We could not find any results for:
Make sure your spelling is correct or try broadening your search.
Register for Free to get streaming real-time quotes, interactive charts, live options flow, and more.
| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Ithaca Energy | LSE:IAE | London | Ordinary Share | CA4656761042 | COM SHS NPV (DI) |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 110.75 | 0.00 | 01:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
From Apr 2019 to Apr 2024
TIDMIAE
RNS Number : 2616A
Ithaca Energy Inc
23 March 2017
Not for Distribution to U.S. Newswire Services or for Dissemination in the United States
Ithaca Energy Inc.
2016 Financial Results
23 March 2017
Ithaca Energy Inc. (TSX: IAE, LSE AIM: IAE) ("Ithaca" or the "Company") announces its financial results for the twelve months ended 31 December 2016, together with the results of its independent year-end reserves assessment and an operations update.
Financial and operating highlights
-- Average production of 9,310 barrels of oil equivalent per day ("boepd"), ahead of full year guidance of 9,000 boepd (2015: 12,066 boepd)
-- Unit operating expenditure reduced to $23/boe in 2016 (2015: $31/boe) -- 2016 cashflow from operations of $147 million, down from $261 million in 2015
-- Loss after tax of $54 million, impacted by the reduction in UK tax rates during the year (2015: $121 million)
-- Downside commodity price hedging in place to mid-2018 - 7,600 boepd at an average floor of $50/boe
-- Net debt reduced to $598 million at year-end 2016, down from $665 million at the start of 2016
-- Refinancing of the Company's debt facilities anticipated during 2017 -- Proved and probable reserves, as independently evaluated by Sproule(1) , increased to
76 MMboe, primarily as a result of the Vorlich and Austen licence acquisitions and updated portfolio work programmes
Greater Stella Area development activities
-- Stella field started up in February 2017 - production to date approximately 1,700 barrels of oil per day net to Ithaca
-- FPF-1 dynamic commissioning programme on-going - producing at reduced rates to minimise flaring until the gas processing systems are fully commissioned
-- Harrier field development programme underway - development drilling to be completed in 2017, with start-up of production expected in the second half of 2018
Recommended Delek cash takeover offer - opportunity created for shareholders to crystallise the full value of their investments at a premium cash price
-- Takeover offer by DLK Investments Limited, a wholly owned subsidiary of Delek Group Limited ("Delek"), announced on 6 February 2017 for a cash consideration of C$1.95 per share, which equates to approximately GBP1.19 per share(2)
-- Acceptance of the offer is unanimously recommended by the Board of Directors (excluding the Delek related party directors) based on an evaluation of the fullness of the offer relative to the future upsides and execution risks of the business
-- Shareholder circulars distributed and closing of initial deposit period set as 17.00 (Toronto time) on 20 April 2017 - the offer is conditional upon, amongst other things, more than 50% of the shares outstanding that are not currently owned by the Offeror and its affiliates being deposited by that time
Les Thomas, Chief Executive Officer, commented:
Our 2016 financial results reflect a year of good progress for the Company culminating in first oil from the Stella field in February 2017. This progress has been reflected in the near four-fold increase in our share price since the start of last year. Stella first oil was an important milestone for the Company and production is forecast to ramp-up upon completion of on-going dynamic commissioning of the gas processing facilities. Having reached this important milestone and after weighing up the potential risks and opportunities that lie ahead, the Board considers the takeover offer tabled by Delek as providing full value to shareholders and wholeheartedly recommends its acceptance."
Production & Operations
Average production in 2016 was 9,310 boepd (92% oil). The asset portfolio performed well over the course of the year, with production running ahead of the 9,000 boepd guidance as a result of solid performance from the Cook field.
As previously guided, average production in 2017 is anticipated to be in the range of 19,000 to 22,000 boepd (approximately 75% oil). This range reflects the Stella start-up schedule, the programme of planned maintenance shutdowns during the year and sensitivities associated with the performance of those operational programmes.
Production in the first quarter of 2017 is forecast to average approximately 9,200 boepd, including the initial contribution from the Stella field since mid-February 2017.
While the on-going dynamic commissioning operations are continuing on the FPF-1, the Stella field is being produced at reduced rates from two of the five wells on the field in order to limit gas flaring. As a consequence, average Stella production to date has been approximately 1,700 barrels of oil per day net to Ithaca.
Greater Stella Area Development
Stella
Following completion of the necessary offshore preparatory works on the FPF-1 floating production facility, first hydrocarbons from the Stella field was achieved in mid-February 2017. Production was initially started from one well on the field in order to commission and stabilise the liquid processing systems on the FPF-1 and commence oil exports to the shuttle tanker.
Continued progress is being made with the FPF-1 dynamic commissioning programme. The key outstanding tasks involve commissioning of the fuel gas system and the two gas export compressors, in order to commence gas exports to the CATS pipeline.
Initial load testing on the first of the two gas export compressors identified the requirement for modifications to the instrumentation on the machine in order to complete the commissioning scope. This work is in the process of being completed and it is expected that the planned commissioning programme will shortly recommence. Once load testing of the compressor has been satisfactorily proven, this will enable gas to be routed to the fuel gas system and initial pipeline exports to begin. Following this, testing of the second gas export compressor will commence.
Once both export compressors are operational the ramp-up to full production rates will commence, followed by optimisation of production across the wells on the field. While it was anticipated that the dynamic commissioning and ramp-up programme would take up to eight weeks to complete, it is likely that these activities will take longer, with the ramp-up phase of operations now expected to commence in April 2017.
GSA Oil Export Pipeline
The work programme that is underway for installation of the oil export pipeline from the FPF-1 to the Norpipe system remains scheduled for completion in the second half of 2017. The main outstanding activities to be completed are the installation and tie-in of the pipeline export pumps on the FPF-1 and installation of the final subsea connections that are required to be undertaken immediately prior to the switchover from shuttle tanker to pipeline export.
Harrier Development
As previously announced, activities on the Harrier field development programme are scheduled to commence in April 2017, with the arrival on location of the ENSCO 122 heavy duty jack-up drilling rig. The rig programme involves a multilateral well being drilled into the two reservoir formations on the field and is scheduled to be completed 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.
Financials
Hedging
The Company's commodity hedging position remains unchanged since the start of 2017. As of the start of this year the Company has 7,600 boepd (85% oil) hedged at an average floor price of $50/boe for the 18 months to 30 June 2018. Full commodity price upside exposure has been retained on 60% of the volumes hedged and upside exposure to $60/boe has been retained on a further 25% of the hedged volumes.
Operating Expenditure
Unit operating costs were reduced from $31/boe in 2015 to $23/boe in 2016, a year-on-year reduction of 26%. This reduction was achieved through supply chain cost saving initiatives, removing overheads and resetting the cost base to reflect the requirements of the current commodity price environment, combined with the cessation of operations at the Company's legacy high cost fields.
Forecast 2017 unit operating expenditure is anticipated to be approximately $18/boe, reflecting the anticipated positive impact on unit costs of Stella field production.
Capital Expenditure
Total capital expenditure in 2016 was $63 million, in line with the revised guidance issued during the year to reflect inclusion of the expenditure associated with acceleration of the GSA oil pipeline installation operations.
The planned capital expenditure programme for 2017 is forecast to total approximately $70 million. 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.
Tax
The Company had a UK tax allowances pool of over $1,700 million at 31 December 2016. At current commodity prices, the pool is forecast to shelter the Company from the payment of corporation tax over the medium term.
During the year the UK government reduced Corporation Tax rates levied on E&P companies by 10% and effectively abolished Petroleum Revenue Tax charges. As a result of these changes, a non-cash deferred tax charge of $58 million is reflected in the 2016 Income Statement.
Net Debt & Credit Facilities
The Company's net debt at 31 December 2016 was $598 million, down $67 million since the start of the year.
It is anticipated that net debt at the end of the first quarter of 2017 will be approximately $615 million. The increase on the year-end figure is due to anticipated movements in working capital. Net debt is forecast to resume its downward trend over the course of the year as a result of increased cashflow generation from the Stella field.
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.
Year-End Reserves
Total proved and probable ("2P") reserves as at 31 December 2016 have been independently estimated by Sproule(1) , a qualified reserves evaluator, as 76 million barrels of oil equivalent ("MMboe"). These reserves reflect the addition of the Vorlich and Austen licence acquisitions completed during 2016 and updated portfolio work programmes. Further details of the Sproule evaluation are set out in the Management Discussion and Analysis for the 2016 financial results.
The results of the Sproule reserves assessment do not result in a change in information that would reasonably be expected to alter the conclusions of the independent valuation prepared by GMP FirstEnergy for the purposes of Company's evaluation of the Delek takeover offer, which was completed in accordance with the requirements of Multilateral Instrument 61-101 - Protection of Minority Security Holders in Special Transactions. As such, the Company does not believe that the Sproule reserves assessment would reasonably be considered new information for the purposes of National Instrument 61-104 - Takeover Bids and Issuer Bids, that would reasonably be expected to affect the decision of the shareholders of the Company to accept or reject the Delek takeover offer.
Recommended Delek Takeover Offer
On 6 February 2017 the Company 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 (the "Offer").
The Offer is being made by DKL Investments Limited (the "Offeror"), an affiliate of Delek, which is currently Ithaca's largest shareholder and holds approximately 19.7% of the currently issued and outstanding common shares of the Company.
The Board of Directors excluding the Delek related party directors (the "Directors"), after consulting with its financial and legal advisers, considers the terms of the Offer to be in the best interests of Ithaca and its shareholders and have accordingly unanimously recommended that shareholders accept the Offer and deposit their shares. The principal reasons for this recommendation are centred on an evaluation of the fullness of the Offer relative to the future upsides and execution risks of the business.
