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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 | 00:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
From Nov 2019 to Nov 2024
TIDMIAE
RNS Number : 0572F
Ithaca Energy Inc
15 May 2017
Not for Distribution to U.S. Newswire Services or for Dissemination in the United States
Ithaca Energy Inc.
First Quarter 2017 Financial Results
15 May 2017
Ithaca Energy Inc. (TSX: IAE, LSE AIM: IAE) ("Ithaca" or the "Company") announces its financial results for the three months ended 31 March 2017 ("Q1-2017" or the "Quarter").
Q1-2017 financial highlights
Hot Features
Premium
-- Average production of 9,337 barrels of oil equivalent per day ("boepd")
-- Unit operating expenditure reduced to $21/boe, down from $23/boe average rate in 2016
-- Cashflow from operations of $30 million, resulting in a netback of $36/boe
-- Earnings of $11 million
-- Downside commodity price hedging in place to mid-2018 - 6,800 boepd at an average floor of $49/boe from 1 April 2017
FPF-1 commissioning and operations update
-- Stella field started up mid-February 2017 - producing at constrained rates to minimise gas flaring until gas processing systems fully available
-- Commissioning of gas export compressors well advanced - one export train fully commissioned and the second materially completed
-- Initial gas exports to the CATS pipeline system delivered with the first export compressor in April 2017 - gas exports currently temporarily suspended until later this month while mechanical repairs are completed on the FPF-1 sea water lift pumps that are required for gas system cooling
-- Once both gas export compressors are fully operational, Stella remains forecast to add approximately 16,000 boepd net initial annualised production to the production portfolio
-- Average full year 2017 production is forecast to be in the range of 18,000 to 19,000 boepd, reflecting the expected schedule for the step-up in Stella production rates
Greater Stella Area development activities progressing to plan
-- Harrier field development programme commenced - development well drilling in progress with start-up of production expected in the second half of 2018
-- Good progress continues to be made on the FPF-1 modifications required to enable the switch from oil tanker loading to pipeline export in the second half of 2017
-- Vorlich development planning on-going - identification of the optimal development solution and preparation for submission of a field development plan
-- Additional 25% interest in the Ithaca-operated Austen discovery acquired from Premier Oil
Delek cash takeover offer
-- The offer of C$1.95 per share was accepted by holders of 318,833,909 common shares, resulting in Delek owning 94.2% of the issued and outstanding shares of the Company, including the shares it owned prior to announcement of the transaction
-- Delek has announced it intends to carry out a compulsory acquisition of the remaining shares for the same cash consideration as the offer
Greater Stella Area Development
Stella
Following first hydrocarbons from the Stella field in mid-February 2017, operational activities on the FPF-1 have been centred on completion of the dynamic commissioning programme required on the gas processing systems on the vessel. During this programme, oil production continues to be maintained at constrained rates in order to minimise gas flaring. The oil processing facilities on the FPF-1 have been performing well and an initial cargo of approximately 235,000 barrels of oil was exported via shuttle tanker from the field in April 2017. Oil production to date from the field has been limited to approximately 1,900 boepd net to Ithaca.
Dynamic commissioning activities on the gas processing facilities are now well advanced. The first of the two gas export compressors has been fully commissioned, with initial gas exports into the CATS pipeline system achieved in late April 2017, and commissioning of the second export compressor has also been materially completed. Gas exports have temporarily been suspended until replacement of the drive motors on the FPF-1 sea water lift pumps that provide cooling for the gas processing systems has been completed. As a consequence, it is forecast that gas exports from the first compressor will recommence later this month, stepping up to full production rates in early June 2017 once commissioning of the second export compressor is completed.
Once both gas export compressors are fully operational, Stella remains forecast to add approximately 16,000 boepd net initial annualised production to the Company's asset portfolio.
GSA Oil Export Pipeline
Good progress continues to be made on the FPF-1 modifications required to enable the switch from oil tanker loading to pipeline exports via the Norpipe system during 2017. All the main items of equipment required to be installed on the FPF-1 have now been transferred on to the vessel and work is progressing to plan on installation of the pipeline export pumps. Upon completion of the necessary tie-ins to the existing facilities on the vessel, the final subsea connections that need to be undertaken immediately prior to the switchover from shuttle tanker to pipeline export will be completed by Technip.
Harrier Development
Development drilling on the Harrier field commenced as planned in April 2017. The ENSCO 122 heavy duty jack-up rig is being used to drill a multilateral well into the two reservoir formations on the field, with the well scheduled for completion in the second half of 2017.
The Harrier well is to be tied back via a 7.5 kilometre pipeline to an existing slot on the Stella main drill centre manifold for onward export and processing of production on the FPF-1. The subsea infrastructure installation activities are scheduled for summer 2018, resulting in the anticipated start-up of Harrier production in the second half of 2018.
Austen Discovery
The Company entered into a sales and purchase agreement with Premier Oil E&P UK Limited in May 2017 to acquire its 25% interest in licence P1823 (Block 30/13b) for a nominal consideration. The licence contains the Ithaca-operated Austen discovery. The transaction, which is effective as of 1 January 2017 and expected to complete in the second half of 2017, will result in the Company being the sole owner of the licence. The Austen discovery is located approximately 30 kilometres south-east of the Greater Stella Area hub.
Production & Operations
Production in the first quarter of 2017 averaged 9,337 boepd (Q1 2016: 8,997 boepd). This represented a 4% increase on production in Q1 2016 predominantly due to higher volumes from the Pierce field, along with a modest contribution from the Stella field, offsetting natural decline on the Dons area fields.
Average production in 2017 is forecast to be in the range of 18,000 to 19,000 boepd (80% oil), reflecting the schedule for the step-up in Stella production rates and the other previously noted planned maintenance shutdowns scheduled for the asset portfolio during the year.
Financials
Hedging
The Company's commodity hedging position remains unchanged since the start of 2017. As of 1 April 2017 the Company has 6,800 boepd (90% oil) hedged at an average floor price of $49/boe for the 15 months to 30 June 2018. Full commodity price upside exposure has been retained on 65% of the volumes hedged and upside exposure to $60/boe has been retained on a further 25% of the hedged volumes.
Operating Expenditure
Net unit operating costs in Q1-2017 were $21/boe, down from an average of $23/boe in 2016. This reduction was achieved through continued downward pressure on operating costs across the portfolio and the benefit of a modest contribution during the quarter from lower cost Stella field production.
Forecast 2017 net unit operating expenditure is anticipated to be approximately $18/boe, reflecting the anticipated positive impact on unit costs of Stella field production.
Capital Expenditure
The planned capital expenditure programme for 2017 is forecast to total approximately $70 million. Of this, approximately $8 million was incurred in Q1-2017. The majority of the 2017 expenditure relates to the GSA, primarily being Harrier development activities plus completion of the GSA oil export pipeline investment programme and Vorlich field development planning activities.
Tax
The Company had a UK tax allowances pool of over $1,700 million at 31 March 2017. At current commodity prices, the pool is forecast to shelter the Company from the payment of corporation tax over the medium term.
Net Debt & Credit Facilities
Net debt at 31 March 2017 was $614 million, up slightly on the year-end total of $598 million due to working capital movements and the timing of initial sales receipts from Stella field production.
Net debt is forecast to reduce significantly over the course of 2017 as the operating cashflows of the business step up materially as a consequence of Stella production.
Ithaca's existing bank debt facilities and senior notes have maturities in late 2018 and mid-2019, respectively. During 2017 the Company will assess the options to refinance these credit facilities and the associated debt maturity profiles.
Delek Takeover Offer
On 6 February 2017 the Company announced that it had entered into a definitive support agreement with Delek Group Ltd ("Delek") on the terms of a cash takeover bid for all of the issued and to be issued common shares of Ithaca not currently owned by Delek for C$1.95 per share (the "Offer"). The Offer was made by DKL Investments Limited (the "Offeror"), an affiliate of Delek and Ithaca's largest shareholder at the time the Offer was announced.
On 20 April 2017 the conditions of the Offer were satisfied, with the Offer being accepted by holders of 241,293,465 of the issued and outstanding common shares of the Company. As required by securities laws, the Offer was subsequently extended until 3 May 2017, following which a further 77,540,444 common shares were tendered. Consequently, upon completion of the Offer, the Offeror became the owner of 400,699,334 common shares, including the shares already owned by the Offeror prior to announcement of the takeover, representing 94.2% of the issued and outstanding shares of the Company
Following completion of the Offer, Delek has subsequently notified the Company of its intention to carry out a compulsory acquisition by the Offeror of all the remaining issued and outstanding common shares of Ithaca not currently owned by the Offeror for the same cash consideration as the Offer under and subject to the Business Corporations Act (Alberta). As a consequence, the Company will be seeking to cancel its admission to trading on the AIM market of the London Stock Exchange and to voluntarily delist from the TSX following completion of the compulsory acquisition. Further details on this will be announced in due course.
Following completion of the compulsory acquisition and proposed delisting, the Company will continue to report its annual and quarterly financial statements as required by the terms of the indenture for the $300 million senior notes due July 2019.
Q1-2017 Financial Results Conference Call
A conference call and webcast for investors and analysts will be held today at 12.00 BST (07.00 EDT), with a playback facility being made available on the Company's website later that day. 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 (0)203 059 8125; Canada +1 855 287 9927; US +1 724 928 9460. A short presentation to accompany the results will be available on the Company's website prior to the call.
The unaudited consolidated financial statements of the Company for the three months ended 31 March 2017 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.
Glossary
boe Barrels of oil equivalent boepd Barrels of oil equivalent per day
-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
Cenkos Securities
Neil McDonald nmcdonald@cenkos.com +44 (0)207 397 8900
Beth McKiernan bmckiernan@cenkos.com +44 (0)131 220 9778
Nick Tulloch ntulloch@cenkos.com +44 (0)131 220 6939
RBC Capital Markets
Matthew Coakes matthew.coakes@rbccm.com +44 (0)207 653 4000
Notes
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.
All references to dollars ($) in this press release refer to the United States dollar (USD), unless otherwise stated.
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.
