------------------ --------- --------------------- --------- ------------ -------------------
CASH PROVIDED BY (USED
IN):
Operating activities
Loss Before Tax (6,799) 55,540 (67,401) 37,144
Adjustments for:
Depletion, depreciation and
amortisation 11 21,705 30,946 59,088 93,206
Exploration and evaluation
expenses 10 20 620 839 29,721
Onerous contracts - (914) - (20,916)
Share based payment 170 238 502 627
Loan fee amortisation 1,040 1,267 3,119 4,324
Revaluation of financial instruments 26 10,944 (39,129) 96,097 52,088
Gain on disposal - (1,034) - (26,271)
Accretion 17 2,316 2,285 6,883 6,784
Bank interest & charges 5,738 5,913 17,599 19,252
---------------------------------------------- ----- --------------- --------- ------------ -------------------
Cashflow from operations 35,134 55,732 116,726 195,958
---------------------------------------------- ----- --------------- --------- ------------ -------------------
Changes in inventory, receivables
and payables relating to operating
activities (1,466) (10,353) (1,071) (35,437)
Petroleum Revenue Tax refunded/(paid) - 1,140 (916) (3,303)
Corporation Tax refunded - - 6,009 -
----------------------------------------------------- ----------- --------- ------------ -------------------
Net cash from operating activities 33,668 46,519 120,748 157,218
---------------------------------------------- ----- --------------- --------- ------------ -------------------
Investing activities
Capital expenditure (37,765) (40,283) (63,890) (158,229)
Loan to associate 125 183 1,126 (279)
Decommissioning 17 (712) - (2,877) -
Proceeds on disposal - 32,521 - 32,521
Changes in receivables and payables
relating to investing activities 20,462 13,450 21,797 (15,843)
----------------------------------------------------- --------------- --------- ------------ -------------------
Net cash (used)/from investing
activities (17,890) 5,871 (43,844) (141,830)
----------------------------------------------------- ----------- --------- ------------ -------------------
Financing activities
Proceeds from issuance of shares - - 346 -
Loan (repayment)/draw down (3,875) (51,500) (48,875) 3,688
Bank interest and charges (7,682) (15,682) (9,083) (26,993)
----------------------------------------------------- ----------- --------- ------------ -------------------
Net cash from financing activities (11,557) (67,182) (57,612) (23,305)
----------------------------------------------------- ----------- --------- ------------ -------------------
Currency translation differences
relating to cash (301) (177) (1,063) (1,010)
Increase/(decrease) in cash and
cash equivalents 3,920 (14,969) 18,229 (8,927)
------------------------------------------------------------- ------- --------- ------------ -------------------
Cash and cash equivalents, beginning
of period 25,852 25,423 11,543 19,381
Cash and cash equivalents, end
of period 29,772 10,454 29,722 10,454
----------------------------------------------------- --------------- --------- ------------ -------------------
The accompanying notes on pages 6 to 23 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 development and production of oil and gas in the North Sea. The Corporation's registered office is 1600, 333 - 7th Avenue S.W., Calgary, Alberta, Canada, T2P 2Z1. The Corporation's shares trade on the Toronto Stock Exchange in Canada and the London Stock Exchange's Alternative Investment Market in the United Kingdom under the symbol "IAE".
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 policies applied in these condensed interim consolidated financial statements are based on IFRS issued and outstanding as of 11 November 2016, 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 2016 could result in restatement of these interim consolidated financial statements.
The consolidated financial statements have been prepared on a going concern basis using the historical cost convention, except for financial instruments which are measured at fair value.
The consolidated financial statements are presented in US dollars and all values are rounded to the nearest thousand (US$'000), except when otherwise indicated.
The condensed interim consolidated financial statements should be read in conjunction with the Corporation's annual financial statements for the year ended 31 December 2015.
3. SIGNIFICANT ACCOUNTING POLICIES, JUDGEMENTS AND ESTIMATION UNCERTAINTY
Basis of measurement
The interim consolidated financial statements have been prepared under the historical cost convention, except for the revaluation of certain financial assets and financial liabilities (under IFRS) to fair value, including derivative instruments.
Basis of consolidation
The interim consolidated financial statements of the Corporation include the financial statements of Ithaca Energy Inc. and all wholly-owned subsidiaries as listed per note 29. Ithaca has twenty wholly-owned subsidiaries. All inter-company transactions and balances have been eliminated on consolidation.
Subsidiaries are all entities, including structured entities, over which the group has control. The group controls an entity when the group is exposed to or has rights to variable returns from its investments with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the group. They are deconsolidated on the date that control ceases.
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 acquired, the difference is recognised directly in the statement of income as negative goodwill.
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.
Interest in joint arrangements and associates
Under IFRS 11, joint arrangements are those that convey joint control which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. Associates are investments over which the Corporation has significant influence but not control or joint control, and generally holds between 20% and 50% of the voting rights.