A full explanation of the reasons underlying the recommendation to shareholders and the multiple factors evaluated by Directors is contained in the Directors' Circular that was issued to shareholders on 14 March 2017. The evaluation and its conclusion was made in light of the Directors' own knowledge of the business, the industry and the financial condition and prospects of the Company and based upon the recommendation of a special committee of independent directors ("the Special Committee"), which has been advised by RBC Capital Markets in its capacity as financial advisor to the Company.
The Offer will be open for acceptance until 17.00 (Toronto time) on 20 April 2017 (the "Expiry Time"). Shareholders wishing to accept the Offer must take action to deposit their shares.
Successful completion of the Offer is conditional upon, amongst other things, more than 50% of the common shares outstanding (excluding the shares already owned by the Offeror and its affiliates) being validly deposited under the Offer prior to the Expiry Time (the "Minimum Tender Condition"). No deposited shares will be purchased by the Offeror if the Minimum Tender Condition is not satisfied.
Full details of the Offer are contained in Takeover Bid Circular issued by Delek to shareholders of the Company on 14 March 2017 and the associated Ithaca Directors' Circular that was issued on the same date. Copies of both documents are available on the Company's website (www.ithacaenergy.com) and on SEDAR (www.sedar.com).
2016 Financial Results Conference Call
A conference call and webcast for investors and analysts will be held today at 12.00 GMT (08.00 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.
Notes
1. The year-end independent reserves evaluation has been performed by Sproule International Limited ("Sproule"), a qualified reserves evaluator, in accordance with the Canadian Oil and Gas Evaluation Handbook pursuant to NI 51-101 - Standards of Reserves Disclosure for Oil and Gas Activities.
2. Based on the closing exchange rate on 10 March 2017, as noted in the Takeover Bid Circular issued by Delek.
The audited consolidated financial statements of the Company for the year ended 31 December 2016 and the related Management Discussion and Analysis are available on the Company's website (www.ithacaenergy.com) and on SEDAR (www.sedar.com). All values in this release and the Company's financial disclosures are in US dollars, unless otherwise stated.
-S -
Enquiries:
Ithaca Energy
Les Thomas lthomas@ithacaenergy.com +44 (0)1224 650 261
Graham Forbes gforbes@ithacaenergy.com +44 (0)1224 652 151
Richard Smith rsmith@ithacaenergy.com +44 (0)1224 652 172
FTI Consulting
Edward Westropp edward.westropp@fticonsulting.com +44 (0)203 727 1521
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, 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).
Hot Features
Premium
2016 HIGHLIGHTS
===================================================================
Solid cashflow
generation * Average production of 9,310 barrels of oil equivalent
in the year per day ("boepd"), ahead of full year guidance of
9,000 boepd (2015: 12,066 boepd)
* Unit operating expenditure reduced to $23/boe in 2016
(2015: $31/boe)
* 2016 cashflow from operations of $147 million, down
from $240 million in 2015
* Loss after tax of $54 million, impacted by the
reduction in UK tax rates during the year (2015: $121
million)
* Downside commodity price hedging in place to mid-2018
- 7,600 boepd at an average floor of $50/boe
* Net debt reduced to $598 million at year-end 2016,
down from $665 million at the start of 2016
* Refinancing of the Company's debt facilities
anticipated during 2017
* Proved and probable reserves, as independently
evaluated by Sproule(1) , increased to 76 MMboe,
primarily as a result of the Vorlich and Austen
licence acquisitions and updated portfolio work
programmes
-------------------------------------------------------------------
Stella first
oil achieved * Stella field started up in February 2017 - production
on 16 February to date approximately 1,700 barrels of oil equivalent
2017 per day net to Ithaca
* FPF-1 dynamic commissioning programme on-going -
producing at reduced rates to minimise gas flaring
until the gas processing systems are fully
commissioned
* Harrier field development programme underway -
development drilling to be completed in 2017, with
start-up of production expected in the second half of
2018
Delek Offer
-opportunity * Takeover offer by DLK Investments Limited, a wholly
for shareholders owned subsidiary of Delek Group Limited("Delek"),
to crystallise announced on 6 February 2017 for a cash consideration
full value of C$1.95 per share, which equates to approximately
of their investments GBP1.19 per share(2)
at a premium
cash price
* Acceptance of the offer is unanimously recommended by
the Board of Directors (excluding the Delek related
party directors) based on a number of factors
including an evaluation of the fullness of the offer
relative to the future upsides and execution risks of
the business
* Shareholder circulars distributed and closing of
initial deposit period set as 17.00 (Toronto time) on
20 April 2017 - the offer is conditional upon,
amongst other things, more than 50% of the shares
outstanding that are not currently owned by the
Offeror and its affiliates being deposited
-------------------------------------------------------------------
(1) The year-end independent reserves evaluation has been performed by Sproule International Limited ("Sproule"), a qualified reserves evaluator, in accordance with the Canadian Oil and Gas Evaluation Handbook pursuant to NI 51-101 - Standards of Reserves Disclosure for Oil and Gas Activities.
(2) Based on the closing exchange rate on 10 March 2017, as noted in the shareholder circulars
SUMMARY STATEMENT OF INCOME
========================================================================
2016 2015
Average Production kboe/d 9.6 12.1
Average Realised Oil Price(1) $/bbl 44 54
Revenue(2) M$ 146.5 201.0
Commodity Hedging Cash Gain M$ 87.9 177.9
Revenue(2) (Incl. Cash Hedging Gain) M$ 234.4 378.9
Opex M$ (78.2) (106.5)
G&A M$ (4.7) (9.8)
Foreign Exchange(3) M$ (4.7) (1.7)
Cashflow from Operations M$ 146.8 261.0
DD&A & Impairment M$ (76.1) (520.5)
Non-Cash Hedging (Loss)/Gain M$ (119.3) (22.6)
Finance Costs M$ (36.6) (40.2)
Other Non-Cash Costs M$ 1.3 (4.1)
Loss before Taxation M$ (83.7) (326.4)
Taxation - Excluding Rate Changes M$ 87.8 245.7
- Reduced Tax Rates Impact M$ (57.9) (40.3)
Earnings Loss M$ (53.8) (121.0)
Cashflow Per Share $/Sh. 0.36 0.76
Earnings Per Share $/Sh. (0.13) (0.35)
(1) Average realised price before hedging
(2) Revenue net of stock movements
(3) Foreign exchange net of related realised
hedging gains & losses
SUMMARY BALANCE SHEET
========================================================================
M$ 31 Dec. 31 Dec.
2016 2015
Cash & Equivalents 27 12
Other Current
Assets 198 372
PP&E 1,112 1,113
Deferred Tax
Asset 384 356
Other Non-Current
Assets 210 211
Total Assets 1,931 2,063
Current Liabilities (245) (283)
Borrowings (619) (666)
Asset Retirement
Obligations (207) (227)
Other Non-Current
Liabilities (116) (93)
Total Liabilities (1,187) (1,270)
Net Assets 744 793
Share Capital 619 617
Other Reserves 25 23
Surplus 100 153
Shareholders'
Equity 744 793
CORPORATE STRATEGY
=============================================================
Ithaca Energy Inc. ("Ithaca" or the "Company")
is a North Sea oil and gas operator focused
on the delivery of lower risk growth through
the appraisal and development of UK undeveloped
discoveries and the exploitation of its
existing UK producing asset portfolio.
Ithaca's goal is to generate sustainable
long term shareholder value by building
a highly profitable 25kboepd North Sea
oil and gas company.
Execution of the Company's strategy is
focused on the following core activities:
* Maximising cashflow and production from the existing
asset base
* 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
-----------------------------------------------------
RECOMMED DELEK TAKEOVER OFFER
Unanimously On 6 February 2017 the Company announced
recommended that it had entered into a definitive
takeover by support agreement with Delek Group Ltd
Delek ("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 or any of its affiliates
for C$1.95 per share (the "Offer").
The Offer is being made by DKL Investments
Limited (the "Offeror"), an affiliate
of Delek, which is currently Ithaca's
largest shareholder and holds approximately
19.7% of the currently issued and outstanding
common shares of the Company.
The Board of Directors excluding the Delek
related party directors (the "Directors"),
after consulting with its financial and
legal advisers, considers the terms of
the Offer to be in the best interests
of Ithaca and its shareholders and accordingly
unanimously recommends that shareholders
accept the Offer and deposit their shares.
A principal reason for this recommendation
is centred on an evaluation of the fullness
of the Offer relative to the future upsides
and execution risks of the business.
A full explanation of the reasons underlying
the recommendation to shareholders and
the multiple factors evaluated by Directors
is contained in the Directors' Circular
that was issued to shareholders on 14
March 2017 and is available on the Company's
Sedar profile at Sedar.com. The evaluation
and its conclusion was made in light of
the Directors' own knowledge of the business,
the industry and the financial condition
and prospects of the Company and based
upon the recommendation of a special committee
of independent directors ("the Special
Committee"), which has been advised by
RBC Capital Markets ("RBC") in its capacity
as financial advisor to the Company.
The Offer will be open for acceptance
until 17.00 (Toronto time) on 20 April
2017 (the "Expiry Time"). Shareholders
wishing to accept the Offer must take
action to deposit their shares.
Successful completion of the Offer is
conditional upon, amongst other things,
more than 50% of the common shares outstanding
(excluding the shares already owned by
the Offeror and its affiliates) being
validly deposited under the Offer prior
to the Expiry Time (the "Minimum Tender
Condition"). No deposited shares will
be purchased by the Offeror if the Minimum
Tender Condition is not satisfied.