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, 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" and similar expressions, and the negatives thereof, whether used in connection with the Offer, the compulsory acquisition by the Offeror under the Business Corporations Act (Alberta), the proposed cancellation of admission to trading on the AIM market of the London Stock Exchange, the proposed voluntary delisting from the TSX, operational activities, drilling plans, future GSA field development programmes, Stella production ramp-up timing, production forecasts, budgetary figures, future operating costs, anticipated net debt, anticipated funding requirements, planned maintenance shutdowns, potential developments including the timing and anticipated benefits of acquisitions and dispositions 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 and Annual Information Form for the year ended 31 December 2016 and in reports which are on file with the Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).
HIGHLIGHTS FIRST QUARTER 2017
=============================================================
Solid cashflow
generation * Average production of 9,337 boepd (Q1 2016: 8,997
during the boepd)
quarter
* Unit operating expenditure reduced to $21/boe, down
from $23/boe average rate in 2016
* Cashflow from operations of $30 million, resulting in
a netback of $36/boe
* Earnings of $11 million (Q1 2016: $18 million loss)
* Downside commodity price hedging in place to mid-2018
- 6,800 boepd at an average floor of $49/boe from 1
April 2017
* Net debt of $614 million at 31 March 2017, up
slightly on the year-end position of $598 million
primarily as a result of working capital movements
-------------------------------------------------------------
First production
from Stella * Stella field started up mid-February 2017 - producing
field achieved at constrained rates to minimise gas flaring until
mid-February gas processing systems fully available
2017
* Commissioning of gas export compressors well advanced
- one export train fully commissioned and the second
materially completed
* Initial gas exports to the CATS pipeline system
delivered with the first export compressor in April
2017 - gas exports currently temporarily suspended
until later this month while mechanical repairs are
completed on the FPF-1 sea water lift pumps that are
required for gas system cooling
* Once both gas export compressors are fully
operational, Stella remains forecast to add
approximately 16,000 boepd net initial annualised
production to the production portfolio
* Average full year 2017 production is forecast to be
in the range of 18,000 to 19,000 boepd, reflecting
the expected schedule for the step-up in Stella
production rates
-------------------------------------------------------------
GSA development
activities * Harrier field development programme commenced -
progressing development well drilling in progress with start-up
to plan of production expected in the second half of 2018
* Good progress continues to be made on the FPF-1
modifications required to enable the switch from oil
tanker loading to pipeline export in the second half
of 2017
* Vorlich development planning on-going -
identification of the optimal development solution
and preparation for submission of a field development
plan
* Additional 25% interest in the Ithaca-operated Austen
discovery acquired from Premier Oil
-------------------------------------------------------------
Delek share
tender offer * Takeover offer by DLK Investments Limited, a wholly
completed owned subsidiary of Delek Group Limited ("Delek"),
- compulsory announced on 6 February 2017 for a cash consideration
acquisition of C$1.95 per share
announced
* The offer was accepted by holders of 318,833,909
common shares resulting in Delek owning 94.2% of the
issued and outstanding shares of the Company,
including the shares it owned prior to announcement
of the transaction
* Delek has announced it intends to carry out a
compulsory acquisition of the remaining shares for
the same cash consideration as the offer
SUMMARY STATEMENT OF INCOME
=========================================================================================
Q1 2017 Q1 2016
Average Production kboe/d 9.3 9.0
Average Realised Oil Price(1) $/bbl 51 36
Revenue(2) M$ 40.0 27.0
Commodity Hedging Cash Gain M$ 7.9 38.7
Revenue(2) (Incl. Cash Hedging Gain) M$ 47.9 65.7
Opex(3) M$ (17.3) (20.2)
G&A M$ (1.6) (1.7)
Foreign Exchange/other M$ 1.6 0.5
Cashflow from Operations M$ 30.6 44.4
DD&A (3) M$ (14.8) (17.6)
Non-Cash Hedging (Loss) M$ (2.2) (33.6)
Finance Costs M$ (8.6) (9.2)
Other Non-Cash Costs M$ (0.8) (0.5)
Taxation M$ 6.5 34.2
Earnings M$ 10.7 17.7
Cashflow Per Share $/Sh. 0.07 0.11
Earnings Per Share $/Sh. 0.03 0.04
(1) Average realised price before hedging
(2) Revenue net of stock movements
(3) Figures shown net of Stella related
returns and costs from investment in associate
SUMMARY BALANCE SHEET
=========================================================================================
M$ 31 Mar. 31 Dec.
2017 2016
Cash & Equivalents 6 27
Other Current
Assets 170 198
PP&E 1,110 1,112
Deferred Tax
Asset 390 384
Other Non-Current
Assets 210 210
Total Assets 1,886 1,931
Current Liabilities (191) (245)
Borrowings (615) (619)
Asset Retirement
Obligations (208) (207)
Other Non-Current
Liabilities (116) (116)
Total Liabilities (1,130) (1,187)
Net Assets 756 744
Share Capital 621 619
Other Reserves 25 25
Surplus 110 100
Shareholders'
Equity 756 744
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
* 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
---------------------------------------------------
DELEK TAKEOVER OFFER
Delek share On 6 February 2017 the Company announced
tender offer that it had entered into a definitive
completed support agreement with Delek Group Ltd
- compulsory ("Delek") on the terms of a cash takeover
acquisition bid for all of the issued and to be issued
announced common shares of Ithaca not currently
owned by Delek for C$1.95 per share (the
"Offer"). The Offer was made by DKL Investments
Limited (the "Offeror"), an affiliate
of Delek and Ithaca's largest shareholder
at the time the Offer was announced.
On 20 April 2017 the conditions of the
Offer were satisfied, with the Offer being
accepted by holders of 241,293,465 of
the issued and outstanding common shares
of the Company. As required by securities
laws, the Offer was subsequently extended
until 3 May 2017, following which holders
of a further 77,540,444 common shares
were tendered. Consequently, upon completion
of the Offer, the Offeror became the owner
of 400,699,334 common shares, including
the shares already owned by the Offeror
prior to announcement of the takeover,
representing 94.2% of the issued and outstanding
shares of the Company.
Following completion of the Offer, Delek
has subsequently notified the Company
of its intention to carry out a compulsory
acquisition by the Offeror of all the
remaining issued and outstanding common
shares of Ithaca not currently owned by
the Offeror for the same cash consideration
as the Offer under and subject to the
Business Corporations Act (Alberta). As
a consequence, the Company will be seeking
to cancel its admission to trading on
the AIM market of the London Stock Exchange
and to voluntarily delist from the TSX
following completion of the compulsory
acquisition.
DEBT FACILITIES
Refinanced As at 31 March 2017, the Company's available
RBL with extended RBL borrowing capacity is over $410 million.
tenor to be When combined with its existing $300 million
established senior unsecured notes, the business has
in Summer a total debt capacity of over $710 million.
2017 Consequently, the Company maintains approximately
$100 million of funding headroom when
compared to net debt at the end of Q1
2017 of $614 million.
Ithaca's existing bank debt facilities
and senior notes have maturities in late
2018 and mid-2019. During 2017 the Company
will assess the options to refinance these
credit facilities and the associated debt
maturity profiles in order to ensure that
they are appropriately aligned with the
funding requirements of the business.
Austen Licence
Additional In May 2017 the Company entered into a
interest acquired sales and purchase agreement with Premier
in the Ithaca-operated Oil E&P UK Limited to acquire its 25%
Austen discovery interest in licence P1823 (Block 30/13b)
for a nominal consideration. The licence
contains the Ithaca-operated Austen discovery.
The transaction, which is effective as
of 1 January 2017 and expected to complete
in the second half of 2017, will result
in the Company being the sole owner of
the licence.
The Austen discovery is located approximately
30 kilometres south-east of the GSA hub.
It 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-10Z that was drilled
in 2012 by the previous licence operator
ENGIE E&P UK Limited. Further subsurface
and development engineering studies are
on-going in order to advance the preparation
of a Field Development Plan for approval
prior to January 2019.
Based on the results of the end-2016 independent
reserves evaluation completed by Sproule
International Limited in accordance with
Canadian Oil and Gas Evaluation Handbook
pursuant to NI 51-101 - Standards of Reserves
Disclosure for Oil and Gas Activities,
the acquisition adds approximately 2.5
million barrels of oil equivalent to the
Company's proven and probable reserves
base.
GREATER STELLA AREA DEVELOPMENT
---------------------------------------------------
GSA "hub and Ithaca's focus on the Greater Stella Area
spoke" strategy ("GSA") is driven by monetisation of the
Company's existing portfolio of undeveloped
discoveries located in the area.
The GSA development involves the creation
of a production hub based on deployment
of the Ithaca operated FPF-1 floating
production facility, which is located
over the Stella field, with onward export
of oil and gas to market. To maximise
initial oil and condensate production
and fill the gas processing facilities
on the FPF-1, initial production from
the hub will come from the Stella field.
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
Stella first Following first hydrocarbons from the
hydrocarbons Stella field in mid-February 2017, operational
delivered activities on the FPF-1 have been centred
in February on completion of the dynamic commissioning
2017 - dynamic programme required on the gas processing
commissioning systems on the vessel. During this programme,
of the gas oil production continues to be maintained
processing at constrained rates in order to minimise
facilities gas flaring. The oil processing facilities
on-going on the FPF-1 have been performing well
and an initial cargo of approximately
235,000 barrels of oil was exported via
shuttle tanker from the field in April
2017. Oil production to date from the
field has averaged approximately 1,900
boepd net to Ithaca.
Dynamic commissioning activities on the
gas processing facilities are now well
advanced. The first of the two gas export
compressors has been fully commissioned,
with initial gas exports into the CATS
pipeline system achieved in late April
2017, and commissioning of the second
export compressor has also been materially
completed. Gas exports have temporarily
been suspended until replacement of the
drive motors on the FPF-1 sea water lift
pumps that provide cooling for the gas
processing systems has been completed.
As a consequence, it is forecast that
gas exports from the first compressor
will recommence later this month, stepping
up to full production rates in early June
2017 once commissioning of the second
export compressor is completed.
Once both gas export compressors are fully
operational, Stella remains forecast to
add approximately 16,000 boepd net initial
annualised production to the Company's
asset portfolio.