Under the equity method, investments are carried at cost plus post-acquisition changes in the Corporation's share of net assets, less any impairment in value in individual investments. The consolidated statement of income reflects the Corporation's share of the results and operations after tax and interest.
The Corporation's interest in joint operations (eg exploration and production arrangements) are accounted for by recognising its assets (including its share of assets held jointly), its liabilities (including its share of liabilities incurred jointly), its revenue from the sale of its share of the output arising from the joint operation, its share of revenue from the sale of output by the joint operation and its expenses (including its share of any expenses incurred jointly).
Revenue
Oil, gas and condensate revenues associated with the sale of the Corporation's crude oil and natural gas are recognised when title passes to the customer. This generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism. Revenues from the production of oil and natural gas properties in which the Corporation has an interest with joint venture partners are recognised on the basis of the Corporation's working interest in those properties (the entitlement method). Differences between the production sold and the Corporation's share of production are recognised within cost of sales at market value.
Interest income is recognised on an accruals basis and is separately recorded on the face of the statement of income.
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 21 (c). The expense is recorded in the consolidated 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 share based compensation 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 the statement of cash flow, cash and cash equivalents include investments with an original maturity of three months or less.
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, accounts receivable, deposits, derivatives, accounts payable, accrued liabilities, contingent consideration and borrowings. 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.
Analysis of the fair values of financial instruments and further details as to how they are measured are provided in notes 26 to 28.
Inventory
Inventories of materials and product inventory supplies are stated at the lower of cost and net realisable value. Cost is determined on the first-in, first-out method. Current oil and gas inventories are stated at fair value less cost to sell. Non-current oil and gas inventories are stated at historic cost.
Trade receivables
Trade receivables are recognised and carried at the original invoiced amount, less any provision for estimated irrecoverable amounts.
Trade payables
Trade payables are measured at cost.
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, administrative and share based payment expenses 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 CGUs 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 statement of income.
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, direct costs including staff costs and share based payment expense 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.
Borrowings
All interest-bearing loans and other borrowings with banks are initially recognised at fair value net of directly attributable transaction costs. After initial recognition, interest-bearing loans and other borrowings are subsequently measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs, discount or premium.
Loan origination fees are capitalised and amortised over the term of the loan. Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets until such time as the assets are substantially ready for their intended use of sale. All other borrowing costs are expensed as incurred.
Senior notes are measured at amortised cost.
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.
Onerous contracts
Onerous contract provisions are recognised where the unavoidable costs of meeting the obligations under a contract exceed the economic benefits expected to be received under it.
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.
Deferred tax assets and liabilities are offset only when a legally enforceable right of offset exists and the deferred tax assets and liabilities arose in the same tax jurisdiction.
Petroleum Revenue Tax
In addition to corporate income taxes, the Group's financial statements also include and disclose Petroleum Revenue Tax (PRT) on net income determined from oil and gas production.
PRT is accounted for under IAS 12 since it has the characteristics of an income tax as it is imposed under Government authority and the amount payable is based on taxable profits of the relevant field. Deferred PRT is accounted for on a temporary difference basis.
Operating leases
Rentals under operating leases are charged to the statement of income on a straight line basis over the period of the lease.
Finance leases
Finance leases that transfer substantially all the risks and benefits incidental to ownership of the leased item to the Corporation, are capitalised at the commencement of the lease at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Lease payments are apportioned between finance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are recognised in finance costs in the income statement. A leased asset is depreciated over the useful life of the asset. However, if there is no reasonable certainty that the Corporation will obtain ownership by the end of the lease term, the asset is depreciated over the shorter of the estimated useful life of the asset and the lease term.
Maintenance expenditure
Expenditure on major maintenance refits or repairs is capitalised where it enhances the life or performance of an asset above its originally assessed standard of performance; replaces an asset or part of an asset which was separately depreciated and which is then written off, or restores the economic benefits of an asset which has been fully depreciated. All other maintenance expenditure is charged to the statement of income as incurred.
Recent accounting pronouncements
New and amended standards and interpretations need to be adopted in the first interim financial statements issued after their effective date (or date of early adoption). There are no new IFRSs or IFRICs that are effective for the first time for this interim period that would be expected to have a material impact on the Corporation.
Significant accounting judgements and estimation uncertainties
The preparation of financial statements in conformity with IFRS requires management to make estimates and assumptions regarding certain assets, liabilities, revenues and expenses. Such estimates must often be made based on unsettled transactions and other events and a precise determination of many assets and liabilities is dependent upon future events. Actual results may differ from estimated amounts.
The amounts recorded for depletion, depreciation of property and equipment, long-term liability, stock-based compensation, contingent consideration, decommissioning liabilities, derivatives 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. Further information on each of these estimates is included within the notes to the financial statements.
4. SEGMENTAL REPORTING
The Company operates a single class of business being oil and gas exploration, development and production and related activities in a single geographical area presently being the North Sea.