DEBT FACILITIES
Planned 2016 The Company completes a semi-annual redetermination
RBL redeterminations process with its reserves based lending
successfully ("RBL") bank syndicate, at the end of
completed April and October of each year, to review
- over $110M the borrowing capacity of its assets based
of headroom on the technical and commodity price assumptions
in place at applied by the syndicate. Following the
end 2016 successful completion of the October 2016
redetermination, the Company's available
RBL borrowing capacity is over $410 million.
When combined with the $300 million senior
unsecured notes the Company has in place,
the business has a total debt capacity
of over $710 million, maintaining in excess
of $110 million of funding headroom when
compared to net debt at the end of 2016
of $598 million.
The Company is focused on maintaining
a solid liquidity position, with substantial
deleveraging having already been delivered
before Stella first hydrocarbons. A robust
financial position has been retained during
the current period of lower and more volatile
oil prices as a result of various proactive
measures taken to increase the financial
strength of the business and ensure that
the Company has sufficient flexibility
to manage downside risks.
As a consequence of the substantial deleveraging,
the Company elected to reduce the size
of the debt facilities from $650 million
to $535 million in June 2016, saving approximately
$0.5 million in commitment fees for the
remainder of the year. This change has
no effect on the current RBL debt capacity
of approximately $410 million, as this
is below the reduced facility size of
$535 million.
Both RBL facilities are based on conventional
oil and gas industry borrowing base financing
terms, neither of which have historic
financial covenant tests. The Company's
$300 million senior unsecured notes, due
July 2019, similarly have no historic
financial covenant tests.
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.
DIRECTOR & EXECUTIVE CHANGES
Certain director and senior management
changes have been made since the start
of the year. Following the Company's annual
general meeting in June 2016, Jack Lee
and Frank Wormsbecker retired from the
Board of Directors. Brad Hurtubise, a
serving Non-Executive Director of the
board, succeeded Mr Lee as Non-Executive
Chairman. In January 2016 Richard Smith
was appointed to the executive team as
Chief Commercial Officer, and in April
2016, Nick Muir, Chief Technical Officer,
left the Company.
PRODUCTION & OPERATIONS
-----------------------------------------------------
2016 PRODUCTION
Solid 2016 The producing asset portfolio performed
production well during 2016, with production running
- ahead of ahead of the 9,000 boepd guidance largely
full year as a result of solid performance from
guidance the Cook field. Average production for
2016 was 9,310 boepd, 92% oil (2015: 12,066
boepd), which compares to full year base
production guidance of approximately 9,000
boepd.
When comparing 2016 with 2015, production
has down by approximately 23%. This reflects
the specific steps taken in 2015 to reposition
the portfolio to meet the requirements
of the lower Brent price environment,
namely the cessation of production from
the Athena and Anglia fields, and no significant
investment in the existing production
portfolio as a consequence of the prevailing
uncertainty and volatility in oil prices.
Production was also restricted on the
Pierce field during the first half of
2016 due to the requirement to complete
remedial works on the field's subsea gas
injection flowline.
2017 PRODUCTION
Average production in 2017 is anticipated
to be in the range of 19,000 to 22,000
boepd (approximately 75% oil). This range
reflects the updated Stella start-up schedule,
the programme of planned maintenance shutdowns
during the year and sensitivities associated
with the performance of those operational
programmes.
Production in the first quarter of 2017
is forecast to average approximately 9,200
boepd, including the initial contribution
from the Stella field since mid-February
2017.
While the on-going dynamic commissioning
operations are continuing on the FPF-1,
the Stella field is being produced at
reduced rates from two of the five wells
on the field. As a consequence, average
Stella production to date has been approximately
1,700 barrels of oil per day net to Ithaca,
with the produced gas being flared until
the fuel gas systems have been commissioned.
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 completion of the necessary
hydrocarbons offshore preparatory works on the FPF-1,
delivered first hydrocarbons from the Stella field
in February was achieved in mid-February 2017. Production
2017 - dynamic was initially started from one well on
commissioning the field in order to commission and stabilise
of the gas the hydrocarbon processing systems on
processing the FPF-1 and commence oil exports to
facilities the adjacent shuttle tanker.
on-going
Continued progress is being made with
the FPF-1 dynamic commissioning programme.
The key outstanding tasks involve commissioning
of the fuel gas system and the two gas
export compressors, in order to commence
gas exports to the CATS pipeline.
Initial load testing on the first of the
two gas export compressors identified
the requirement for modifications to the
instrumentation on the machine in order
to complete the commissioning scope. This
work is in the process of being completed
and it is expected that the planned commissioning
programme will shortly recommence. Once
load testing of the compressor has been
satisfactorily proven, this will enable
gas to be routed to the fuel gas system
and initial pipeline exports to begin.
Following this, testing of the second
gas export compressor will commence.
Once both export compressors are operational
the ramp-up to full production rates will
commence, followed by optimisation of
production across the wells on the field.
While it was anticipated that the dynamic
commissioning and ramp-up programme would
take up to eight weeks to complete, it
is likely that these activities will take
longer, with the ramp-up phase of operations
now expected to commence in April 2017.
GSA OIL EXPORT PIPELINE
Switch from Access to the Norpipe oil pipeline system
oil tanker was secured in 2016 for future GSA oil
to pipeline production, allowing a switch from tanker
export scheduled loading to pipeline exports during 2017.
for 2017 - This move will significantly reduce the
reducing fixed fixed operating costs of the GSA facilities
operating and enhance operational uptime, resulting
costs and in improved reserves recovery and increasing
increasing the long term value of the GSA as a production
the long term hub.
value of the The key work associated with creating
GSA a connection to the Norpipe system was
successfully executed as part of a fast-track
operational programme undertaken during
the planned summer 2016 pipeline maintenance
shutdown. Following this, the 44 kilometre
spurline from the FPF-1 to the Norpipe
system was installed in September 2016.
The main outstanding activities that now
remain to be completed are the installation
and tie-in of the pipeline export pumps
on the FPF-1 and installation of the final
subsea connections that need to be undertaken
immediately prior to the switchover from
shuttle tanker to pipeline export.
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 to in the Harrier field development programme
commence in will commence in 2017. The development
Q2 2017, commencing involves drilling of a multilateral well
the build into the two reservoir formations on the
out of the field, with the well tied back via a 7.5
GSA production kilometre pipe to an existing slot on
hub the Stella main drill centre manifold
for onward export and processing of production
on the FPF-1.
The GSA joint venture has contracted with
Ensco Offshore UK Limited for the provision
of a heavy duty jack-up drilling rig,
which is expected to arrive on location
in April 2017. The drilling programme
is forecast to be completed in the second
half of 2017 and the subsea infrastructure
installation activities in summer 2018,
resulting in the anticipated start-up
of Harrier production in the second half
of 2018.
LICENCE PORTFOLIO ACTIVITIES
-------------------------------------------------------
GSA SATELLITE ACQUISITIONs
Strategic In line with Ithaca's strategic objective
asset acquisitions to increase value from the GSA infrastructure
close to GSA through the acquisition of interests in
hub -opportunity potential satellite fields, the Company
to leverage has acquired approximately 33% of the
infrastructure the Vorlich discovery along with a 75%
value interest and operatorship of the Austen
discovery.
VORLICH
In October 2016 the Company completed
the acquisition of 100% of licence P1588
(Block 30/1f) through three purchases
from ENGIE E&P UK Limited ("ENGIE E&P"),
INEOS UK SNS Limited and Maersk Oil North
Sea Limited. Licence P1588 contains approximately
10-20% of the Vorlich discovery, with
the balance of the discovery located in
licence P363 (Block 30/1c). When taking
into account the P363 licence interest
acquired from TOTAL E&P UK Limited in
January 2016, these transactions increase
Ithaca's overall interest in the Vorlich
discovery by around 16%, to approximately
33%. The remaining interest is owned by
BP, who is also Operator of the Vorlich
licence.
Vorlich was discovered and appraised in
2014 with exploration well 30/1f-13A,Z
and 13Z. The well encountered hydrocarbons
in a Palaeocene sandstone reservoir in
Block 30/1c and a subsequent side-track
into Block 30/1f confirmed the westerly
extension of the discovery. The well was
flow tested at a maximum rate of 5,350
boepd (approximately 80% oil).
Vorlich is located approximately 10 kilometres
north of the Company's GSA production
hub and was estimated as of 31 December
2016 to contain gross proven and probable
undeveloped reserves of approximately
22 MMboe by Sproule. Following completion
of the Vorlich appraisal programme in
2014, current activities are focused on
planning and preparation of a Field Development
Plan ("FDP").
The overall Vorlich licence interests
are as follows:
* Licence P363: BP (Operator), 80%; Ithaca, 20%
* Licence PL1588: Ithaca (Operator), 100%
AUSTEN
In December 2016 an SPA was completed
with ENGIE E&P to acquire a 75% interest
and operatorship of Licence P1823 (Block
30/13b), effective 1 May 2016. The licence
contains the Austen discovery, which is
located approximately 30 kilometres south-east
of the GSA hub. Austen is an Upper Jurassic
oil / gas-condensate accumulation on which
a number of wells have been drilled, the
most recent being appraisal well 30/1b-10,10Z
drilled by ENGIE E&P in 2012.
It is planned for further subsurface and
development engineering studies to be
completed in order to advance preparation
of an FDP for approval prior to January
2019.
Cook Field Operatorship
Operatorship In March 2016 Ithaca took over operatorship
obtained of of the Cook field (61.345% working interest)
core producing following completion of Shell and ExxonMobil's
Cook field sale of the Anasuria floating production,
in 2016 storage and offloading vessel (and associated
feeder field interests), which serves
as the host facility for the field.
West Don Field LICENCE INTEREST
During Q1 2016 First Oil Expro Limited
("First Oil") entered into administration.