GSA OIL EXPORT PIPELINE
Switch from Good progress continues to be made on
oil tanker the required FPF-1 modifications to enable
to pipeline the switch from oil tanker loading to
export scheduled pipeline exports via the Norpipe system
for 2017 - during 2017. All the main items of equipment
reducing fixed required to be installed on the FPF-1
operating have now been transferred on to the vessel
costs and and work is progressing to plan on installation
increasing of the pipeline export pumps. Upon completion
the long term of the necessary tie-ins to the existing
value of the facilities on the FPF-1, the final subsea
GSA connections that need to be undertaken
immediately prior to the switchover from
shuttle tanker to pipeline export will
be completed by Technip. This will involve
a planned shutdown of production on the
FPF-1 in the second half of 2017.
The opportunity to switch from tanker
loading to pipeline export was secured
in 2016, when access to the Norpipe system
was secured through execution of a fast-track
offshore work programme to make a connection
to the system. This move will significantly
reduce the fixed operating costs of the
GSA facilities and enhance operational
uptime and enable improved reserves recovery
from the fields served by the FPF-1 production
hub.
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.
HARRIER DEVELOPMENT
Harrier field In line with the Company's strategy for
development building out the GSA production hub, investment
drilling commenced in the Harrier development programme commenced
in Q2 2017, in April 2017 when the ENSCO 122 heavy
beginning duty jack-up rig arrived on location for
the build drilling of the planned multilateral well
out of the into the two Harrier reservoir formations.
GSA production The drilling programme is scheduled to
hub be completed in the second half of 2017,
with the associated subsea infrastructure
installation activities planned for summer
2018. The Harrier well is to be tied back
via a 7.5 kilometre pipe to an existing
slot on the Stella main drill centre manifold
for onward export and processing of production
on the FPF-1. The start-up of production
from the field is anticipated in the second
half of 2018.
VORLICH DEVELOPMENT
Vorlich development Following the various transactions completed
planning activities in 2016 to acquire an approximately 33%
on-going working interest in the BP-operated Vorlich
discovery, work is progressing on the
various studies and commercial negotiations
required to identify the optimal development
solution for the discovery. Completion
of this work will enable a field development
plan to be prepared and submitted to the
UK Oil and Gas Authority for formal approval.
PRODUCTION & OPERATIONS
----------------------------------------------
2017 PRODUCTION
Production in the first quarter of 2017
averaged 9,337 boepd (Q1 2016: 8,997 boepd).
This represented a 4% increase on production
in Q1 2016 predominantly due to higher
volumes from the Pierce field, along with
a modest contribution from the Stella
field, offsetting natural decline on the
Dons area fields.
Average production in 2017 is forecast
to be in the range of 18,000 to 19,000
boepd (80% oil), reflecting the schedule
for the step-up in Stella production rates
and the other previously noted planned
maintenance shutdowns scheduled for the
asset portfolio during the year.
COMMODITY HEDGING
------------------------------------------------
Additional As part of the financial and risk management
hedging put strategy of the business, the Company
in place - actively seeks to maintain a balanced
commodity commodity hedging position. Any hedging
price protection is executed at the discretion of the Company,
established with no minimum requirements stipulated
for 6,800 in the Company's debt finance facilities.
boepd to June In Q1 2017, the Company benefitted from
2018 realised commodity hedging gains in the
period of $7.9 million, equating to an
additional $10 of revenue per sales barrel
of oil equivalent in the quarter.
As of 1 April 2017 the Company has 6,800
boepd (90% oil) hedged at an average floor
price of $49/boe for the 15 months to
30 June 2018. Full commodity price upside
exposure has been retained on 65% of the
volumes hedged and upside exposure to
$60/boe has been retained on a further
25% of the hedged volumes. Based on valuations
relative to the respective oil and gas
forward curves as of 1 April 2017, these
hedges were valued at $5.0 million.
OPERATING EXPITURE
----------------------------------------------
Net unit operating Net unit operating costs for Q1 2017 were
costs for $21/boe. This represents a further reduction
Q1 2017 of on the average rate of $23/boe delivered
$21/boe - in 2016, resulting from continued downward
forecast to pressure on operating costs across the
fall to $18/boe portfolio and the benefit of a modest
for the full contribution during the quarter from lower
year cost Stella field production.
Forecast 2017 net unit operating expenditure
is anticipated to be approximately $18/boe,
reflecting the benefit of the start-up
of production from the Stella field.
CAPITAL EXPITURE
-----------------------------------------------
2017 capex Capital expenditure in 2017 is forecast
estimated to total approximately $70 million, of
to be approximately which approximately $8 million was incurred
$70M in Q1 2017. The majority of this expenditure
relates to the GSA, primarily being Harrier
development activities plus completion
of the GSA oil export pipeline investment
programme and Vorlich field development
planning activities. The forecast expenditure
is also inclusive of any additional Stella
start-up costs.
NET DEBT
---------------------------------------------------------------
DEBT SUMMARY (M$) 31 Mar. 31 Dec.
2017 2016
Net debt forecast RBL Facility 320.0 324.9
to reduce Senior Notes 300.0 300.0
further in Total Debt 620.0 624.9
2017 through UK Cash and Cash Equivalents (5.9) (27.2)
increased Net Drawn Debt 614.1 597.7
cashflow generation
from Stella Note this table shows debt repayable as
field opposed to the reported balance sheet
debt which nets off capitalised RBL and
senior note costs
Net debt was reduced by $67 million in
2016 to $598 million at 31 December 2016,
increasing slightly to $614 million at
31 March 2017 due to working capital movements
and the timing of initial sales receipts
from Stella field production.
Net debt is forecast to reduce significantly
over the course of 2017 as the operating
cashflows of the business step up materially
as a consequence of Stella production.
TRADING ENVIRONMENT
---------------------------------------------------
COMMODITY PRICES
---------------------------------------------------
Q1 Q1
2017 2016
Average Brent
Price $/bbl 52 34
Although the increase in Brent has had
a positive impact on revenues in Q1 2017
relative to Q1 2016, it is worth noting
that the oil price impact on the Company's
results in Q1 2016 were materially mitigated
by the significant hedging protection
that was in place.
FOREIGN EXCHANGE RATES
---------------------------------------------------
Q1 Q1
2017 2016
GBP : USD
average 1.24 1.43
GBP : USD
period end
spot 1.25 1.44
Volatility in exchanges rates resulting
from the UK's decision during 2016 to
exit the European Union has had a positive
impact on the financial results as a consequence
of the ensuing devaluation of the pound
sterling versus the US dollar.
Ahead of the introduction of gas sales
from the Stella field the majority of
the Company's revenue is derived from
US dollar denominated oil sales, while
approximately 80% of costs are incurred
in pounds sterling. Going forward, gas
sales in pounds sterling will significantly
reduce GBP:USD exchange rate exposure.
Q1 2017 RESULTS OF OPERATIONS
--------------------------------------------------
REVENUE
--------------------------------------------------
Average Realised Q1 2017 Q1 2016
Price
Oil Pre-Hedging $/bbl 51 36
Oil Post-Hedging $/bbl 59 60
Revenue increased to $37.2 million in
Q1 2017 (Q1 2016: $33.2 million) as a
consequence of a $15/bbl or 42% increase
in the realised oil price prior to taking
into account hedging, partly offset by
a 21% reduction in sales volumes.
Although production volumes increased
in Q1 2017 compared to Q1 2016, sales
volumes were significantly less due to
lifting schedules. In particular on Cook
there were no oil liftings made during
the quarter, with oil production instead
being held in inventory at 31 March 2017
(see Cost of Sales section below).
The realised oil price for the quarter
increased from $36/bbl in Q1 2016 to $51/bbl
in Q1 2017, in line with the increase
in Brent for the comparative periods.
This price was further improved by realised
oil and gas hedging gains of $10 per sales
barrel of oil equivalent in the quarter,
resulting in a $7.9 million gain being
reported through Foreign Exchange and
Financial Instruments (see below).
While the 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.
COST OF SALES
-------------------------------------------------
$'000 Q1 2017 Q1 2016
Operating Expenditure 18,118 20,185
DD&A 14,472 17,608
Movement in Oil
& Gas Inventory (2,795) 6,325
Other 115 -
Total 29,910 44,118
Cost of sales decreased in Q1 2017 by
approximately 32% to $29.9 million (Q1
2016: $44.1 million). This was attributable
to decreases in operating costs, depletion,
depreciation and amortisation ("DD&A")
and an increase in the value of oil and
gas inventory.
OPERATING EXPITURE
Reported operating costs decreased by
10% in the quarter to $18.1 million (Q1
2016: $20.2 million). These operating
costs include tariff payments made to
a 49% owned associated company of Ithaca,
FPF-1 Limited. The net unit operating
cost of the business is calculated by
netting off the payments which are received
by Ithaca through its 49% ownership in
the associated company. This net unit
operating cost averaged $21 per boe in
Q1 2017 ($25/boe in Q1 2016), and is forecast
to further reduce during 2017 as Stella
production ramps up.
DD&A
The unit DD&A rate for the quarter decreased
to $17/boe (Q1 2016: $21/boe), resulting
in a total DD&A expense for the period
of $14.5 million (Q1 2016: $17.6 million).
This reduction in expense was due primarily
to a lower average DD&A/boe rate as a
result of increased proven and probable
("2P") reserves associated with a number
of key fields in the portfolio, partially
offset by increased production.
MOVEMENT IN INVENTORY
An oil and gas inventory movement of $2.8
million was credited to cost of sales
in Q1 2016 (Q1 2015: charge of $6.3 million).
This credit arose primarily as a result
of increased stock volumes due to lifting
schedules in the quarter, partially offset
by a reduction in value due to the fall
in Brent from the year end.