5. REVENUE
Three months ended Nine months ended
30 Sept 30 Sept
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
------------------ ---------- --------- --------- ---------
Oil sales 43,404 41,380 98,938 167,054
Gas sales 1,039 542 2,934 3,782
Condensate sales 114 85 392 375
Other income 28 101 81 424
------------------ ---------- --------- --------- ---------
44,585 42,108 102,345 171,635
6. ADMINISTRATIVE EXPENSES
Three months ended 30 Sept Nine months ended
30 Sept
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
-------------------------- --------- --------- --------- ---------
General & administrative (841) (2,509) (3,802) (7,611)
Share based payment (170) (238) (501) (627)
-------------------------- --------- --------- --------- ---------
(1,011) (2,747) (4,303) (8,238)
7. FINANCE COSTS
Three months ended Nine months ended
30 Sept 30 Sept
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
---------------------------- ---------- --------- --------- ---------
Bank interest and charges (946) (1,630) (3,228) (6,258)
Senior notes interest (3,830) (3,830) (11,489) (11,179)
Finance lease interest (247) (260) (751) (791)
Non-operated asset finance
fees (9) (11) (21) (61)
Prepayment interest (706) (181) (2,110) (963)
Loan fee amortisation (1,040) (1,267) (3,119) (4,324)
Accretion (2,316) (2,285) (6,883) (6,784)
---------------------------- ---------- --------- --------- ---------
(9,094) (9,464) (27,601) (30,360)
8. ACCOUNTS RECEIVABLE
30 Sept 31 Dec
2016 2015
US$'000 US$'000
---------------- --------- ---------
Trade debtors 223,319 222,010
Accrued income 910 996
---------------- --------- ---------
224,229 223,006
9. INVENTORY
30 Sept 31 Dec
2016 2015
Current US$'000 US$'000
--------------------- -------------------- ---------
Crude oil inventory 24,301 18,721
Materials inventory 1,861 2,179
--------------------- -------------------- ---------
26,162 20,900
30 Sept 31 Dec
2016 2015
Non-current US$'000 US$'000
--------------------- -------------------- ---------
Crude oil inventory 7,908 7,908
The non-current portion of inventory relates to long term stocks at the Sullom Voe Terminal.
10. EXPLORATION AND EVALUATION ASSETS
US$'000
---------------------------------------- --------------------
At 1 January 2015 89,844
Additions 30,263
Disposals (44,005)
Release of exploration obligations (1,431)
Write offs/relinquishments (30,522)
Impairment (32,926)
At 31 December 2015 and 1 January 2016 11,223
Additions 6,498
Write offs/relinquishments (838)
---------------------------------------- --------------------
At 30 September 2016 16,883
Following completion of geotechnical evaluation activity, certain North Sea licences were declared unsuccessful and certain prospects were declared non-commercial. This resulted in the carrying value of these licences being fully written off to nil with $0.8 million being expensed in the period to 30 September 2016.
11. PROPERY, PLANT AND EQUIPMENT
Development & Production Other fixed
Oil and Gas assets assets Total
US$'000 US$'000 US$'000
---------------------------- --------------------------- ----------------------- ------------------
Cost
At 1 January 2015 2,341,069 4,140 2,345,209
Additions 141,318 717 142,035
Disposals - (1,451) (1,451)
Release of onerous contract
provision (377) - (377)
At 31 December 2015 and 1
January 2016 2,482,010 3,406 2,485,416
Additions 60,323 3 60,326
At 30 September 2016 2,542,333 3,409 2,545,742
DD&A and Impairment
At 1 January 2015 (907,305) (2,695) (910,000)
DD&A charge for the period (119,768) (462) (120,230)
Disposals - 613 613
Impairment charge for the
period (353,753) - (353,753)
At 31 December 2015 and 1 January 2016 (1,380,826) (2,544) (1,383,370) DD&A charge for the period (58,881) (207) (59,088) At 30 September 2016 (1,439,707) (2,751) (1,442,458) NBV at 1 January 2015 1,433,764 1,445 1,435,209 NBV at 1 January 2016 1,101,184 862 1,102,046 NBV at 30 September 2016 1,102,626 658 1,103,284
The net book amount of property, plant and equipment includes $28.9 million (31 December 2015: $30.2 million) in respect of the Pierce FPSO lease held under finance lease.
12. GOODWILL
30 Sept 31 Dec
2016 2015
US$'000 US$'000
----------------- --------- ---------
Closing balance 123,510 123,510
$123.5 million goodwill represents $136.1 million recognised on the acquisition of Summit Petroleum Limited ("Summit") in July 2014 as a result of recognising a $136.9 million deferred tax liability as required under IFRS 3 fair value accounting for business combinations. Absent the deferred tax liability the price paid for the Summit assets equated to the fair value of the assets. $1.0 million represented goodwill recognised on the acquisition of gas assets from GDF in December 2010. As at 31 December 2015 a non-taxable impairment of $13.6 million was recorded relating to goodwill.