Consequently, the joint venture partners
in the West Don field have exercised their
forfeiture rights, resulting in Ithaca
acquiring a further 4.125% interest in
the West Don field for zero consideration
(proportionate to its West Don field interest
prior to the First Oil default). Ithaca's
total interest in the field is now 21.4%.
The Company does not expect any significant
cost exposure as a result of First Oil's
default other than the associated net
incremental decommissioning liability,
which is currently estimated to be $1.9
million.
COMMODITY HEDGING
------------------------------------------------
Additional As part of its financial and risk management
hedging put strategy, the Company actively seeks to
in place - maintain a balanced commodity hedging
commodity position. Any hedging is executed at the
price protection discretion of the Company, with no minimum
established requirements stipulated in any of the
for 7,600 Company's debt finance facilities.
boepd to June In 2016, the Company benefitted from realised
2018 commodity hedging gains for the year of
$87.9 million, equating to an additional
$25 of revenue per sales barrel of oil
equivalent in the year.
As of 1 January 2017, the Company has
7,600 boepd (85% oil) hedged at an average
floor price of $50/boe for the 18 months
to 30 June 2018. Full commodity price
upside exposure has been retained on 60%
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 January 2017, these
hedges were valued at $7.2 million.
RESERVES
------------------------------------------------
Total proved and probable ("2P") reserves
as at 31 December 2016 estimated to be
76 MMboe, as independently evaluated by
Sproule International Limited, a qualified
reserves evaluator, in accordance with
the Canadian Oil and Gas Evaluation Handbook
pursuant to NI 51-101 - Standards of Reserves
Disclosure for Oil and Gas Activities.
The movement in total 2P reserves between
end-2015 and end-2016 is set out in the
following table. In summary, the Company's
2P reserves have increased during 2016
primarily as a result of the acquisition
of the Vorlich and Austen licence interests,
coupled with technical revisions for future
work programmes on the Cook and Pierce
fields.
2P Reserves MMboe
Opening Reserves - 31
December 2015* 53.2
Production (3.4)
Relinquishments (1.0)
Acquisitions 16.2
Revisions - Economic /
Technical 11.5
Closing Reserves - 31
December 2016 76.5
* Excluding Vorlich reserves
of 3.8 MMboe, for which the
licence interest was acquired
in 2015 but the transaction
formally completed in 2016
The 2P reserves post-tax net present value
discounted at 10% ("NPV-10") assessed
by Sproule as at 31 December 2016 was
estimated as $1,528 million, based on
forecast Brent prices of $55/bbl in 2017
rising to $70/bbl in 2019 and over $80/bbl
in 2026. This represents an unrisked estimate
of the value of the individual producing
and development assets, including four
future GSA development projects, drilling
of a water injection well on the Cook
field and modification of the Pierce field
for the gas blowdown phase of operations.
This Sproule NPV-10 is not a company valuation
as it does not take into account the future
financial liabilities of the Company or
the estimated decommissioning costs associated
with assets that have ceased production
prior to the date of the evaluation, being
Jacky, Athena, Anglia, Causeway and certain
well abandonment obligations. The following
table, taking account of the factors noted
above, sets out the implied unrisked Company
post tax net asset value ("NAV") derived
from the Sproule evaluation of C$2.03
per fully diluted share.
Unrisked / Sproule Price Deck $million
Sproule Post-Tax NAV at 31.12.16 1,528
Deductions:
RBL Facility (Net of Cash) (298)
Senior Notes (300)
Petrofac Payments(1) (131)
Shell / BP Prepayment (FS note 19) (77)
Decommissioning (Non-Sproule Assets) (60)
Unrisked Vorlich/Austen Contingent Consideration (FS note 21) (11)
Implied Unrisked Company Post-Tax NAV at 31.12.16 651
Implied Fully Diluted Share Price (C$/Sh.)(2) C$2.03
1. As per Financial Statements note 25 ($100M) and note 26 ($31M)
2. 431 million fully diluted shares, which includes in-the-money options relative to
the takeover
offer price
OPERATING EXPITURE
--------------------------------------------------------
Full year Continued operating cost savings have
opex under reduced 2016 unit operating costs to $23/boe,
guidance for down from $31/boe in 2015 and below the
current producing $30/boe guidance provided at the start
asset base of the year. Cost reductions have been
at $23/boe achieved across the portfolio, with the
Cook, Pierce and Wytch Farm fields delivering
the most significant savings.
Forecast 2017 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
---------------------------------------------------------------
2016 capital Total capital expenditure in 2016 was
expenditure $63 million, in line with the revised
of $60M with guidance issued during the year to reflect
2017 expected inclusion of the expenditure associated
expenditure with acceleration of the GSA oil pipeline
of $70M installation operations.
Net 2017 capital expenditure is forecast
to total approximately $70 million. The
majority of this expenditure relates to
the GSA, primarily being Harrier development
activities plus completion of the GSA
oil export pipeline investment programme
and Vorlich field development planning
activities. The forecast expenditure is
also inclusive of any additional Stella
start-up costs, which are expected to
be minimal.
NET DEBT
---------------------------------------------------------------
Further deleveraging DEBT SUMMARY (M$) 31 Dec. 31 Dec.
delivered 2016 2015
in 2016 - RBL Facility 324.9 376.8
net debt reduced Senior Notes 300.0 300.0
to $598M at Total Debt 624.9 676.8
end 2016 UK Cash and Cash Equivalents (27.2) (11.5)
Net Drawn Debt 597.7 665.3
Note this table shows debt repayable as
opposed to the reported balance sheet
debt which nets off capitalised RBL and
senior note costs
Net debt was reduced by $67 million in
2016 to $598 million at 31 December 2016.
This reduction reflects the benefit of
continuing strong operating cashflow generation
from the base producing assets delivered
as a result of solid production, reduced
operating costs and lower capital expenditures
across the portfolio.
TRADING ENVIRONMENT
-------------------------------------------------
COMMODITY PRICES
-------------------------------------------------
2016 2015
Average Brent
Price $/bbl 44 52
The 2016 financial results reflect the
impact of the continued reduction in Brent
prices that has been a central feature
of the sector since the middle of 2014.
The average Brent price fell by 15% to
$44/bbl in 2016, down from $52/bbl in
2015. While this has had a significant
negative impact on revenues, the fall
in Brent has been materially mitigated
during the period by the significant hedging
protection the Company had in place.
FOREIGN EXCHANGE RATES
-------------------------------------------------
2016 2015
GBP : USD
average 1.36 1.53
GBP : USD
period end
spot 1.23 1.48
Volatility in exchanges rates resulting
from the UK's decision during 2016 to
exit the European Union, has also 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 US dollar denominated
oil sales, while approximately 80% of
costs are incurred in pounds sterling.
In general, however, the company has sought
to minimise currency volatility through
active hedging of sterling.
SELECTED ANNUAL INFORMATION
------------------------------------------------------------------------
* Revenues have reduced by approximately 30% in 2016 as
a result of a decrease in the realised oil price,
which was also the main driver behind the reduction
in revenues in 2015 compared to 2014, combined with a
reduction in underlying sales volumes.
* Total assets decreased from 2015 to 2016 mainly as a
result of the decrease in the derivative financial
instruments as they unwound and were realised. The
cash realised from the derivatives has been used to
pay down debt and therefore reduce liabilities. The
movement from 2014 to 2015 was mainly due to the
impairment write downs driven by the oil price
environment.
* In 2015 a non-cash impairment charge of $203 million
(post-tax) turned a pre impairment post-tax profit of
$82 million into a post-tax loss of $121 million. A
similar impairment charge ($173 million post-tax) was
recorded in 2014. These impairments resulted from
materially lower near term oil prices assumptions. In
2016 there has been no further significant change in
the oil price environment, therefore 2016 shows a
modest post-tax impairment of $3m due to the
cessation of production from the Causeway and Topaz
fields.
Years Ending 31 December 2016 2015 2014
($'000)
Total Revenue 143,691 206,975 378,593
Cashflow from operations 146,838 261,048 181,465
-------------------------- ---------- ---------- ------------
(Loss)/Profit After
Tax (pre impairment) (50,474) 81,612 139,993
(Loss)/Profit After
Tax (post impairment) (53,800) (121,005) (24,535)
-------------------------- ---------- ---------- ------------
Total Assets 1,903,854 2,062,881 2,358,775
Total Non-Current
Liabilities (937,256) (985,785) (1,094,571)
-------------------------- ---------- ---------- ------------
Net Earnings Per
Share ($/Sh.) (1) (0.13) (0.35) (0.07)
Net Earnings Per
Share - Fully Diluted
($/Sh.) (1) (0.13) (0.35) (0.07)
Cashflow Per Share
($/Sh.) (1) 0.36 0.76 0.55
Cashflow Per Share
- Fully Diluted ($/Sh.)
(1) 0.36 0.76 0.55
Weighted Average
No. Shares (000s) 411,644 345,667 328,381
Weighted Average
No. Shares - diluted
(000s) 412,077 345,667 329,952
-------------------------- ---------- ---------- ------------
(1) Weighted average number of shares
2016 RESULTS OF OPERATIONS
--------------------------------------------------
REVENUE
--------------------------------------------------
Average Realised
Price 2016 2015
Oil Pre-Hedging $/bbl 44 54
Oil Post-Hedging $/bbl 59 95
Revenue decreased by $63.3 million in
2016 to $143.7 million (2015: $207.0 million)
primarily as a consequence of an $11/bbl
or 20% decrease in the pre-hedging realised
oil price associated with the fall in
Brent during the year, coupled with a
20% decrease in underlying sales volumes.