Movement in Oil Gas Total
Operating kbbls kboe kboe
Oil & Gas Inventory
Opening inventory 384 (3) 381
Production 774 66 840
Liftings/sales (699) (66) (765)
Closing volumes 459 (3) 456
ADMINISTRATION EXPENSES AND EXPLORATION
& EVALUATION EXPENSES
-----------------------------------------------
$'000 Q1 Q1 2016
Administration 2017
expense levels General & Administration
maintained ("G&A") 1,580 1,658
through on-going Share Based Payments
monitoring ("SBP") 65 111
Total Administration
Expenses 1,645 1,769
Exploration &
Evaluation ("E&E")
write off 745 421
ADMINISTRATION EXPENSES
Total administrative expenses were reduced
to $1.6 million in Q1 2017 (Q1 2016: $1.8
million). Underlying G&A costs are tightly
managed, with the business continuing
to benefit from the savings that can be
secured in the current commodity price
environment.
E&E EXPENSES
A minor write off of E&E assets was made
at the period end relating to non-commercial
prospects.
FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS
----------------------------------------------------
$'000 Q1 Q1
2017 2016
Gain on Foreign Exchange 1,708 502
---------------------------- -------- ---------
Total Gain on Foreign
Exchange 1,708 502
---------------------------- -------- ---------
Revaluation of Commodity
Hedges (2,175) (32,335)
Revaluation of Other
Instruments (17) (1,230)
Total Revaluation (Loss) (2,192) (33,565)
---------------------------- -------- ---------
Realised Gain on Commodity
Hedges 7,898 39,163
Realised (Loss) on
Other Instruments - (419)
Total Realised Gain 7,898 38,744
---------------------------- -------- ---------
Total Foreign Exchange
& Financial Instruments 7,414 5,681
---------------------------- -------- ---------
FOREIGN EXCHANGE
While the majority of the Company's revenue
is US dollar denominated, expenditures
are predominantly incurred in pounds sterling
(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 Q1 2017, a foreign exchange gain of
$1.7 million was recorded (Q1 2016: $0.5
million gain). This was primarily driven
by the settlement of pounds sterling invoices
at a lower exchange rate than the GBP:USD
rate on the date they were received.
FINANCIAL INSTRUMENTS
The Company recorded an overall gain of
$5.7 million on financial instruments
for the quarter ended 31 March 2017 (Q1
2016: $5.2 million gain).
A $7.9 million realised gain was made
in Q1 2017. This comprised a $5.1 million
gain on oil hedges maturing during the
quarter (at an average exercise price
of $59/bbl compared to an average Brent
price of $54/bbl) and a $2.8 million gain
on gas hedges (at an average price of
64p/therm compared to an average NBP price
of 48p/therm. The total realised gain
of $7.9 million in the period was offset
by a $2.2 million negative revaluation
of instruments as at 31 March 2017.
The $2.2 million negative revaluation
of commodity hedges was due to the realisation
of hedged oil and gas volumes during the
quarter (i.e. the transfer of previously
unrealised gains to realised gain), partly
offset by an upward revaluation of the
remaining hedges at 31 March 2017 due
to a weakening of the oil forward curve.
As of 31 March 2017 the Company's commodity
hedges were valued at $5.0 million based
on valuations relative to the respective
oil and gas forward curves, comprising
$1.5 million for oil hedges and $3.5 million
for gas hedges.
FINANCE COSTS
---------------------------------------------
$'000 Q1 Q1
Reducing finance 2017 2016
cost profile Bank interest and
driven by charges 755 1,150
decreasing Senior notes interest 3,830 3,830
net debt Finance lease interest 240 254
Non-operated asset
finance fees 12 4
Prepayment interest 678 622
Loan fee amortisation 1,040 1,040
Accretion 2,069 2,273
Total Finance
Costs 8,624 9,173
Finance costs decreased to $8.6 million
in Q1 2017 (Q1 2016: $9.2 million). This
reduction is primarily attributable to
the decrease in RBL bank charges resulting
from the deleveraging of the business
over the last eighteen months. All other
finance costs have remained relatively
stable quarter on quarter.
TAXATION
---------------------------------------------------
$'000 Q1 2017 Q1
No UK tax 2016
anticipated UK corporation tax
to be payable - excluding rate
within the changes 6,516 10,078
next 5 years Impact of change
in tax rates - 24,155
Total Taxation 6,516 34,233
A tax credit of $6.5 million was recognised
in the quarter ended 31 March 2017 (Q1
2016: $34.2 million credit). The key driver
between the anticipated tax charge of
$1.7 million, being 40% of profit before
tax for the quarter, and the tax credit
that has been recognised is a $9.2 million
credit relating to the UK Ring Fence Expenditure
Supplement, partly offset by a small charge
in respect of adjustments to the additional
capital allowances recognised in relation
to Stella for expenditure incurred by
Ithaca but paid by Petrofac. In accordance
with the Stella Sale and Purchase Agreement
("SPA"), Ithaca receives the right to
claim a tax benefit for these capital
allowances and the tax benefit of these
allowances continue to be 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 legal completion of the
SPA, in accordance with its terms, of
a sum calculated at the prevailing tax
rate applied to the relevant capital allowances.
The relevant capital allowances are expected
to be around $250 million and implies,
assuming current tax rates, a payment
of approximately $100 million. A related
deferred tax asset is recorded at 31 March
2017 of $93.5million reflecting the expected
future benefit of these additional capital
allowances.
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 was enacted in March
2016 and therefore the deferred PRT provision
was fully released through the Q1 2016
results giving rise to a credit of $24.2
million.
It was also announced in the UK Budget
on 16 March 2016 that the Supplementary
Corporation Tax ("SCT") rate payable by
oil and gas producers would be reduced
from 20% to 10% with effect from 1 January
2016. This reduces the Company's future
SCT charge accordingly. The impact of
the 10% reduction in the SCT rate was
not enacted until September 2016, meaning
there is no impact on the Q1 2016 comparatives.
CAPITAL INVESTMENTS
===========================================
$'000 Additions
2017 capital Q1 2017
investment Development & Production
programme ("D&P") 11,623
primarily Exploration & Evaluation
focused on ("E&E") 1,821
GSA development Other Fixed Assets 18
activities Total 13,462
Excluding capitalised interest costs,
capital expenditure in the quarter was
approximately $8.1 million, which mainly
related to activities on the GSA.
WORKING CAPITAL
---------------------------------------------------------------------------
$'000 31 Mar. 31 Dec. Increase
2017 2016 / (Decrease)
Cash & Cash Equivalents 5,870 27,199 (21,329)
Trade & Other Receivables 136,247 158,579 (22,332)
Inventory 25,827 27,729 (1,902)
Other Current Assets 5,000 7,183 (2,183)
Trade & Other Payables (187,768) (236,928) 49,160
Net Working Capital* (14,824) (16,238) 1,414
*Working capital being total current assets
less trade and other payables
As at 31 March 2017 Ithaca had a net working
capital credit balance of $14.8 million,
including an unrestricted cash balance
of $5.9 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 period.
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 increased over
the three month period to 31 March 2017
as a result of a positive cashflow from
operations offset by repayment of borrowings
in the quarter.
CAPITAL RESOURCES
-------------------------------------------------------------
DEBT FACILITIES
Approximately As at 31 March 2017 the Company has bank
$100 million debt facilities totalling $535 million
funding headroom ($475 million senior RBL Facility and
at 31 March $60 million junior RBL), both with a maturity
2017 of September 2018. As at the same date,
the debt capacity of these facilities
was over $410 million. When combined with
the $300 million senior unsecured notes,
due July 2019, the Company has funding
headroom of approximately $100 million
as at the end of the quarter.
Both RBL facilities are based on conventional
oil and gas industry borrowing base financing
terms, neither of which have historic
financial covenant tests, and are due
to mature in late 2018. The Company's
$300 million senior unsecured notes similarly
have no historic financial covenant tests,
nor do they have any financial maintenance
covenant tests. The senior notes are 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.
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.
Cashflow from operations
Cash generated from operating activities
was $30.3 million. Revenues from the producing
portfolio of assets were bolstered by
the hedging programme in place combined
with reduced operating costs.
Cashflow from financing activities
Cash used in financing activities was
$12.0 million, being interest charges
coupled with repayments of the debt facilities
during the quarter.
Cashflow from investing activities
Cash used in investing activities was
$18.3 million, primarily associated with
further capital expenditure on the GSA
development (including capitalised interest).
COMMITMENTS
-------------------------------------------------
The Company's commitments relate primarily
to capital investment activities on the
GSA, along with other on-going operational
commitments across the portfolio. Rig
commitments relate to the on-going Harrier
development drilling campaign.
With the Stella field now in production,
the Company's overall commitments are
relatively modest and are forecast to
be funded from the operating cashflows
of the business.
$'000 1 Year 2-5 5+ Years
Years
Office Leases 216 - -
Licence Fees 488 - -
Engineering 19,663 - -
Rig Commitments 7,661 - -
Total 28,028 - -
In addition to the amounts shown in the
table, in 2015 Ithaca entered into an
agreement with Petrofac in respect of
the FPF-1 Floating Production facility
whereby 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 fully ramped up production is achieved
from the Stella field. A further payment
to Petrofac of up to $34 million was initially
to be made by Ithaca dependent on the
timing of sail-away of the FPF-1. This
further payment was revised to $17 million
in Q3 2016. This payment will also be
deferred until three and a half years
after fully ramped up production is achieved
from the Stella field.
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 Ithaca Classification Subsequent Measurement
Instrument
Category
Held-for-trading Cash, cash Fair Value with
equivalents, changes recognised
restricted in net income
cash, derivatives,
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 Accounts
Receivables receivable
----------------- ---------------------- ------------------------
Other financial Accounts
liabilities payable,
operating
bank loans,
accrued liabilities
----------------- ---------------------- ------------------------
The classification of all financial instruments
is the same at inception and at 31 March
2017.
COMMODITIES
The following table summarises the commodity
hedges in place at 31 March 2017.
Derivative Term Volume Average
bbl Price
$/bbl
April 2017 -
Oil Swaps June 2017 261,514 70
April 2017 -
Oil Puts June 2018 1,704,100 54
April 2017 -
Oil Collars June 2018 812,506 47 -60*
Derivative Term Volume Average
Therms Price
p/therm
April 2017 -
Gas Puts June 2017 18,200,000 58
* Hedged with an average floor price of
$46.85/bbl and a celling price of $60/bbl.