13. INVESTMENT IN ASSOCIATES
30 Sept 31 Dec
2016 2015
US$'000 US$'000
--------------------------------------- --------- ---------
Investments in FPF-1 and FPU services 18,337 18,337
Investment in associates comprises shares, acquired by Ithaca Energy (Holdings) Limited, in FPF-1 Limited and FPU Services Limited as part of the completion of the Greater Stella Area transactions in 2012. There has been no change in value during the period with the above investment reflecting the Corporation's share of the associates' results.
14. BORROWINGS
30 Sept 31 Dec
2016 2015
US$'000 US$'000
----------------------------- ---------- ----------
RBL facility (327,918) (376,793)
Senior notes (300,000) (300,000)
Long term bank
fees 4,452 6,779
Long term senior notes fees 3,039 3,884
----------------------------------- ---------- ----------
(620,427) (666,130)
Bank debt facilities
The Company's bank debt facilities are sized at $535 million: a $475 million senior RBL and a $60 million junior RBL. Both RBL facilities are based on conventional oil and gas industry borrowing base financing terms, with loan maturities in September 2018, and are available to fund on-going development activities and general corporate purposes. The combined interest rate of the two bank debt facilities, fully drawn, is LIBOR plus 3.4% prior to Stella coming on-stream, stepping down to LIBOR plus 2.9% after Stella production has been established.
The availability to draw upon the facilities is reviewed by the bank syndicate on a semi-annual basis, with the results of the October 2016 redetermination resulting in debt availability of over $410 million.
Senior Reserves Based Lending Facility
As at 30 September 2016, the Corporation has a Senior Reserved Based Lending ("Senior RBL") Facility of $475 million. As at 30 September 2016, $327.9 million (31 December 2015: $377 million) was drawn down under the Senior RBL. $4.5 million (31 December 2015: $6.8 million) of loan fees relating to the RBL have been capitalised and remain to be amortised.
Junior Reserves Based Lending Facility
As at 30 September 2016, the Corporation had a Junior Reserved Based Lending ("Junior RBL") Facility of $60 million. The facility remains undrawn at the quarter end.
Senior Notes
As at 30 September 2016, the Corporation had $300 million 8.125% senior unsecured notes due July 2019, with interest payable semi-annually. $3.0 million of loan fees (31 December 2015: $3.9 million) have been capitalised and remain to be amortised.
Covenants
The Corporation is subject to financial and operating covenants related to the facilities. Failure to meet the terms of one or more of these covenants may constitute an event of default as defined in the facility agreements, potentially resulting in accelerated repayment of the debt obligations.
The Corporation was in compliance with all its relevant financial and operating covenants during the period.
The key covenants in both the Senior and Junior RBLs are:
- A corporate cashflow projection showing total sources of funds must exceed total forecast uses of funds for the later of the following 12 months or until forecast first oil from the Stella field.
- The ratio of the net present value of cashflows secured under the RBL for the economic life of the fields to the amount drawn under the facility must not fall below 1.15:1
- The ratio of the net present value of cashflows secured under the RBL for the life of the debt facility to the amount drawn under the facility must not fall below 1.05:1.
There are no financial maintenance covenants tests under the senior notes.
Security provided against the facilities
The RBL facilities are secured by the assets of the guarantor member of the Ithaca Group, such security including share pledges, floating charges and/or debentures.
The Senior notes are unsecured senior debt of Ithaca Energy Inc., guaranteed by certain members of the Ithaca Group and subordinated to existing and future secured obligations.
15. TRADE AND OTHER PAYABLES
30 Sept 31 Dec
2016 2015
US$'000 US$'000
------------------------------ ---------- ----------
Trade payables (128,232) (129,719)
Accruals and deferred income (170,346) (146,188)
(298,578) (275,907)
16. EXPLORATION OBLIGATIONS
30 Sept 31 Dec
2016 2015
US$'000 US$'000
------------------------- --------- ---------
Exploration obligations (4,000) (4,000)
The above reflects the fair value of E&E commitments assumed as part of the Valiant transaction.
17. DECOMMISSIONING LIABILITIES
30 Sept 31 Dec
2016 2015
US$'000 US$'000
------------------------------------ --------------------- ----------------------
Balance, beginning of period (226,915) (213,105)
Additions (2,279) -
Accretion (6,883) (9,092)
Revision to estimates - (4,718)
Decommissioning provision utilised 2,877 -
Balance, end of period (233,200) (226,915)
The total future decommissioning liability was calculated by management based on its net ownership interest in all wells and facilities, estimated costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. The Corporation uses a risk free rate of 4.0 percent (31 December 2015: 4.0 percent) and an inflation rate of 2.0 percent (31 December 2015: 2.0 percent) over the varying lives of the assets to calculate the present value of the decommissioning liabilities. These costs are expected to be incurred at various intervals over the next 21 years.
The economic life and the timing of the obligations are dependent on Government legislation, commodity price and the future production profiles of the respective production and development facilities.