While produced volumes decreased by 23%
in 2016 compared to 2015, sales volumes
decreased to a slightly lesser extent
due to lifting schedules, in particular,
larger oil liftings from the Cook field
in 2016. Sales volumes decreased overall
in 2016 primarily due to the cessation
of production from the Athena, Anglia
and Causeway fields as well as reduced
production on the Dons fields.
The reduction in the average realised
price for the year was offset to a significant
extent by realised oil and gas hedging
gains of $25 per sales barrel of oil equivalent
in the year, resulting in an $87.9 million
gain on commodities being reported through
Foreign Exchange and Financial Instruments
(see below).
In terms of the average realised oil price
for the year, there was a decrease to
$44/bbl in 2016 (2015: $54/bbl) in line
with the average price of Brent for the
twelve months ended 31 December 2016 (2015:
$52/bbl). While realised oil prices for
each of the fields in the Company's portfolio
do not strictly follow the Brent price
pattern, with some fields sold at a discount
or premium to Brent and under contracts
with differing timescales for pricing,
the average realised price for all the
fields traded in line with Brent.
COST OF SALES
-----------------------------------------------------
$'000 2016 2015
Operating Expenditure 78,219 106,468
DD&A 70,521 120,230
Movement in Oil
& Gas Inventory (2,804) 6,030
Total 145,936 232,728
Cost of sales decreased in 2016 by approximately
37% to $145.9 million (2015: $232.7 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
27% in the year to $78.2 million (2015:
$106.5 million). Cost reductions were
achieved across the portfolio, with the
Cook, Pierce and Wytch Farm fields delivering
the most significant savings. This continued
focus on driving down costs resulted in
a unit operating cost of $23/boe for 2016,
representing a reduction of over 25% compared
to the equivalent rate of $31/boe for
2015 and below the $30/boe level guided
at the start of the year. This reduced
rate incorporates a significant benefit
($3/boe compared to 2015) relating to
movements in the US$:GBP exchange rate,
as underlying costs are primarily incurred
in pounds sterling.
DD&A
The unit DD&A rate for the period decreased
to $21/boe (2015: $27/boe), resulting
in a total DD&A expense for the period
of $70.5 million (2015: $120.2 million).
This reduction in expense was due to a
combination of lower production and impairment
write downs booked in Q4 2015 as a result
of the change in the oil price environment,
which also lowered average DD&A/boe rates.
MOVEMENT IN INVENTORY
An oil and gas inventory movement of $2.8
million was credited to cost of sales
in 2016 (2015: charge of $6.0 million).
This credit arose primarily as a result
of an increase in inventory value arising
from the increase in underlying Brent
prices between the end of 2015 and 2016,
partially offset by an overlift in the
year.
In 2016 less barrels of oil were produced
(3,103 kbbls) than sold (3,188 kbbls),
predominantly due to the lifting of the
historic build-up of inventory on the
Cook field, partly offset by production
exceeding liftings on the Pierce field.
Movement in Oil Gas Total
Operating kbbls kboe kboe
Oil & Gas Inventory
Opening inventory 472 (3) 469
Production 3,103 304 3,407
Liftings/sales (3,188) (304) (3,492)
Transfers/other (3) - (3)
Closing volumes 384 (3) 381
ADMINISTRATION EXPENSES AND EXPLORATION
& EVALUATION EXPENSES
-------------------------------------------------
$'000 2016 2015
General & Administration
("G&A") 4,683 9,763
Share Based Payments
("SBP") 697 172
Total Administration
Expenses 5,380 9,935
Exploration &
Evaluation ("E&E")
Administration write off 770 30,522
expenses reduced
through on-going ADMINISTRATION EXPENSES
cost saving Total administration expenses were reduced
measures by 46% to $5.4 million in 2016 (2015:
$9.9 million). This was largely attributable
to the cost savings initiatives that have
been implemented within the lower oil
price environment, as well as the absence
of Norwegian expenses following the sale
of Norwegian operations in July 2015.
Costs incurred in the year reflect further
reductions in contractor rates and a decrease
in both employee and contractor numbers
from 2015.
E&E EXPENSES
A minor write off of E&E assets was made
in the year relating to non-commercial
prospects. The 2015 write off relates
primarily to the drilling of the unsuccessful
Snømus exploration well in Norway,
the costs for which were paid for by MOL
Plc as part of the divestment of the Norwegian
business during that year.
FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS
------------------------------------------------------
$'000 2016 2015
Gain / (Loss) on Foreign
Exchange 4,319 (1,670)
---------------------------- ---------- ---------
Total Gain/(Loss) on
Foreign Exchange 4,319 (1,670)
---------------------------- ---------- ---------
Revaluation of Commodity
Hedges (119,248) (23,338)
Revaluation of Other
Instruments (32) 736
Total Revaluation (Loss) (119,280) (22,602)
---------------------------- ---------- ---------
Realised Gain on Commodity
Hedges 87,908 176,773
Realised (Loss)/Gain
on Other Instruments (9,044) 1,155
Total Realised Gain 78,864 177,928
---------------------------- ---------- ---------
Total Foreign Exchange
& Financial Instruments (36,097) 153,656
---------------------------- ---------- ---------
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 2016, a foreign exchange gain of $4.3
million was recorded (2015: $1.7 million
loss). This was driven by the GBP:USD
exchange rate moving from 1.48 at 1 January
2016 to 1.23 at 31 December 2016, with
fluctuations throughout the year of between
1.22 and 1.48.
FINANCIAL INSTRUMENTS
The Company recorded an overall loss of
$40.4 million on financial instruments
for the year ended 31 December 2016 (2015:
$155.0 million gain).
A $78.9 million realised gain was made
in 2016. This comprised a $48.9 million
gain on oil hedges maturing during the
year (at an average exercise price of
$64/bbl compared to an average Brent price
of $44/bbl) and an $39.0 million gain
on gas hedges (at an average price of
62p/therm compared to an average NBP price
of 34p/therm), partially offset by a $8.8
million loss on foreign exchange and interest
rate instruments. The total realised gain
of $78.9 million in the period was offset
by a $119.3 million negative revaluation
of instruments as at 31 December 2016.
This resulted from a negative revaluation
of oil hedges of $65.1 million and gas
hedges of $54.2 million. This fair value
accounting for financial instruments by
its nature leads to volatility in the
results due to the impact of revaluing
the financial instruments at the end of
each reporting period.
The $65.1 million negative revaluation
of oil hedges was due to the realisation
of hedged oil volumes during the year
(i.e. the transfer of previously unrealised
gains to realised gain), combined with
a downward revaluation of the remaining
oil hedges at year end 2016 due to a strengthening
of the oil forward curve. The $54.2 million
negative revaluation of gas hedges arises
in the same way, being a combination of
realisations during the year and a negative
revaluation of the remaining gas hedges
at the year end due to a small increase
in the gas forward curve.
As of 31 December 2016, the Company's
commodity hedges were valued at $7.2 million,
$3.6 million for oil hedges and $3.6 million
for gas hedges, based on valuations relative
to the respective oil and gas forward
curves.
FINANCE COSTS
------------------------------------------------------
$'000 2016 2015
Reducing finance Bank interest and
cost profile charges (4,157) (7,384)
driven by Senior notes interest (15,319) (15,009)
decreasing Finance lease interest (994) (1,048)
net debt Non-operated asset
finance fees (32) (71)
Prepayment interest (2,719) (2,059)
Loan fee amortisation (4,159) (5,591)
Accretion (9,215) (9,092)
Total Finance
Costs (36,596) (40,254)
Finance costs decreased to $36.6 million
in 2016 (2015: $40.3 million). This reduction
is primarily attributable to the decrease
in RBL bank interest resulting from the
deleveraging of the business over the
last eighteen months, with drawn bank
debt having fallen from $377 million at
31 December 2015 to $325 million at 31
December 2016. All other finance costs
have remained relatively stable year on
year.
TAXATION
----------------------------------------------------
No UK tax $'000 2016 2015
anticipated UK & Norway Corporation
to be payable Tax - excluding
within the Rate Changes 87,818 248,226
next 5 years Impact of Change
in Tax Rates (57,961) (40,291)
Petroleum Revenue
Tax - (2,523)
Total Taxation 29,857 205,412
A tax credit of $29.9 million was recognised
in the year ended 31 December 2016 (2015:
$205.4 million credit). This comprises
a charge relating to rate changes of $58.0
million offset by a credit of $87.8 million.
Significant components of the $87.8 million
Corporation Tax ("CT") credit include
a $44.7 million credit relating to the
UK Ring Fence Expenditure Supplement and
$25.7 million in respect of additional
capital allowances recognised in relation
to Stella for expenditure incurred by
Ithaca but paid by Petrofac. The tax benefit
of these capital 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 Stella
first oil of a sum calculated at the prevailing
tax rate applied to the relevant capital
allowances, in accordance with the SPA.
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 December
2016 of $95.0million reflecting the expected
future benefit of these additional capital
allowances.
The rate change related charge of $58.0
million comprises the impact of rate changes
on CT of $82.1 million offset by a credit
of $24.2 million relating to PRT.
It was announced in the UK Budget on 16
March 2016 that Petroleum Revenue Tax
("PRT") was effectively abolished from
1 January 2016 with the introduction of
a 0% rate. This eliminated the Company's
future PRT tax charge from 1 January 2016.
The PRT rate change has been enacted and
therefore the deferred PRT provision was
fully released through the Q1 2016 results
giving rise to a credit of $24.2 million.
Further, it was also announced in the
UK Budget that the SCT rate would be reduced
from 20% to 10% with effect from 1 January
2016. This will reduce the Company's future
SCT charge accordingly. The impact of
the 10% reduction in the Supplementary
Charge was to reduce the net deferred
tax assets by $70.9 million, coupled with
the CT impact of the PRT rate change of
$11.2 million, giving an overall rate
change driven CT charge for 2016 of $82.1million.