QUARTERLY RESULTS SUMMARY
---------------------------------------------------------------------------------------------------------
$'000 31 31 30 30 31 31 30 30
Mar Dec Sep Jun Mar Dec Sep Jun
2017 2016 2016 2016 2016 2015 2015 2015
Revenue 37,239 41,346 44,585 24,511 33,250 35,340 42,108 59,152
Profit/(Loss)
Before
Tax 4,175 (16,256) (6,798) (44,081) (16,521) (363,562) 55,540 (26,826)
Profit/(Loss)
After
Tax 10,691 10,648 (70,694) (11,466) 17,712 (177,625) 42,812 39,888
Earnings
per share
"EPS"
- Basic(1) 0.03 0.26 (0.17) (0.03) 0.04 (0.35) 0.13 0.12
EPS -
Diluted(1) 0.02 0.25 (0.17) (0.03) 0.04 (0.35) 0.13 0.12
Common
shares
outstanding
(000) 415,886 413,099 411,784 411,784 411,384 411,384 329,519 329,519
--------------- -------- --------- --------- --------- --------- ---------- -------- ---------
(1) Based on weighted average number of
shares
The most significant factors to have affected
the Company's profit before tax during
the above quarters are fluctuations in
underlying commodity prices and movement
in production volumes. The Company has
utilised commodity and foreign exchange
hedging 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 commodity prices and
exchange rates. In addition, the significant
reduction in underlying commodity prices
over the period has resulted in impairment
write downs in Q4 2015. The tax charge/credit
can also be volatile, for example due
to the timing of recognition of losses.
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 31 March 2017 Ithaca had 415,885,700
common shares outstanding along with 21,536,481
options outstanding to employees and directors
to acquire common shares.
31 March
2017
Common Shares Outstanding 415,885,700
Share Price((1) $1.45/
Share
Total Market Capitalisation $603,034,265
(1) Represents the TSX close price (CAD$1.93)
on 31 March 2017. US$:CAD$ 0.75 on 31
March 2017
Following completion of the Delek takeover
offer on 3 May 2017 and the associated
exercise of share options in accordance
with the terms of the Offer, as of that
date the issued and outstanding common
shares of the Company totalled 425,338,568.
All share options not exercised and tendered
to the Offer have been surrendered and
cancelled. Accordingly, the fully diluted
common shares of the Company total 425,338,568
as of 3 May 2017.
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 31 March 2017, 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 31 March 2017, 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 31 March 2017, there were no changes
in the Company's internal control over
financial reporting that occurred during
the quarter ended 31 March 2017 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 The Company has certain lease agreements
Sheet Arrangements and rig commitments which were entered
into in the normal course of operations,
all of which are disclosed under the heading
"Commitments", above. Leases are treated
as either operating leases or finance
leases based on the extent to which risks
and rewards incidental to ownership lie
with the lessor or the lessee under IAS
17. Where appropriate, finance leases
are recorded on the balance sheet. As
at 31 March 2017, finance lease assets
of $28.1 million and related liabilities
of $29.8 million are included on the balance
sheet.
--------------------------------------------------
Related Party A director of the Company is a partner
Transactions of Burstall Winger Zammit LLP who acts
as counsel for the Company. The amount
of fees paid to Burstall Winger Zammit
LLP in Q1 2017 was $0.0 million (Q1 2016:
$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 31 March 2017 the Company had loans
receivable from FPF-1 Limited and FPU
Services Limited, associates of the Company,
for $59.7 million and $0.0 million, respectively
(31 March 2016: $60.5 million and $0.1
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 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 2016 were 76 MMboe
(see "Licence Portfolio Activities").
These reserves were independently assessed
by Sproule, a qualified reserves evaluator,
as of December 31, 2016 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.
--------------------------------------------------
Well Test Certain well test results disclosed in
Results 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 2016, (the
"AIF") filed on SEDAR at www.sedar.com.
Commodity RISK: The Company's performance is significantly
Price Volatility impacted 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,
as a means of establishing a floor in
realised prices.
---------------------------------------------------
Foreign Exchange RISK: The Company is exposed to financial
Risk risks including 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
gas sales.
---------------------------------------------------
Interest Rate RISK: The Company is exposed to fluctuation
Risk in interest 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
Risk risks relating 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: To the extent cashflow from operations
Risk 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 RISK: The Company is and may in the future
Credit Risk be exposed to third party credit risk
through its contractual arrangements with
its current and future joint venture partners,
marketers of its petroleum production
and other parties.
The 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 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 and the Department of
Business, Energy & Industrial Strategy
("BEIS"). 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: The Company is subject to the risks
Risk 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, with the exception of the Wytch
Farm field for whjch the facilities are
located onshore in the south of England,
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: The Company is executing development
Risk 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: In all areas of the Company's business,
Risk 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: In the event a major incident were
Risk 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
Information by reference herein contain certain forward-looking
Advisories 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;
* Completion of the proposed compulsory acquisition by
the Offeror under the Business Corporations Act
(Alberta);
* The proposed cancellation of admission to trading on
the AIM market of the London Stock Exchange, the
proposed voluntary delisting for the TSX;
* 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 Stella post start-up commissioning
operations and production ramp up timings;
* 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 taxes;
* Adverse regulatory or court rulings, orders and
decisions; and,
* Risks associated with the nature of the common
shares.
Additional The information in this MD&A is provided
Reader Advisories as of 15 May 2017. The Q1 2017 results
have been compared to the results of the
comparative period in 2016. This MD&A
should be read in conjunction with the
Company's unaudited consolidated financial
statements as at 31 March 2017 and 2016
together with the accompanying notes and
Annual Information Form ("AIF") for the
year ended 31 December 2016. 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 months ended 31 March
2017 and 2016
(unaudited)
2017 2016
Note US$'000 US$'000
--------------------------------------------- ------ --------- --------------------------
Revenue 5 37,239 33,250
Operating costs (18,118) (20,185)
Other (115) -
Movement in oil and gas inventory 2,795 (6,325)
Depletion, depreciation and
amortisation (14,472) (17,608)
-------------------------------------------------- ------ --------- --------------------------
Cost of
sales (29,910) (44,118)
Gross Profit /(Loss) 7,329 (10,868)
Exploration and evaluation
expenses 10 (745) (421)
Gain on financial
instruments 25 5,706 5,179
Total administrative
expenses 6 (1,645) (1,769)
Foreign exchange 1,708 502
Finance costs 7 (8,624) (9,173)
Interest income 409 29
Share of profit in
associate 38 -
------------------------------------------------- ------ --------- --------------------------
Profit/(Loss) Before
Tax 4,175 (16,521)
Taxation 23 6,516 34,233
----------------------------------------------- ------ --------- --------------------------
Profit After
Tax 10,691 17,712
Earnings per share
(US$ per share)
Basic 22 0.03 0.04
Diluted 22 0.02 0.04
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 22
are an integral part of the financial statements.
Consolidated Statement
of Financial Position
(unaudited)
31 March 31 December
Note 2017 2016
US$'000 US$'000
-------------------------------- -------- ---------------------- -------------------
ASSETS
Current assets
Cash and cash equivalents 5,870 27,199
Accounts receivable 8 135,105 157,912
Deposits, prepaid
expenses and other 1,142 667
Inventory 9 25,827 27,729
Derivative financial
instruments 26 7,812 11,512
-------------------------------- -------- ---------------------- -------------------
175,756 225,019
Non-current assets
Long-term receivable 28 60,157 59,922
Long-term inventory 9 8,438 8,438
Investment in associate 13 18,375 18,337
Exploration and evaluation
assets 10 28,150 27,075
Property, plant &
equipment 11 1,081,769 1,084,599
Deferred tax assets 390,179 383,663
Goodwill 12 123,510 123,510
-------------------------------- -------- ---------------------- -------------------
1,710,578 1,705,544
Total assets 1,886,334 1,930,563
LIABILITIES AND EQUITY
Current liabilities
Trade and other payables 15 (187,768) (236,928)
Contingent consideration 19 - (4,000)
Derivative financial
instruments 26 (2,812) (4,329)
(190,580) (245,257)
Non-current liabilities
Borrowings 14 (614,585) (618,566)
Decommissioning liabilities 16 (208,434) (206,933)
Other long term liabilities 17 (107,853) (107,428)
Contingent consideration 19 (8,650) (8,650)
(939,522) (941,577)
Net Assets 756,232 743,729
-------------------------------- -------- ---------------------- -------------------
Equity
Share capital 20 621,345 619,207
Share based payment
reserve 21 24,859 25,185
Retained earnings 110,028 99,337
Total Equity 756,232 743,729
-------------------------------- -------- ---------------------- -------------------
The financial statements were approved by the Board of Directors on 12 May 2017
and signed on its behalf by:
"Les Thomas"
--------------------------------
Director
"Alec Carstairs"
--------------------------------
Director
The accompanying notes on pages 6 to 22 are an integral part of the financial statements.
Consolidated Statement of Changes in Equity
(unaudited)
Share Share Retained Total
capital based earnings Equity
payment
reserve
US$'000 US$'000 US$'000 US$'000
--------------------- --------------------- --------- ---------- --------
Balance, 1 Jan
2016 617,375 22,678 153,136 793,189
Share based payment - 768 - 768
Profit for the
period - - 17,712 17,712
--------------------- --------------------- --------- ---------- --------
Balance, 31 March
2016 617,375 - 170,848 811,669
--------------------- --------------------- --------- ---------- --------
Balance, 1 Jan
2017 619,207 25,185 99,337 743,729
Share based payment - 283 - 283
Shares issued 2,138 (609) - 1,529
Profit for the
period - - 10,691 10,691
Balance, 31 March
2017 621,345 24,859 110,028 756,232
--------------------- --------------------- --------- ---------- --------
The accompanying notes on pages 6 to 22 are an integral part of the financial statements.