18. OTHER LONG TERM LIABILITIES
30 Sept 31 Dec
2016 2015
US$'000 US$'000
------------------------ ---------- ----------------------
Shell prepayment (63,629) (62,227)
BP gas prepayment (13,687) -
Finance lease acquired (30,157) (30,316)
Balance, end of period (107,473) (92,543)
The prepayment balance relates to cash advances under the Shell oil sales agreement and BP gas sales agreement which have been classified as long-term liabilities as short-term repayment is not due in the current oil price environment. The finance lease relates to the Pierce FPSO acquired as part of the Summit acquisition.
19. FINANCE LEASE LIABILITIES
30 Sept 31 Dec 31 Dec
2016 2015 2013
US$'000 US$'000 US$'000
----------------------------------------- --------- ---------
Total minimum lease payments
Less than 1 year (2,595) (2,602) -
Between 1 and 5 years (12,468) (12,570) -
5 years and later (21,663) (23,502) -
Interest
Less than 1 year (953) (994) -
Between 1 and 5 years (3,907) (4,123) -
5 years and later (3,076) (3,569) -
Present value of minimum lease payments
Less than 1 year (1,642) (1,608) -
Between 1 and 5 years (8,561) (8,447) -
5 years and later (18,587) (19,933) -
----------------------------------------- --------- ---------
The finance lease relates to the Pierce FPSO acquired as part of the Summit acquisition in July 2014.
20. CONTINGENT CONSIDERATION
30 Sept 31 Dec
2016 2015
US$'000 US$'000
--------------------- --------- ---------
Balance outstanding (4,000) (4,000)
The contingent consideration at the end of the period relates to the acquisition of the Stella field and is payable upon first oil.
21. SHARE CAPITAL
No. of common Amount
Authorised share capital shares US$'000
------------------------------------------ -------------- ---------
At 30 September 2016 and 31 December 2015 Unlimited -
(a) Issued
The issued share capital is as follows:
Issued Number of common Amount
shares US$'000
------------------------------------- ------------------- ----------------------
Balance 1 January 2016 411,384,045 617,375
Issued for cash - options exercised 400,000 346
Balance 30 September 2016 411,784,045 617,721
(b) Stock options
In the nine months ended 30 September 2016, the Corporation's Board of Directors granted 12,000,000 options at an exercise price of $0.40 (C$0.55).
The Corporation's stock options and exercise prices are denominated in Canadian Dollars when granted. As at 30 September 2016, 28,313,137 stock options to purchase common shares were outstanding, having an exercise price range of $0.40 to $2.51 (C$0.55 to C$2.71) 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 2016 31 December 2015
--------------------- ---------------------------------- ---------------------------
Wt. Avg
Wt. Avg Exercise
No. of Options Exercise Price* No. of Options Price*
--------------------- --------------- ----------------- --------------- ----------
Balance, beginning
of period 19,216,206 $1.70 24,232,428 $1.81
Granted 12,000,000 $0.40 950,000 $0.84
Forfeited / expired (2,503,069) $1.63 (5,966,222) $2.05
Exercised (400,000) $0.62 - -
--------------------- --------------- ----------------- --------------- ----------
Options 28,313,137 $1.16 19,216,206 $1.70
--------------------- --------------- ----------------- --------------- ----------
* 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 2016.
Options Outstanding Options Exercisable
--------------------------------------------------------------- ---------------------------------------------------------
Wt.
Wt. Avg Wt. Avg Range of Avg Wt. Avg
Range of No. of Life Exercise Exercise No. of Options Life Exercise
Exercise Price Options (Years) Price* Price (Years) Price*
----------------- ----------- ------------------- ---------- ------------ ----------------- ------------ ----------
$2.46-$2.51 $2.46-$2.51
(C$2.53-C$2.71) 6,373,136 1.2 $2.47 (C$2.53-C$2.71) 4,503,136 1.2 $2.47
$0.84-$2.03 $0.84-$2.03
(C$1.04-C$1.99) 10,490,001 1.6 $1.20 (C$1.04-C$1.99) 5,680,001 1.1 $1.47
$0.40 (C$0.55) 11,450,000 3.2 $0.40 $0.40 (C$0.55) 200,000 0.7 $0.40
----------------- ----------- ------------------- ---------- ------------------ ----------- ------------ ------------
28,313,137 2.2 $1.16 10,083,137 1.1 $1.89
================= =========== =================== ========== ================== =========== ============ ============
The following is a summary of stock options as at 31 December 2015.
Options Outstanding Options Exercisable
------------------------------------------------------- ---------------------------------------------------------
Wt.