Note that the 2015 comparative contains
a charge of $40.3 million relating to
the previous changes in the SCT and PRT
rates enacted in Q1 2015.
CAPITAL INVESTMENTS
===========================================================================
2016 capital $'000 Additions
investment YTD
programme 2016
primarily Development & Production
focused on ("D&P") 59,871
GSA development Exploration & Evaluation
activities ("E&E") 15,363
Other Fixed Assets 5
Total 75,239
Capital additions in 2016 totalled $75.2
million, with the major component being
additions to development and production
("D&P") assets.
Excluding capitalised interest costs,
non-cash additions relating to decommissioning
and Vorlich licence acquisition costs
paid at completion of the various transactions,
capital expenditure was approximately
$63 million. This mainly related to activities
on the GSA, including work carried out
on the oil export pipeline committed to
post issuance of original guidance of
$50 million. As previously advised, although
the majority of the oil export pipeline
work was carried out in 2016 it will only
become cash spend in the first half of
2017.
WORKING CAPITAL
---------------------------------------------------------------------------
$'000 31 Dec. 31 Dec. Increase
2016 2015 / (Decrease)
Cash & Cash Equivalents 27,199 11,543 15,656
Trade & Other Receivables 158,579 223,749 (65,170)
Inventory 27,729 20,900 6,829
Derivative Financial
Instruments (current) 7,183 126,887 (119,704)
Trade & Other Payables (236,928) (275,907) 38,979
Net Working Capital* (16,238) 107,172 (123,410)
*Working capital being total current assets
less trade and other payables
As at 31 December 2016 Ithaca had a net
working capital credit balance of $16.2
million, including an unrestricted cash
balance of $27.2 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 decreased over
the twelve month period to 31 December
2016 mainly as a result of a reduction
in the commodity hedging instrument asset
values of $119.7 million noted above.
The cash realised from the commodity hedges
has been used to reduce debt.
CAPITAL RESOURCES
-------------------------------------------------------------
DEBT FACILITIES
Over $110 As at 31 December 2016 the Company has
million funding bank debt facilities totalling $535 million
headroom at ($475 million senior RBL Facility and
31 December $60 million junior RBL), both with a maturity
2016 with of September 2018, following the voluntary
net debt reduced reduction in the size of the facilities
to $598 million from a total of $650 million during the
year. Following the completion of the
October 2016 RBL redetermination process,
the debt capacity of these facilities
was set at over $410 million. When combined
with the $300 million senior unsecured
notes, due July 2019, the Company has
funding headroom of over $110 million
as at 31 December 2016.
The Company's debt facilities are expected
to be sufficient to ensure that adequate
financial resources are available to cover
anticipated future commitments when combined
with existing cash balances and forecast
cashflow from operations. As noted above,
the bank debt facilities are subject to
semi-annual redeterminations of available
debt capacity using forward looking assumptions,
of which future oil and gas prices are
a key component. Movements in forecast
commodity prices can therefore have a
significant impact on available debt capacity
and limit the Company's ability to borrow.
The Company was in compliance with all
its relevant financial and operating covenants
during the quarter. The key covenants
in the senior and junior RBL facilities,
which are available on the Company's SEDAR
profile at www.sedar.com, are:
* A corporate cashflow projection showing total sources
of funds must exceed total forecast uses of funds for
the later of the following 12 months or until
forecast first oil from the Stella field.
* The ratio of the net present value of cashflows
secured under the RBL for the economic life of the
fields to the amount drawn under the facility must
not fall below 1.15:1.
* The ratio of the net present value of cashflows
secured under the RBL for the life of the debt
facility to the amount drawn under the facility must
not fall below 1.05:1.
There are no financial maintenance covenant
tests associated with the senior notes.
Further cash 2016 CASHFLOW MOVEMENTS
inflow and During the twelve months ended 31 December
reduction 2016 there was a cash inflow from operating,
in net debt investing and financing activities of
delivered approximately $15.7 million (2015 outflow
in 2016 of $7.8 million).
Cashflow from operations
Cash generated from operations was $146.8
million. Revenues from the producing asset
portfolio were bolstered by the substantial
hedging programme in place, while operating
costs reduced by 27% period on period.
Cashflow from financing activities
Cash used in financing activities was
$59.8 million, being primarily repayments
of the debt facilities during the period
combined with interest and bank charges
on the RBL and Senior Notes.
Cashflow from investing activities
Cash used in investing activities was
$95.5 million, primarily associated with
further capital expenditure on the GSA
development (including capitalised interest).
COMMITMENTS
-------------------------------------------------
$'000 1 Year 2-5 5+ Years
Years
Office Leases 216 30 -
Licence Fees 488 - -
Engineering 13,020 - -
Rig Commitments 5,404
Total 19,128 30 -
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 forthcoming
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.
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 first production
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 first production 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 December
2016.
COMMODITIES
The following table summarises the commodity
hedges in place at 31 December 2016.
Derivative Term Volume Average
bbl Price
$/bbl
January 2017
Oil Swaps - June 2017 632,040 69*
January 2017
Oil Puts - June 2018 1,891,600 54
January 2017
Oil Collars - June 2018 1,000,007 47 -60*
Derivative Term Volume Average
Therms Price
p/therm
January 2017
Gas Puts - June 2017 36,200,000 62
January 2017
Gas Swaps - March 2017 1,501,537 47
* Hedged with an average floor price of
$46.50/bbl and a celling price of $60/bbl.
Q4 2016 FINANCIAL RESULTS
--------------------------------------------------
Average realised oil prices in Q4 2016
were $49/bbl or 9% higher than the corresponding
period in 2015 as a result of a modest
recovery in Brent prices. While this increase
in oil price had an impact on sales revenue,
the increase from $35.3 million in Q4
2015 to $41.3 million in Q4 2016 was also
attributable to an increase in sales volumes.
Sales volumes increased in the period
primarily due to the timing of Cook liftings
partly offset by reduced liftings from
the Dons fields due to the Brent System
shutdown in Q4 2016.
Gas volumes, which accounted for only
approximately 3% of total revenue in the
period, were up over 30% on the same period
in 2015, although this was partly offset
by slightly lower realised prices ($16/boe
in Q4 2016 compared to $19/boe in Q4 2015).
Cost of sales decreased to $31.1 million
in Q4 2016 (Q4 2015: $47.4 million) with
significant reductions in operating costs
and DD&A, offset by movements in oil and
gas inventory.
The main drivers behind the decrease in
operating costs from $23.1 million in
Q4 2015 to $17.1 million in Q4 2016 were
a combination of supply chain cost reductions
across the portfolio coupled with reduced
production and therefore lower absolute
tariff costs. The above resulted in Q4
2016 operating costs of $22/boe compared
to $24/boe in Q4 2015.
DD&A decreased significantly from $27.0
million in Q4 2015 to $11.4 million in
Q4 2016. This reduction was mainly attributable
to the impairment write downs booked at
the end of 2015 as a consequence of the
change in oil price environment, coupled
with a change in field mix, with production
primarily coming from the Cook, Pierce
and Wytch Farm assets in Q4 2016. The
blended rate for the quarter decreased
from $26/boe in Q4 2015 to $15/boe in
Q4 2016.
Movement in inventory was a charge of
$2.6 million compared to a credit of $2.4
million in Q4 2015. As noted above, movements
in oil inventory arise due to differences
between barrels produced and sold combined
with changes in the valuation of the barrels
held as inventory. In Q4 2016 fewer barrels
of oil were produced (693kbbl) than sold
(814kbbl), mainly as a result of the timing
of Cook field liftings, partially mitigated
by the Pierce field liftings. This overlift
was partly offset by the increase in value
of oil inventory over the quarter as a
result of the modest recovery in oil price.
In Q4 2015 an excess of production volumes
over sales volumes was partially offset
by a significant reduction in the valuation
of oil inventory to produce a credit of
$2.4 million.
QUARTERLY RESULTS SUMMARY
----------------------------------------------------------------------------------------------------------
$'000 31 30 30 31 31 30 30 31
Dec Sep Jun Mar Dec Sep Jun Mar
2016 2016 2016 2016 2015 2015 2015 2015
Revenue 41,346 44,585 24,511 33,250 35,340 42,108 59,152 70,375
(Loss)/Profit
Before
Tax (16,256) (6,798) (44,081) (16,521) (363,562) 55,540 (26,826) 8,431
Profit/(Loss)
After
Tax 10,648 (70,694) (11,466) 17,712 (177,625) 42,812 39,888 (26,078)
Earnings
per share
"EPS"
- Basic(1) 0.26 (0.17) (0.03) 0.04 (0.35) 0.13 0.12 (0.08)
EPS -
Diluted(1) 0.25 (0.17) (0.03) 0.04 (0.35) 0.13 0.12 (0.08)
Common
shares
outstanding
(000) 413,099 411,784 411,784 411,384 411,384 329,519 329,519 329,519
--------------- --------- --------- --------- --------- ---------- -------- --------- ---------
(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 2014 and 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 December 2016 Ithaca had 413,099,042
common shares outstanding along with 24,413,139
options outstanding to employees and directors
to acquire common shares.
31 December
2016
Common Shares Outstanding 413,099,042
Share Price((1) $1.25 /
Share
Total Market Capitalisation $516,373,803
(1) Represents the TSX close price (CAD$1.69)
on 31 December 2016. US$:CAD$ 0.74 on
31 December 2016
Following the exercise of share options
in the first quarter of the year, the
number of common shares outstanding as
of 23 March is 415,049,036.