Consolidated Statement of Cash Flow
For the three months ended 31 March 2017 and 2016
(unaudited)
2017 2016
Note US$'000 US$'000
--- ----------------------------- ----- --------- ---------
CASH PROVIDED BY / (USED IN):
Operating
activities
Profit/(Loss)
Before Tax 4,175 (16,521)
Adjustments
for:
Depletion, depreciation and
amortisation 11 14,472 17,608
Exploration and evaluation
write off 10 745 421
Share based payment 6 65 111
Loan fee amortisation 7 1,040 1,040
Revaluation of financial
instruments 25 2,192 33,565
Accretion on decommissioning
provisions 16 2,069 2,273
Bank interest & charges 5,514 5,861
------------------------------------- ----- --------- ---------
Cash flow generated from operations 30,272 44,358
------------------------------------------- ----- --------- ---------
Changes in inventory, debtors and
creditors relating to operating
activities (6,916) 1,997
Petroleum Revenue Tax paid - (1,240)
Corporation Tax refunded - 6,009
Net cash generated from
operating activities 23,356 51,124
-------------------------------------- --- ----- --------- ---------
Investing
activities
Capital expenditure 19 (13,462) (8,818)
Contingent (4,000)
consideration -
Investment (38)
in associate -
Loan to associate (235) 685
Decommissioning (569) (2,037)
Changes in debtors and creditors
relating to investing activities (14,922) (5,796)
------------------------------------------------- --------- ---------
Net cash (used in) investing
activities (33,226) (15,966)
-------------------------------------- --- ----- --------- ---------
Financing
activities
Proceeds from issuance of
shares 2,138 -
Loan (repayment) (4,917) (25,000)
Bank interest & charges (8,805) -
------------------------------------------ ----- --------- ---------
Net cash used in financing
activities (11,584) (25,000)
-------------------------------------- --- ----- --------- ---------
Currency translation differences
relating to cash & cash equivalents 122 158
(Decrease)/Increase in cash
and cash equivalents (21,332) 10,316
------------------------------------------- ----- --------- ---------
Cash and cash equivalents,
beginning of period 27,199 11,543
Cash and cash equivalents,
end of period 5,870 21,859
-------------------------------------- --- ----- --------- ---------
The accompanying notes on pages 6 to 22 are an integral part of the financial statements.
Notes to the consolidated 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 12 May 2017,
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 2017
could result in restatement of these interim consolidated
financial statements.
The interim 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 interim 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 2016.
SIGNIFICANT ACCOUNTING POLICIES, JUDGEMENTS
3. 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 28. 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
operations
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 income
statement 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 subsidiaries
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 20 (c). The expense is recorded
in the statement of income or capitalised for all
options granted in the year, with the gross increase
recorded in the share based payment reserve. Compensation
costs are based on the estimated fair values at
the time of the grant and the expense or capitalised
amount is recognised over the vesting period of
the options. Upon the exercise of the stock options,
consideration paid together with the amount previously
recognised in share based payment reserve is recorded
as an increase in share capital. In the event that
vested options expire unexercised, previously recognised
compensation expense associated with such stock
options is not reversed. In the event that unvested
options are forfeited or expired, previously recognised
compensation expense associated with the unvested
portion of such stock options is reversed.
Cash and cash
equivalents
For the purpose of 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 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.
Analyses of the fair values of financial instruments
and further details as to how they are measured
are provided in notes 25 to 27.
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 consolidated 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 are written off to the statement
of income in the period the relevant events occur.
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
For impairment review purposes the Corporation's
oil and gas assets are analysed into cash-generating
units ("CGUs") as identified in accordance with
IAS 36. A review is carried out each reporting
date for any indicators that the carrying value
of the Corporation's assets may be impaired. For
assets where there are such indicators, an impairment
test is carried out on the CGU. 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. If the recoverable
amount of an asset is estimated to be less that
its carrying amount, the carrying amount of the
asset is reduced to the recoverable amount. The
resulting impairment losses are written off 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.
Contingent consideration
Contingent consideration is accounted for as a
financial liability and measured at fair value
at the date of acquisition with any subsequent
remeasurements recognised either in profit or
loss or in other comprehensive income in accordance
with IAS 39.
Taxation
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
The following standards have been published and
are mandatory for the Group's accounting periods
beginning on or after 1 January 2018, but the
Group has not early adopted them:
- IFRS 15 'Revenue from contracts with customers'
is effective for accounting periods beginning
on or after 1 January 2018.
- IFRS 9 'Financial instruments' is effective
for accounting periods on or after 1 January
2018.
- IFRS 16 'Leases' is effective for accounting
periods beginning on or after 1 January 2019.
Significant accounting judgements and estimation
uncertainties
The preparation of financial statements in conformity
with IFRS requires management to make estimates
and assumptions regarding certain assets, liabilities,
revenues and expenses. Such estimates must often
be made based on unsettled transactions and other
events and a precise determination of many assets
and liabilities is dependent upon future events.
Actual results may differ from estimated amounts.
The amounts recorded for depletion, depreciation
of property and equipment, long-term liability,
share based payment, contingent consideration,
onerous contract provisions, decommissioning
liabilities, derivatives, and deferred taxes
are based on estimates. The depreciation charge,
any impairment tests and fair value estimates
for the purpose of purchase price allocation
(business combinations) 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 development and production and related activities in a single geographical area presently being the North Sea.
5. REVENUE
Three months ended
31 March
2017 2016
US$'000 US$'000
------------------ ---------- ---------
Oil sales 35,941 32,031
Gas sales 1,130 1,071
Condensate sales 116 128
Other income 52 20
-------------------- ---------- ---------
37,239 33,250
6. ADMINISTRATIVE EXPENSES
Three months ended
31 March
2017 2016
US$'000 US$'000
-------------------------- ---------- ---------
General & administrative (1,580) (1,658)
Share based payment (65) (111)
---------------------------- ---------- ---------
(1,645) (1,769)
7. FINANCE COSTS
Three months ended 31 March
2017 2016
US$'000 US$'000
--------------------------- --------- ---------
Bank charges and interest (755) (1,152)
Senior notes interest (3,830) (3,830)
Finance lease interest (240) (254)
Non-operated asset
finance fees (12) (4)
Prepayment interest (678) (622)
Loan fee amortisation (1,040) (1,040)
Accretion (2,069) (2,273)
----------------------------- --------- ---------
(8,624) (9,173)
8. ACCOUNTS RECEIVABLE
31 March 31 Dec
2017 2016
US$'000 US$'000
---------------- --------- ---------
Trade debtors 124,857 146,190
Accrued income 10,247 11,722
------------------ --------- ---------
135,105 157,912
9. INVENTORY
31 March 31 Dec
2017 2016
Current US$'000 US$'000
--------------------- -------------------- ---------
Crude oil inventory 23,965 25,868
Materials inventory 1,862 1,861
--------------------- -------------------- ---------
25,827 27,729
31 March 31 Dec
2017 2016
Non-current US$'000 US$'000
--------------------- --------- ---------
Crude oil inventory 8,438 8,438
The non-current portion of inventory relates to long term stocks at the Sullom Voe Terminal.
10. EXPLORATION AND EVALUATION ASSETS
US$'000
----------------------------------- ------------------------
At 1 January 2016 11,223
Additions 15,363
Write offs/relinquishments (770)
Impairment 1,259
----------------------------------- ------------------------
At 31 December 2016 and 1 January
2017 27,075
Additions 1,820
Write offs/relinquishments (745)
At 31 March 2017 28,150
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 $0.8 million being expensed in the period to 31 March 2017.
11. PROPERY, PLANT AND EQUIPMENT
Development
& Production
Oil and Gas Other fixed
Assets assets Total
US$'000 US$'000 US$'000
Cost
At 1 January 2016 2,482,010 3,406 2,485,416
Additions 59,871 5 59,876
At 31 December 2016
and 1 January 2017 2,541,881 3,411 2,545,292
Additions 11,624 18 11,642
At 31 March 2017 2,553,505 3,429 2,556,934
DD&A and Impairment
At 1 January 2016 (1,380,826) (2,544) (1,383,370)
DD&A charge for the
period (70,250) (271) (70,521)
Impairment charge for
the period (6,802) - (6,802)
At 31 December 2016
and 1 January 2017 (1,457,878) (2,815) (1,460,693)
DD&A charge for the
period (14,413) (60) (14,472)
At 31 March 2017 (1,472,291) (2,875) (1,475,165)
NBV at 1 January 2016 1,101,184 862 1,102,046
NBV at 1 January 2017 1,084,003 596 1,084,599
NBV at 31 March 2017 1,081,214 554 1,081,769
The net book amount of property, plant and equipment includes $28.1million (31 December 2016: $28.5 million) in respect of the Pierce FPSO lease held under finance lease.
12. GOODWILL
31 March 31 Dec
2017 2016
US$'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 $13.6 million was recorded relating to goodwill.
13. INVESTMENT IN ASSOCIATES
31 March 31 Dec
2017 2016
US$'000 US$'000
-------------------------- ---------------- ----------
Investments in FPF-1 and
FPU services 18,375 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 an increase of $0.04m in value during the period with the above investment reflecting the Company's share of the associates' results.
14. BORROWINGS
31 March 31 Dec
2017 2016
US$'000 US$'000
----------------------------- -------------------- ----------
RBL facility (320,000) (324,918)
Senior notes (300,000) (300,000)
Long term bank fees 3,010 3,666
Long term senior notes fees 2,405 2,686
------------------------------------- -------------------- ----------
(614,585) (618,566)
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.
Senior Reserves Based Lending Facility
As at 31 March 2017, the Corporation has a Senior Reserved Based Lending ("Senior RBL") Facility of $475 million. As at 31 March 2017, $320 million (31 December 2016: $324 million) was drawn down under the Senior RBL. $3.0 million (31 December 2016: $3.7 million) of loan fees relating to the RBL have been capitalised and remain to be amortised.
Junior Reserves Based Lending Facility
As at 31 March 2017, the Corporation had a Junior Reserved Based Lending ("Junior RBL") Facility of $60 million. The facility remains undrawn at the period end.
Senior Notes
As at 31 March 2017, the Corporation had $300 million 8.125% senior unsecured notes due July 2019, with interest payable semi-annually. $2.4 million of loan fees (31 December 2016: $2.7 million) have been capitalised and remain to be amortised.
Covenants
The Corporation is subject to financial and operating covenants related to the facilities. Failure to meet the terms of one or more of these covenants may constitute an event of default as defined in the facility agreements, potentially resulting in accelerated repayment of the debt obligations.