Wt. Avg Wt. Avg Avg Wt. Avg
Range of No. of Life Exercise Range of No. of Life Exercise
Exercise Price Options (Years) Price* Exercise Price Options (Years) Price*
----------------- ----------- ----------- ---------- ------------------ ---------- ------------- ----------
$2.28-$2.52
$2.28-$2.52
(C$2.31-C$2.71) 7,326,205 1.9 $2.46 (C$2.31-C$2.71) 2,953,333 1.6 $2.44
$0.84-$2.03
$0.84-$2.03
(C$1.04-C$1.99) 11,890,001 2.4 $1.22 (C$1.04-C$1.99) 5,800,001 1.7 $1.54
----------------- ----------- ----------- ---------- ------------------ ---------- ------------- ----------
19,216,206 2.2 $1.70 8,753,334 1.7 $1.84
================= =========== =========== ========== ================== ========== ============= ==========
(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 2016 for total stock options granted was $0.7 million and $2.4 million respectively (Q3 2015: $1.1 million, Q3 YTD 2015: $3.1 million). $0.2 million and $0.3 million were charged through the income statement for share based payment for the three and nine months ended 30 September 2016 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 nine months For the year ended
ended 30 September 31 December 2015
2016
----------------------------- -------------------- -------------------
Risk free interest rate 0.53% 0.65%
Expected stock volatility 60% 59%
Expected life of options 3 years 3 years
Weighted Average Fair Value C$0.22 C$0.43
22. SHARE BASED PAYMENT RESERVE
30 Sept 31 Dec
2016 2015
US$'000 US$'000
------------------------------ --------------------- ---------------------
Balance, beginning of period 22,678 19,234 Share based payment cost 2,334 3,444 Balance, end of period 25,012 22,678 23. EARNINGS PER SHARE
The calculation of basic earnings per share is based on the profit after tax and the weighted average number of common shares in issue during the period. The calculation of diluted earnings per share is based on the profit after tax and the weighted average number of potential common shares in issue during the period.
Three months ended Nine months ended
30 Sept 30 Sept
2016 2015 2016 2015
--------------------------------- ------------ ------------ ------------ ------------
Wtd av. number of common shares
(basic) 411,784,045 329,518,620 411,519,811 329,518,620
Wtd av. number of common shares
(diluted) 418,627,887 329,518,620 412,945,290 329,518,620
24. TAXATION
Three months ended Nine months ended
30 Sept 30 Sept
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
----------------------------- ----------- --------- --------- ----------
Taxation (charge)/credit (63,895) (12,728) 2,953 19,475
It was announced in the UK Budget on 16 March 2016 that the rate of Petroleum Revenue Tax ("PRT") was effectively abolished from 1 January 2016 with the introduction of a 0% PRT rate. This eliminated the Company's future PRT tax charge from 1 January 2016. The PRT rate change was enacted in March 2016 and resulted in a credit of $24.2 million in the Q1 2016 results.
Further, it was also announced that the Supplementary Charge in respect of ring fence trades ("SCT") would be reduced from 20% to 10% with effect from 1 January 2016. This has reduced the Company's future SCT charge charge accordingly. The rate change was enacted in September 2016 and the impact of the 10% reduction in the Supplementary Charge was to reduce the net deferred tax assets by $74.7 million. Coupled with the CT impact of the PRT rate change noted above of $11.2 million this gives an overall rate change driven CT charge for the nine months to 30 September 2016 of $85.9 million
In accordance with the Stella Sale and Purchase Agreement ("SPA"), Ithaca receives the right to claim a tax benefit for additional capital allowances on certain capital expenditures incurred by Ithaca and paid for by Petrofac on the Stella project.
The tax benefit of these capital allowances is received by Ithaca as the expenditure is incurred. In recognition of the benefit Ithaca receives from the additional capital allowances a payment is expected to be made to Petrofac 5 years after Stella first oil of a sum calculated at the prevailing tax rate applied to the relevant capital allowances, in accordance with the SPA. The taxation charge above includes a deferred tax credit of $9.0 million for the three months ended 30 September 2016. The related deferred tax asset (adjusting for the SCT rate change) as at 30 September 2016 is $81.0 million.
25. COMMITMENTS
30 Sept 31 Dec
2016 2015
US$'000 US$'000
----------------------------- ---------------------- -------------
Operating lease commitments
Within one year 240 240
Two to five years 120 300
30 Sept 31 Dec
2016 2015
US$'000 US$'000
----------------------------------------------------- ----------- ---------
Capital commitments
Capital commitments incurred jointly with other
ventures (Ithaca's share) 15,756 9,534
In addition to the amounts above, during the year Ithaca has entered into an agreement with Petrofac in respect of the FPF-1 Floating Production facility.
Ithaca will pay Petrofac $13.7 million in respect of final payment on variations to the contract, with payment deferred until three and a half years after first production from the Stella field. A further payment to Petrofac of up to $34 million was to be made by Ithaca dependent on the timing of sail-away of the FPF-1. This further payment has been revised to $17 million. This payment will also be deferred until three and a half years after first production from the Stella field.