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 December 2016, and
concluded that such disclosure controls
and procedures are effective to ensure
that information required to be disclosed
by the Company in its annual filings,
interim filings and other reports filed
or submitted under securities legislation
is recorded, processed, summarised and
reported within the time periods specified
in the securities legislation and such
information is accumulated and communicated
to the Company's management, including
its certifying officers, as appropriate
to allow timely decisions regarding required
disclosures.
The Chief Executive Officer and Chief
Financial Officer have designed, or have
caused such internal controls over financial
reporting to be designed under their supervision,
to provide reasonable assurance regarding
the reliability of financial reporting
and preparation of the Company's financial
statements for external purposes in accordance
with IFRS including those policies and
procedures that:
(a) pertain to the maintenance of records
that in reasonable detail accurately and
fairly reflect the transactions and dispositions
of the Company's assets;
(b) are designed to provide reasonable
assurance that transactions are recorded
as necessary to permit preparation of
financial statements in accordance with
IFRS, and that receipts and expenditures
of the Company are being made only in
accordance with authorisations of management
and directors of the Company; and
(c) are designed to provide reasonable
assurance regarding prevention or timely
detection of unauthorised acquisition,
use or disposition of the Company's assets
that could have a material effect on the
annual financial statements or interim
financial statements.
The Chief Executive Officer and Chief
Financial Officer performed an assessment
of internal control over financial reporting
as at 31 December 2016, based on the criteria
established in Internal Control - Integrated
Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway
Commission ("COSO"), and concluded that
internal control over financial reporting
is effective with no material weaknesses
identified.
Based on their inherent limitations, disclosure
controls and procedures and internal controls
over financial reporting may not prevent
or detect misstatements and even those
options determined to be effective can
provide only reasonable assurance with
respect to financial statement preparation
and presentation.
As of 31 December 2016, there were no
changes in the Company's internal control
over financial reporting that occurred
during the year ended 31 December 2016
that have materially affected, or are
reasonably likely to materially affect,
our internal control over financial reporting.
CHANGES IN ACCOUNTING POLICIES
---------------------------------------------------
New and amended standards and interpretations
need to be adopted in the first financial
statements issued after their effective
date (or date of early adoption). There
are no new IFRSs of IFRICs that are effective
for the first time for this period that
would be expected to have a material impact
on the Company.
ADDITIONAL INFORMATION
---------------------------------------------------
Non-IFRS Measures "Cashflow from operations" and "cashflow
per share" referred to in this MD&A are
not prescribed by IFRS. These non-IFRS
financial measures do not have any standardised
meanings and therefore are unlikely to
be comparable to similar measures presented
by other companies. The Company uses these
measures to help evaluate its performance.
As an indicator of the Company's performance,
cashflow from operations should not be
considered as an alternative to, or more
meaningful than, net cash from operating
activities as determined in accordance
with IFRS. The Company considers cashflow
from operations to be a key measure as
it demonstrates the Company's underlying
ability to generate the cash necessary
to fund operations and support activities
related to its major assets. Cashflow
from operations is determined by adding
back changes in non-cash operating working
capital to cash from operating activities.
"Net working capital" referred to in this
MD&A is not prescribed by IFRS. Net working
capital includes total current assets
less trade & other payables. Net working
capital may not be comparable to other
similarly titled measures of other companies,
and accordingly Net working capital may
not be comparable to measures used by
other companies.
"Net debt" referred to in this MD&A is
not prescribed by IFRS. The Company uses
net drawn debt as a measure to assess
its financial position. Net drawn debt
includes amounts outstanding under the
Company's debt facilities and senior notes,
less cash and cash equivalents.
---------------------------------------------------
Off Balance 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 December 2016, finance lease assets
of $28.5 million and related liabilities
of $30.2 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 2016 was $0.2 million (2015: $0.2
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 December 2016 the Company had
loans receivable from FPF-1 Limited and
FPU Services Limited, associates of the
Company, for $59.9 million and $0.0 million,
respectively (31 December 2015: $60.8
million and $0.2 million, respectively)
as a result of the completion of the GSA
transactions.
---------------------------------------------------
BOE Presentation The calculation of boe is based on a conversion
rate of six thousand cubic feet of natural
gas ("mcf") to one barrel of crude oil
("bbl"). The term boe may be misleading,
particularly if used in isolation. A boe
conversion ratio of 6 mcf: 1 bbl is based
on an energy equivalency conversion method
primarily applicable at the burner tip
and does not represent a value equivalency
at the wellhead. Given the value ratio
based on the current price of crude oil
as compared to natural gas is significantly
different from the energy equivalency
of 6 mcf: 1 bbl, utilising a conversion
ratio at 6 mcf: 1 bbl may be misleading
as an indication of value.
---------------------------------------------------
Reserves The estimates of reserves stated herein
for individual properties may not reflect
the same confidence level as estimates
of reserves for all properties, due to
the effects of aggregation.
The Company's total net proved and probable
reserves at 31 December 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;
-- Delek's ability to complete the Offer;
* 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 22 March 2017. The 2016 results
have been compared to the results of 2015.
This MD&A should be read in conjunction
with the Company's audited consolidated
financial statements as at 31 December
2016 and 2015 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.
----------------------------------------------------------------
General Information
Directors
Brad Hurtubise Chairman)
Les Thomas (Chief Executive)
Jay Zammit
Ron Brenneman
Alec Carstairs
Joseph Asaf Bartfeld
Yosef Abu
Jack Lee (resigned 23 June 2016)
Frank Wormsbecker (resigned 23 June 2016)
Company Secretary
Pinsent Masons Secretarial Limited
1 Park Row
Leeds
LS1 5AB
Independent Auditors
PricewaterhouseCoopers LLP
Chartered Accountants and Statutory Auditors
431 Union Street
Aberdeen
AB11 6DA
Bankers
BNP Paribas
London Office
40 Harewood Avenue
London
NW1 6AA
Solicitors
Pinsent Masons
13 Queen's Road
Aberdeen
AB15 4YL
Registered Office
1600, 333 - 7th Avenue S.W.
Calgary
Alberta
Canada
T2P 2Z1
Independent Auditors' Report
To the Shareholders of Ithaca Energy Inc. We have audited the accompanying consolidated financial statements of Ithaca Energy Inc. and its subsidiaries, which comprise the consolidated Statement of Financial Position as at 31 December 2016 and 31 December 2015, the Consolidated Statement of Income, the Consolidated Statement of Changes in Equity and Consolidated Statement of Cash Flow for the years then ended, and the related notes, which comprise a summary of significant accounting policies and other explanatory information. Management's responsibility for the consolidated financial statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. Auditor's responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the
entity's internal control. An audit also includes
evaluating the appropriateness of accounting policies
used and the reasonableness of accounting estimates
made by management, as well as evaluating the overall
presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained
in our audits is sufficient and appropriate to
provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements
present fairly, in all material respects, the financial
position of Ithaca Energy Inc. and its subsidiaries
as at 31 December 2016 and 31 December 2015 and
their financial performance and their cash flows
for the years then ended in accordance with International
Financial Reporting Standards.
Chartered Accountants
"PricewaterhouseCoopers LLP"
-------------------------------------------------------------------------------
PricewaterhouseCoopers
LLP
431 Union
Street
Aberdeen
AB11 6DA
22 March
2017
Consolidated Statement
of Income
For the year ended 31
December 2016
2016 2015
Note US$'000 US$'000
------------------------------------------------ ------- ---------- --------------
Revenue 5 143,691 206,975
Operating
costs (78,219) (106,468)
Movement in oil and
gas inventory (6,030) (14,640)
Depletion, depreciation
and amortisation (120,230) (167,378)
----------------------------------------------------- ------- ---------- --------------
Cost of
sales (145,936) (232,728)
Gross
Loss (2,245) (25,753)
Exploration and evaluation
expenses 10 (770) (30,522)
Gain on asset disposal 2,913 26,600
(Loss) / Gain on financial
instruments 27 (40,416) 155,326
Impairment of oil
& gas assets 13 (5,543) (386,679)
Impairment of goodwill 12 - (13,604)
Total administrative
expenses 6 (5,380) (9,935)
Foreign exchange 4,319 (1,670)
Finance costs 7 (36,596) (40,254)
Interest income 62 74
---------------------------------------------------- ------- ---------- --------------
Loss Before Tax (83,656) (326,417)
Taxation 25 29,857 205,412
------------------------------------------------- ------- ---------- --------------
Loss for the
year (59,799) (121,005)
Earnings per share
(US$ per share)
Basic 24 (0.13) (0.35)
Diluted 24 (0.13) (0.35)
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 8 to 26
are an integral part of the financial statements.