The Corporation was in compliance with all its relevant financial and operating covenants during the period.
The key covenants in both the Senior and Junior RBLs are:
- A corporate cashflow projection showing total sources of funds must exceed total forecast uses of funds for the later of the following 12 months or until forecast first oil from the Stella field.
- The ratio of the net present value of cashflows secured under the RBL for the economic life of the fields to the amount drawn under the facility must not fall below 1.15:1
- The ratio of the net present value of cashflows secured under the RBL for the life of the debt facility to the amount drawn under the facility must not fall below 1.05:1.
There are no financial maintenance covenants tests under the senior notes.
Security provided against the facilities
The RBL facilities are secured by the assets of the guarantor members of the Ithaca Group, such security including share pledges, floating charges and/or debentures.
The Senior notes are unsecured senior debt of Ithaca Energy Inc., guaranteed by certain members of the Ithaca Group and subordinated to existing and future secured obligations.
15. TRADE AND OTHER PAYABLES
31 March 31 Dec
2017 2016
US$'000 US$'000
------------------------------ ---------- ----------
Trade payables (71,156) (96,762)
Accruals and deferred income (116,612) (140,166)
------------------------------ ---------- ----------
(187,768) (236,928)
16. DECOMMISSIONING LIABILITIES
31 March 31 Dec
2017 2016
US$'000 US$'000
------------------------------------ --------------------- ------------------------
Balance, beginning of period (206,933) (226,915)
Additions - (2,279)
Accretion (2,069) (9,215)
Revision to estimates - 27,248
Decommissioning provision utilised 568 4,228
Balance, end of period (208,434) (206,933)
The total future decommissioning liability was calculated by management based on its net ownership interest in all wells and facilities, estimated costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. The Corporation uses a risk free rate of 4.0 percent (31 December 2016: 4.0 percent) and an inflation rate of 2.0 percent (31 December 2016: 2.0 percent) over the varying lives of the assets to calculate the present value of the decommissioning liabilities. These costs are expected to be incurred at various intervals over the next 24 years.
The economic life and the timing of the obligations are dependent on Government legislation, commodity price and the future production profiles of the respective production and development facilities.
17. OTHER LONG-TERM LIABILITIES
31 March 31 Dec
2017 2016
US$'000 US$'000
------------------------ ---------- ----------
Shell prepayment (64,468) (64,017)
BP gas prepayment (13,553) (13,212)
Finance lease (29,830) (30,199)
------------------------ ---------- ----------
Balance, end of period (107,853) (107,428)
The prepayment balances relate to cash advances under the Shell oil sales agreement and BP gas sales agreement which have been classified as long-term liabilities as short-term repayment is not due in the current oil price environment. The finance lease relates to the Pierce FPSO acquired as part of the Summit acquisition.
18. FINANCE LEASE LIABILITY
31 March 31 Dec
2017 2016
US$'000 US$'000
-------------------------------- --------- ---------
Total minimum lease payments
Less than 1 year (2,595) (2,595)
Between 1 and 5 years (12,400) (12,434)
5 years and later (20,437) (21,043)
Interest
Less than 1 year (925) (939)
Between 1 and 5 years (3,761) (3,834)
5 years and later (2,767) (2,919)
Present value of minimum lease
payments
Less than 1 year (1,670) (1,656)
Between 1 and 5 years (8,639) (8,600)
5 years and later (17,670) (18,124)
-------------------------------- --------- ---------
The finance lease relates to the Pierce FPSO acquired as part of the Summit acquisition.
19. CONTINGENT CONSIDERATION
31 March 31 Dec
2017 2016
Current US$'000 US$'000
--------------------- ---------- ---------
Balance outstanding - (4,000)
The contingent consideration related to the acquisition of the Stella field and was paid after first oil.
31 March 31 Dec
2017 2016
Non-current US$'000 US$'000
-------------------- --------- ---------
Balance outstanding (8,650) -
The non-current contingent consideration balance at the end of the year relates to the acquisition of the Vorlich and Austen fields, with an amount payable upon FDP submission of $5.9 million and subsequent payment of $2.75 million payable due upon defined production criteria being met.
20. SHARE CAPITAL
Number of Amount
Authorised share capital ordinary US$'000
shares
------------------------------------- ------------------ ------------------------
At 31 March 2017 and 31 December Unlimited -
2016
(a) Issued
The issued share capital is
as follows:
Issued Number of Amount
common shares US$'000
------------------------------------- ------------------ ------------------------
Balance 1 January 2017 413,099,042 619,207
Issued for cash - options exercised 2,786,658 2,138
------------------------------------- ------------------ ------------------------
Balance 31 December 2017 415,885,700 621,345
(b) Stock options
No new stock options have been granted in the quarter ended 31 March 2017.
The Corporation's stock options and exercise prices are denominated in Canadian Dollars when granted. As at 31 March 2017, 21,536,481 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.
Subsequent to the quarter end conditions of a cash takeover offer for all the common shares of the Company not owned by Delek Group Ltd. ("Delek") or any of its affiliates for C$1.95 per share (the "Offer") have been satisfied and the Offer has been accepted by holders of approximately 70.3% of the issued and outstanding common shares, not including the common shares already owned by Delek prior to the announcement of the Offer. As a result of this transactions all stock option have immediately vested.
Changes to the Corporation's stock options are summarised as follows:
31 March 2017 31 December 2016
---------------------- ---------------------------------------------- ------------------------
Wt. Avg Wt. Avg
No. of Exercise No. of Exercise
Options Price* Options Price*
---------------------- ---------------------- ---------------------- ------------ ----------
Balance, beginning
of year 24,413,139 $1.10 19,216,206 $1.70
Granted - - 12,000,000 $0.40
Forfeited / expired (90,000) $2.00 (5,088,070) $1.81
Exercised (2,786,658) $0.58 (1,714,997) $0.85
---------------------- ---------------------- ---------------------- ------------ ----------
Options outstanding,
end of year 21,536,481 $1.16 24,413,139 $1.10
---------------------- ---------------------- ---------------------- ------------ ----------
* 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 31 March 2017:
Options Outstanding Options Exercisable
-------------------------------------------------------- ----------------------------------------------------
Wt. Wt. Wt. Wt.
Range of No. Avg Avg Range of Avg Avg
Exercise of Life Exercise Exercise No. of Life Exercise
Price Options (Years) Price* Price Options (Years) Price*
----------------- ----------- ------------ ---------- ---------------- ----------- --------- ----------
$2.45-$2.51 $2.45-$2.51
(C$2.53-C$2.71) 6,373,136 1.2 $2.47 (C$2.53-C$2.71) 6,341,469 0.7 $2.47
$0.84-$0.93 $0.84-$0.93
(C$1.04-C$1.06) 5,505,005 1.7 $0.93 (C$1.04-C$1.06) 2,750,005 1.7 $0.92
$0.40 (C$0.55) 9,658,340 2.8 $0.40 $0.40 (C$0.55) 2,158,338 2.8 $0.40
----------------- ----------- ------------ ---------- ---------------- ----------- --------- ------------
21,536,481 2.2 $1.16 11,249,812 1.1 $1.69
================= =========== ============ ========== ================ =========== ========= ============
The following is a summary of stock options as at 31 December 2016:
Options Outstanding Options Exercisable
----------------------------------------------------- -----------------------------------------------------
Wt. Wt. Wt. Wt.
Range of No. Avg Avg Range of Avg Avg
Exercise of Life Exercise Exercise No. of Life Exercise
Price Options (Years) Price* Price Options (Years) Price*
----------------- ----------- --------- ---------- ---------------- ---------- ----------- ----------
$2.46-$2.51 $2.46-$2.51
(C$2.53-C$2.71) 6,373,136 1.0 $2.47 (C$2.53-C$2.71) 4,323,333 0.9 $2.47
$0.84-$1.01 $0.84-$1.01
(C$1.04-C$1.97) 6,590,003 1.9 $0.93 (C$1.04-C$1.97) 3,835,003 1.9 $0.94
$0.40 (C$0.55) 11,450,000 3.0 $0.40 $0.40 (C$0.55) 200,000 0.5 $0.40
----------------- ----------- --------- ---------- ---------------- ---------- ----------- ------------
24,413,139 2.2 $1.10 8,358,336 1.1 $1.72
================= =========== ========= ========== ================ ========== =========== ============
(c) Share based payments
Options granted are accounted for using the fair value method. The cost during the three months ended 31 March 2017 for total stock options granted was $0.3 million (Q1 2016: $0.8million). $0.1 million was charged through the statement of income for stock based compensation for the three months ended 31 March 2017 (Q1 2016: $0.1 million), being the Corporation's share of stock based compensation chargeable through the statement of income. The remainder of the Corporation's share of stock based compensation has been capitalised. The fair value of each stock option granted in the period was estimated at the date of grant, using the Black-Scholes option pricing model with the following assumptions:
For the three For the year
months ended ended
31 March 2017 31 December 2016 2013 2012
-------------------------------------------- ------------------ ----------
Risk free interest
rate N/A 0.53% 1.37% 0.40%
Expected stock volatility N/A 60% 51% 74%
Expected life of options N/A 3 years 2 years 3 years
Weighted Average Fair
Value N/A C$0.22 $0.82 $1.08
21. SHARE BASED PAYMENT RESERVE
31 March 31 Dec
2017 2016
US$'000 US$'000
------------------------------ ----------- ----------
Balance, beginning of period 25,185 22,678
Share based payment cost 283 3,058
Transfer to share capital
on exercise of options (609) (551)
------------------------------ ----------- ----------
Balance, end of period 24,859 25,185
22. EARNINGS PER SHARE
The calculation of basic earnings per share is based on the profit after tax and the weighted average number of common shares in issue during the period. The calculation of diluted earnings per share is based on the profit after tax and the weighted average number of potential common shares in issue during the year.