26. 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 2016:
Total Fair
Level 1 Level 2 Level 3 Value
US$'000 US$'000 US$'000 US$'000
--------------------------------- ---------- --------- --------- -----------
Derivative financial instrument
asset - 32,549 - 32,549
Contingent consideration - (4,000) - (4,000)
Derivative financial instrument
liability - (2,175) - (2,175)
--------------------------------- ---------- --------- --------- -----------
The table below presents the total gain/(loss) on financial instruments that has been disclosed through the statement of comprehensive income:
Three months ended Nine months ended
30 Sept 30 Sept
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
--------------------------------- --------- --------------------- --------------------- --------------------
Revaluation of forex forward
contracts 2,955 (3,254) (2,322) 1,785
Revaluation of other long
term liability - - - 307
Revaluation of commodity
hedges (14,001) 41,769 (93,919) (54,529)
Revaluation of interest
rate swaps 102 614 144 349
--------------------------------- --------- --------------------- --------------------- --------------------
(10,944) 39,129 (96,097) (52,088)
Realised (loss)/gain on
forex contracts (4,076) 614 (5,027) 1,221
Realised gain on commodity
hedges 18,104 35,132 76,091 145,238
Realised (loss)/gain on
interest rate swaps (78) 19 (235) (186)
--------------------------------- --------- --------------------- --------------------- --------------------
13,950 35,765 70,829 146,273
--------------------- --------------------- --------------------
Total gain/(loss) on financial
instruments 3,006 74,894 (25,268) 94,185
The Corporation has identified that it is exposed principally to these areas of market risk.
i) Commodity Risk
The table below presents the total gain/(loss) on commodity hedges that has been disclosed through the statement of income at the quarter end:
Three months ended 30 Sept Nine months ended
30 Sept
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
--------------------------------- ------------------ --------- --------- ---------
Revaluation of commodity hedges (14,001) 41,769 (93,919) (54,529)
Realised gain on commodity
hedges 18,104 35,132 76,091 145,238
--------------------------------- ------------------ --------- --------- ---------
Total gain/(loss) on commodity
hedges 4,103 76,901 (17,828) 90,709
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.
The below represents commodity hedges in place at the quarter end:
Derivative Term Volume Average price
----------- ------------- ----------- ------- --------------
Oil swaps Oct 16 - Jun
17 1,037,744 bbls $68.75/bbl
Gas swaps Oct 16 - Mar therms
17 3,065,288 47p/therm
Gas puts Oct 16 - Jun therms
17 59,200,000 63p/therm
In mid October 2016 the Company entered into additional hedging contracts for 1.5 million barrels of 2017 oil production. 750,002 barrels have been hedged using collars with a floor price of $46/bbl and a celling price of $60/bbl and 750,000 barrels have been hedged using put options with a floor price of $53/bbl.
ii) Interest Risk
The table below presents the total gain/(loss) on interest financial instruments that has been disclosed statement of income at the quarter end:
Three months ended 30 Sept Nine months ended
30 Sept
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
----------------------------------- --------- --------- --------- ---------
Revaluation of interest contracts 102 614 144 349
Realised (loss)/gain on interest
contracts (78) 19 (235) (186)
----------------------------------- --------- --------- --------- ---------
Total gain/(loss) on interest
contracts 24 633 (91) 163
Calculation of interest payments for the RBL Facilities agreement incorporates LIBOR. The Corporation is therefore exposed to interest rate risk to the extent that LIBOR may fluctuate. The Corporation evaluates its annual forward cash flow requirements on a rolling monthly basis.
The below represents interest rate financial instruments in place:
Derivative Term Value Rate -------------------- ----------------- ------------ ------ Interest rate swap Oct 16 - Dec 16 $50 million 1.24%
iii) Foreign Exchange Rate Risk
The table below presents the total (loss)/ gain on foreign exchange financial instruments that has been disclosed through the statement of income at the quarter end:
Three months ended 30 Sept Nine months ended
30 Sept
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
--------------------------------------- --------- --------- ---------
Revaluation of foreign exchange forward
contracts 2,955 (3,254) (2,322) 1,785
Realised (loss)/gain on foreign exchange
forward contracts (4,076) 614 (5,027) 1,221
-------------------------------------------- -------- --------- --------- ---------
Total (loss)/gain on forex forward
contracts (1,121) (2,640) (7,349) 3,006
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. The Corporation evaluates its foreign exchange instrument requirements on a rolling monthly basis.
The below represents foreign exchange financial instruments in place at the quarter end:
Derivative Term Value Forward rate ----------- ---------------- --------------------- -------------- Forward Oct 16 - Dec 16 GBP1.6 million/month $1.47/GBP1.00 Forward Oct 16 - Dec 16 GBP1.6 million/month $1.48/GBP1.00 Forward Oct 16 GBP12 million $1.33/GBP1.00
In October 2016, the Company entered into a further forward contract to purchase GBP5 million at a GBP:USD exchange rate of 1.24.
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. Oil production from Cook, Broom, Dons, Pierce, Causeway and Fionn is sold to Shell Trading International Ltd. Wytch Farm oil production is sold on the spot market. Topaz gas production was sold to Hartree Partners Oil and Gas. 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 2016 substantially all accounts receivables are current, being defined as less than 90 days. The Corporation has no allowance for doubtful accounts as at 30 September 2016 (31 December 2015: $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 2016, exposure is $32.5 million (31 December 2015: $126.9 million).