Three months ended
31 March
-------------------------------
2017 2016
------------------------------- ------------ ------------
Weighted av. number of common
shares (basic) 414,607,667 411,384,045
Weighted av. number of common
shares (diluted) 423,622,600 411,384,045
23. TAXATION
Three months ended 31 March
2017 2016
US$'000 US$'000
----------- --------- ---------
Taxation 6,516 34,233
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 legal completion of the SPA, in accordance with its terms, of a sum calculated at the prevailing tax rate applied to the relevant capital allowances. The relevant capital allowances are expected to be around $250 million and implies, assuming current tax rates, a payment of approximately $100 million. The taxation credit above includes a deferred tax charge in the quarter of $1.5 million resulting in a total related deferred tax asset at 31 March 2017 of $93.5 million.
24. COMMITMENTS
31 March 31 Dec
2017 2016
US$'000 US$'000
----------------------------- --------- ---------
Operating lease commitments
Within one year 216 240
Two to five years - 30
Capital commitments
31 March 31 Dec
2017 2016
US$'000 US$'000
--------------------------------------- --------- ---------
Capital commitments incurred jointly
with other ventures (Ithaca's share) 27,812 18,912
In addition to the amounts above, in 2015 Ithaca entered into an agreement with Petrofac in respect of the FPF-1 Floating Production facility whereby 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 fully ramped production is achieved from the Stella field. A further payment to Petrofac of up to $34 million was initially to be made by Ithaca dependent on the timing of sail-away of the FPF-1. This further payment was revised to $17 million in Q3 2016. This payment will also be deferred until three and a half years after fully ramped up production is achieved from the Stella field.
25. FINANCIAL INSTRUMENTS
To estimate the 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 31 March 2017:
Total
Level Level Level Fair
1 2 3 Value
US$'000 US$'000 US$'000 US$'000
-------------------------- ---------- --------- --------------------- ----------
Contingent consideration - (8,650) - (8,650)
Derivative financial
instrument asset - 7,812 - 7,812
Derivative financial
instrument liability - (2,812) - (2,812)
-------------------------- ---------- --------- --------------------- ----------
The table below presents the total gain on financial instruments that has been disclosed through the consolidated statement of comprehensive income:
Three months ended
31 March
2017 2016
US$'000 US$'000
---------------------------- --------------------- ---------
Revaluation of forex
forward contracts (17) (1,220)
Revaluation of commodity
hedges (2,175) (32,335)
Revaluation of interest
rate swaps - (10)
(2,192) (33,565)
Realised (loss) on
forex contracts - (419)
Realised gain on commodity
hedges 7,898 39,163
------------------------------ --------------------- ---------
7,898 38,744
Total gain on financial
instruments 5,706 5,179
The Corporation has identified that it is exposed principally to these areas of market risk.
i) Commodity Risk
The table below presents the total gain on commodity hedges that has been disclosed through the statement of income at the quarter end:
Three months ended 31 March
2017 2016
US$'000 US$'000
----------------------------------- -------------------- ---------
Revaluation of commodity hedges (2,175) (32,335)
Realised gain on commodity hedges 7,898 39,163
----------------------------------- -------------------- ---------
Total gain on commodity hedges 5,723 6,828
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
------------ -------------- ----------- ------- --------------
Apr 17 - June bbls
Oil swaps 17 261,541 $69.6/bbl
Apr 17 - June bbls
Oil puts 18 1,704,100 $54/bbl
Apr 17 - June bbls $46.85 -
Oil collars 18 812,506 $60.0/bbl*
Apr 17 - June therms
Gas puts 17 18,200,000 58p/therm
* hedged with an average floor price of $46.85/bbl and a celling price of $60/bbl.
ii) Interest Risk
The table below presents the total loss on interest financial instruments that has been disclosed statement of income at the quarter end:
Three months ended 31 March
2017 2016
US$'000 US$'000
------------------------------------ ---------------------- ---------
Revaluation of interest contracts - (10)
Total (loss) on interest contracts - (10)
Calculation of interest payments for the RBL Facility agreement incorporates LIBOR. The Corporation is therefore exposed to interest rate risk to the extent that LIBOR may fluctuate.
There were no interest rate financial instruments in place at the quarter end.
iii) Foreign Exchange Rate Risk
The table below presents the total loss on foreign exchange financial instruments that has been disclosed through the statement of income at the quarter end:
Three months ended
31 March
2017 2016
US$'000 US$'000
---------------------------------- --------------------- ---------
Revaluation of forex forward
contracts (17) (1,220)
Realised (loss) on forex forward
contracts - (419)
---------------------------------- --------------------- ---------
Total (loss) on forex forward
contracts (17) (1,639)
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 statement of financial position translation of monetary accounts denominated in non-USD amounts upon spot rate fluctuations from quarter to quarter.
There were no foreign exchange financial instruments in place at the quarter end.
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 and Fionn is sold to Shell Trading International Ltd. Wytch Farm oil production is sold on the spot market. Cook gas is sold to Shell UK Ltd and Esso Exploration & Production UK Ltd. Prior to cessation of production, Causeway oil was sold to Shell Trading International Ltd and Topaz gas production was sold to Hartree Partners Oil and Gas.
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 31 March 2017, substantially all accounts receivables are current, being defined as less than 90 days. The Corporation has no allowance for doubtful accounts as at 31 March 2017 (31 December 2016: $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 31 March 2017, exposure is $7.8 million (31 December 2016: $11.5 million).
The Corporation also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values.
v) Liquidity Risk
Liquidity risk includes the risk that as a result of its operational liquidity requirements the Corporation will not have sufficient funds to settle a transaction on the due date. The Corporation manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Corporation considers the maturity profiles of its financial assets and liabilities. As at 31 March 2017 substantially all accounts payable are current.
The following table shows the timing of contractual cash outflows relating to trade and other payables.
Within 1 1 to 5 years
year US$'000
US$'000
------------------------------ --------------------- -------------------------
Accounts payable and accrued
liabilities (187,768) -
Other long term liabilities - (107,853)
Borrowings - (614,585)
------------------------------ --------------------- -------------------------
(187,768) (722,437)
26. DERIVATIVE FINANCIAL INSTRUMENTS
31 March 31 December
2017 2016
US$'000 US$'000
------------- --------------------- -------------------------
Oil swaps 4,350 7,786
Oil puts (2,679) (1,797)
Oil collars (132) (2,422)
Gas swaps - (110)
Gas puts 3,461 3,709
Other - 17
------------- --------------------- -------------------------
5,000 7,183
27. FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES
Financial instruments of the Corporation consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in these financial statements. At 31 March 2017, the classification of financial instruments and the carrying amounts reported on the statement of financial position and their estimated fair values are as follows:
31 March 2017 31 December
US$'000 2016
US$'000
----------------------------- ---------------------- ----------------------
Carrying Fair Carrying Fair
Classification Amount Value Amount Value
----------------------------- ---------- ---------- ---------- ----------
Cash and cash equivalents
(Held for trading) 5,870 5,870 27,199 27,199
Derivative financial
instruments (Held for
trading) 7,812 7,812 11,512 11,512
Accounts receivable (Loans
and Receivables) 135,105 135,105 157,912 157,912
Deposits 1,142 1,142 667 667
Long-term receivable
(Loans and Receivables) 60,157 60,157 59,922 59,922
Borrowings (Loans and
Receivables) (614,585) (614,585) (618,566) (618,566)
Contingent consideration (8,650) (8,650) (12,650) (12,650)
Derivative financial
instruments (Held for
trading) (2,812) (2,812) (4,329) (4,329)
Other long term liabilities (107,853) (107,853) (107,428) (107,428)
Accounts payable (Other
financial liabilities) (187,768) (187,768) (236,928) (236,928)
28. RELATED PARTY TRANSACTIONS
The consolidated financial statements include the financial statements of Ithaca Energy Inc. and its wholly-owned subsidiaries, listed below, and its net share in its associates FPU Services Limited and FPF-1 Limited.
Country of incorporation % equity interest
at 31 March
2017 2016
-------------------------- -------------------------- --------- ---------
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 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 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.
The following table provides the total amount of transactions that have been entered into with related parties during the quarter ending 31 March 2017 and 31 March 2016, as well as balances with related parties as of 31 March 2017 and 31 December 2016:
Sales Purchases Accounts receivable Accounts
payable
US$'000 US$'000 US$'000 US$'000
------------------ ------------ ---------- -------------------- ---------
Burstall Winger
Zammit LLP 2017 - 29 273 -
2016 - 125 - (38)
A director of the Corporation is a partner of Burstall Winger Zammit LLP who acts as counsel for the Corporation.
Loans to related Amounts owed from related
parties parties
2017 2016
US$'000 US$'000
------------------ ------------- -------------
FPF-1 Limited 60,111 60,523
FPU Services
Limited 46 54
--------------------- ------------- -------------
60,157 60,577
30. SUBSEQUENT EVENTS
On 6 February 2017 the Corporation announced that it had entered into a definitive support agreement with Delek Group Ltd on the terms of a cash takeover bid for all of the issued and to be issued common shares of Ithaca not currently owned by Delek or any of its affiliates for C$1.95 per share.
On 20 April 2017 the Corporation announced that the conditions of the cash takeover offer for all the common shares of the Company not owned by Delek Group Ltd. Subsequent to the quarter end conditions of a cash takeover offer for all the common shares of the Company not owned by Delek Group Ltd. or any of its affiliates for C$1.95 per share have been satisfied and the Offer had been accepted by holders of approximately 70.3% of the issued and outstanding common shares, not including the common shares already owned by Delek prior to the announcement of the Offer.
On the 4th May 2017 the Corporation announced that the share tendering process had now completed for the cash takeover offer made by Delek Group Ltd. Following payment for the common shares tendered during the mandatory extension period for the Offer that expired on 3 May 2017, Delek own 94.2% of the issued and outstanding common shares of the Company via its affiliate DKL Investments Limited.
On the 12 May 2017 the Corporation announced that DKL Investments Limited, had notified Ithaca that it intends to carry out a compulsory acquisition of all the remaining issued and outstanding common shares of the Company that are not currently owned by Delek at the offer proce of C$1.95 per share. The Corporation further announced that it intends to seek the cancellation of its admission to trading on the AIM market of the London Stock Exchange and to voluntarily delist from the TSX following completion of the Compulsory Acquisition.
This information is provided by RNS
The company news service from the London Stock Exchange
END
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