The Corporation also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values.
v) Liquidity Risk
Liquidity risk includes the risk that as a result of its operational liquidity requirements the Corporation will not have sufficient funds to settle a transaction on the due date. The Corporation manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Corporation considers the maturity profiles of its financial assets and liabilities. As at 30 September 2016, substantially all accounts payable are current.
The following table shows the timing of cash outflows relating to trade and other payables.
Within 1 year 1 to 5 years
US$'000 US$'000
------------------------------------------ ---------------------- ----------------------
Accounts payable and accrued liabilities (298,578) -
Other long term liabilities - (107,473)
Borrowings - (620,427)
------------------------------------------ ---------------------- ----------------------
(298,578) (727,900)
27. DERIVATIVE FINANCIAL INSTRUMENTS
30 Sept 31 Dec
2016 2015
US$'000 US$'000
----------------------------------- --------------------- ---------
Oil swaps 18,887 61,602
Oil capped swaps - 7,117
Gas swaps 192 1,690
Gas puts 13,469 56,352
Interest rate swaps (51) (197)
Foreign exchange forward contract (2,123) 126
----------------------------------- --------------------- ---------
30,374 126,690
28. FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES
Financial instruments of the Corporation consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in these financial statements. At 30 September 2016, the classification of financial instruments and the carrying amounts reported on the balance sheet and their estimated fair values are as follows:
30 September 2016 31 December 2015
US$'000 US$'000
----------------------------------- ----------------------- -----------------------
Carrying Carrying
Classification Amount Fair Value Amount Fair Value
----------------------------------- ---------- ----------- ---------- -----------
Cash and cash equivalents (Held
for trading) 29,772 29,772 11,543 11,543
Derivative financial instruments
(Held for trading) 32,549 32,549 126,887 126,887
Accounts receivable (Loans and
Receivables) 224,229 224,229 223,006 223,006
Deposits 1,747 1,747 743 743
Long-term receivable (Loans
and Receivables) 60,136 60,136 61,052 61,052
Bank debt (Loans and Receivables) (620,427) (620,427) (666,130) (666,130)
Contingent consideration (4,000) (4,000) (4,000) (4,000)
Derivative financial instruments
(Held for trading) (2,175) (2,175) (197) (197)
Other long term liabilities (107,473) (107,473) (92,543) (92,543)
Accounts payable (Other financial
liabilities) (298,578) (298,578) (275,907) (275,907)
29. 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 incorporation % equity interest
at 30 Sept
2016 2015
---------------------------- -------------------------- --------- ---------
Ithaca Energy (UK) Limited Scotland 100% 100%
Ithaca Minerals (North
Sea) Limited Scotland 100% 100%
Ithaca Energy (Holdings)
Limited Bermuda 100% 100%
Ithaca Energy Holdings
(UK) Limited Scotland 100% 100%
Ithaca Petroleum Limited England and Wales 100% 100%
Ithaca North Sea Limited England and Wales 100% 100%
Ithaca Exploration Limited England and Wales 100% 100%
Ithaca Causeway Limited England and Wales 100% 100%
Ithaca Gamma Limited England and Wales 100% 100%
Ithaca Alpha (NI) Limited Northern Ireland 100% 100%
Ithaca Epsilon Limited England and Wales 100% 100%
Ithaca Delta Limited England and Wales 100% 100%
Ithaca Petroleum Holdings
AS Norway 100% 100%
Ithaca Petroleum Norge
AS* Norway 0% 0%
Ithaca Technology AS Norway 100% 100%
Ithaca AS Norway 100% 100%
Ithaca Petroleum EHF Iceland 100% 100%
Ithaca SPL Limited England and Wales 100% 100%
Ithaca Dorset Limited England and Wales 100% 100%
Ithaca SP UK Limited England and Wales 100% 100%
Ithaca Pipeline Limited England and Wales 100% 100%
Transactions between subsidiaries are eliminated on consolidation.
*Ithaca Petroleum Norge AS was disposed of in Q2 2015.
The following table provides the total amount of transactions that have been entered into with related parties during the quarter ending 30 September 2016 and 30 September 2015, as well as balances with related parties as of 30 September 2016 and 31 December 2015:
Sales Purchases Accounts receivable Accounts
payable
US$'000 US$'000 US$'000 US$'000
----------------- ------ --------- ---------- -------------------- ---------
Burstall Winger
LLP 2016 - - - (37)
2015 - 111 - (127)
Loans to related Amounts owed from related parties
parties
30 Sept 31 Dec
2016 2015
US$'000 US$'000
---------------------- ------------------------- ---------
FPF-1 Limited 60,088 60,842
FPU Services Limited 48 210
------------------------- ------------------------- ---------
60,136 61,052
30. SEASONALITY
The effect of seasonality on the Corporation's financial results for any individual quarter is not material.
This information is provided by RNS
The company news service from the London Stock Exchange
END
QRTAKDDQOBDDNDD
(END) Dow Jones Newswires
November 14, 2016 02:00 ET (07:00 GMT)
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