Consolidated Statement
of Financial Position
as at 31 December
2016
2016 2015
Note US$'000 US$'000
----------------------------- ------- -------------------- -------------------------
ASSETS
Current assets
Cash and cash equivalents 27,199 11,543
Accounts receivable 8 157,912 223,006
Deposits, prepaid
expenses and other 667 743
Inventory 9 27,729 20,900
Derivative financial
instruments 28 11,512 126,887
----------------------------- ------- -------------------- -------------------------
225,019 383,079
Non-current assets
Long-term receivable 30 59,922 61,052
Long-term inventory 9 8,438 7,908
Investment in associate 14 18,337 18,337
Exploration and evaluation
assets 10 27,075 11,223
Property, plant &
equipment 11 1,084,599 1,102,046
Deferred tax assets 25 383,663 355,726
Goodwill 12 123,510 123,510
----------------------------- ------- -------------------- -------------------------
1,705,544 1,679,802
Total assets 1,930,563 2,062,881
LIABILITIES AND EQUITY
Current liabilities
Trade and other payables 16 (236,928) (275,907)
Exploration obligations 17 - (4,000)
Contingent consideration 21 (4,000) (4,000)
Derivative financial
instruments 28 (4,329) -
(245,257) (283,907)
Non-current liabilities
Borrowings 15 (618,566) (666,130)
Decommissioning liabilities 18 (206,933) (226,915)
Other long term liabilities 19 (107,428) (92,543)
Contingent consideration 21 (8,650) -
Derivative financial
instruments 28 - (197)
----------------------------- ------- -------------------- -------------------------
(941,577) (985,785)
Net Assets 743,729 793,189
----------------------------- ------- -------------------- -------------------------
Equity
Share capital 22 619,207 617,375
Share based payment
reserve 23 25,185 22,678
Retained earnings 22 99,337 153,136
Total Equity 743,729 793,189
----------------------------- ------- -------------------- -------------------------
The financial statements were approved by the Board of Directors on 22 March
2017 and signed on its behalf by:
"Les Thomas"
-----------------------------
Director
"Alec Carstairs"
-----------------------------
Director
The accompanying notes on pages 8 to 26 are an integral part of the financial statements.
Consolidated Statement of Changes in Equity
For the year ended 31
December 2016
Share Share Retained Total
capital based earnings Equity
payment
reserve
US$'000 US$'000 US$'000 US$'000
---------------------- --------------------- ------------------- ------------------- ----------
Balance, 1 Jan
2015 551,632 19,234 274,141 845,007
Share based payment - 3,444 - 3,444
Shares issued 65,743 - - 65,743
Loss for the year - - (121,005) (121,005)
---------------------- --------------------- ------------------- ------------------- ----------
Balance, 31 December
2015 617,375 22,678 153,136 793,189
---------------------- --------------------- ------------------- ------------------- ----------
Balance, 1 Jan
2016 617,375 22,678 153,136 793,189
Share based payment - 3,058 - 3,058
Shares issued 1,832 (551) - 1,281
Loss for the year - - (53,799) (53,799)
Balance, 31 December
2016 619,207 25,185 99,337 743,729 ---------------------- --------------------- ------------------- ------------------- ----------
The accompanying notes on pages 8 to 26 are an integral part of the financial statements.
Consolidated Statement of Cash Flow
For the year ended 31 December 2016
2016 2015
Note US$'000 US$'000
--- ---------------------------- ----- --------- ----------
CASH PROVIDED BY / (USED IN):
Operating
activities
Loss Before
Tax (83,656) (326,417)
Adjustments
for:
Depletion, depreciation and
amortisation 11 70,521 120,230
Exploration and evaluation
expenses 10 770 30,522
Impairment of oil & gas assets 13 5,543 386,679
Impairment of goodwill 12 - 13,604
Onerous contracts - (21,080)
Share based payment 697 172
Loan fee amortisation 7 4,159 5,591
Revaluation of financial
instruments 27 119,281 22,602
Gain on disposal (2,913) (26,600)
Accretion on decommissioning
provisions 7 9,215 9,092
Bank interest & charges 23,221 25,571
----- --------- ----------
Cash flow generated from operations 146,838 239,966
------------------------------------------ ----- --------- ----------
Changes in inventory, debtors and
creditors relating to operating
activities 4,242 (19,987)
Petroleum Revenue Tax (paid) (916) (4,446)
Corporation Tax refunded 6,009 -
Net cash generated from
operating activities 156,173 215,533
------------------------------------- --- ----- --------- ----------
Investing
activities
Capital expenditure (92,594) (164,789)
Loan to associate 1,340 (2,504)
Decommissioning (4,229) -
Proceeds on
disposal - 32,521
Changes in debtors and creditors
relating to investing activities 15,436 (33,317)
Net cash used in
investing activities (80,047) (168,089)
------------------------------------ --- ----- --------- ----------
Financing
activities
Proceeds from issuance of
shares 1,832 66,086
Share issue costs - (344)
Loan (repayment) 15 (51,875) (81,312)
Bank interest & charges (9,802) (38,510)
----------------------------------------- ----- --------- ----------
Net cash used in financing
activities (59,845) (54,080)
------------------------------------- --- ----- --------- ----------
Currency translation differences
relating to cash & cash equivalents (625) (1,202)
Increase/(Decrease) in cash
& cash equivalents 15,656 (7,7838)
------------------------------------------ ----- --------- ----------
Cash and cash equivalents,
beginning of year 11,543 19,381
Cash and cash equivalents,
end of year 27,199 11,543
------------------------------------- --- ----- --------- ----------
The accompanying notes on pages 8 to 26 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".
The consolidated financial statements of Ithaca
Energy Inc. for the year ended 31 December 2016
were authorised for issue in accordance with a
resolution of the directors on 22 March 2017.
2. BASIS OF PREPARATION
The Corporation prepares its financial statements
in accordance with International Financial Reporting
Standards (IFRS) as issued by the International
Accounting Standards Board (IASB) and in accordance
with IFRS Interpretations Committee (IFRS IC) interpretations.
The consolidated financial statements have been
prepared on a going concern basis using the historical
cost convention, except for financial instruments
which are measured at fair value.
The consolidated financial statements are presented
in US dollars and all values are rounded to the
nearest thousand (US$'000), except when otherwise
indicated.
SIGNIFICANT ACCOUNTING POLICIES, JUDGEMENTS
3. AND ESTIMATION UNCERTAINTY
Basis of measurement
The consolidated financial statements have been
prepared under the historical cost convention,
except for the revaluation of certain financial
assets and financial liabilities (under IFRS) to
fair value, including derivative instruments.
Basis of consolidation
The consolidated financial statements of the Corporation
include the financial statements of Ithaca Energy
Inc. and all wholly-owned subsidiaries as listed
per note 30. 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 22 (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 27 to 29.
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.
Onerous Contracts
Onerous contract provisions are recognised where
the unavoidable costs of meeting the obligations
under a contract exceed the economic benefits
expected to be received under it.
Contingent consideration
Contingent consideration is accounted for as a
financial liability and measured at fair value
at the date of acquisition with any subsequent
remeasurements recognised either in 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
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). Amendments have been made to
the following standards effective 1 January 2016.
These amendments have not had a material impact
on the Group's financial statements.
- IFRS 11 'Joint arrangements'
- IAS 16 'Property, plant and equipment'
- IAS 38 'Intangible assets'
- IAS 27 'Separate financial statements'
- IFRS 10 'Consolidated financial statements'
- IAS 1 'Presentation of financial statements'
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
2016 2015
US$'000 US$'000
------------------ ------------------- ---------
Oil sales 138,749 201,055
Gas sales 4,269 4,965
Condensate sales 496 498
Other income 177 457
-------------------- ------------------- ---------
143,691 206,975
6. ADMINISTRATIVE EXPENSES
2016 2015
US$'000 US$'000
-------------------------- --------- ---------
General & administrative (4,683) (9,763)
Share based payment (697) (172)
---------------------------- --------- ---------
(5,380) (9,935)
2016 2015
Employee benefit expense US$'000 US$'000
---------------------------- --------- ---------
Wages and salaries (3,373) (7,821)
Social security costs (4,088) (4,793)
Share options (3,058) (3,444)
Pension costs (706) (1,141)
------------------------------ --------- ---------
(11,225) (17,199)
Staff costs above are recharged to joint venture partners or capitalised to the extent that they are directly attributable to capital projects.
7. FINANCE COSTS
2016 2015
US$'000 US$'000
--------------------------- --------- ---------
Bank charges and interest (4,157) (7,384)
Senior notes interest (15,319) (15,009)
Finance lease interest (994) (1,048)
Non-operated asset
finance fees (33) (71)
Prepayment interest (2,719) (2,059)
Loan fee amortisation (4,159) (5,591)
Accretion (9,215) (9,092)
----------------------------- --------- ---------
(36,596) (40,254)
8. ACCOUNTS RECEIVABLE
2016 2015
US$'000 US$'000
---------------- --------- ---------
Trade debtors 146,190 222,010
Accrued income 11,722 996
------------------ --------- ---------
157,912 223,006
9. INVENTORY
2016 2015
Current US$'000 US$'000
--------------------- --------- ---------
Crude oil inventory 25,868 18,721
Materials inventory 1,861 2,179
--------------------- --------- ---------
27,729 20,900
2016 2015
Non-current US$'000 US$'000
--------------------- --------- ---------
Crude oil inventory 8,438 7,908
The non-current portion of inventory relates to long term stocks at the Sullom Voe Terminal.
10. EXPLORATION AND EVALUATION ASSETS
US$'000
------------------------------------ ---------
At 1 January 2015 89,944
Additions 30,263
Disposals (44,005)
Release of exploration obligations (1,431)
Write offs/relinquishments (30,522)
Impairment (32,926)
------------------------------------ ---------
At 31 December 2015 and 1 January
2016 11,223
Additions 15,363
Write offs/relinquishments (770)
Impairment (note 13) 1,259
------------------------------------ ---------
At 31 December 2016 27,075
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 $0.8 million being expensed in the year to 31 December 2016.
11. PROPERY, PLANT AND EQUIPMENT
Development
& Production
Oil and Gas Other fixed
Assets assets Total
US$'000 US$'000 US$'000
Cost
At 1 January 2015 2,341,069 4,140 2,345,209
Additions 141,318 717 142,035
Disposals - (1,451) (1,451)
Release of onerous
contract provision (377) - (377)
At 31 December 2015
and 1 January 2016 2,482,010 3,406 2,485,416
Additions 59,871 5 59,876
At 31 December 2016 2,541,881 3,411 2,545,292
DD&A and Impairment
At 1 January 2015 (907,305) (2,695) (910,000)
DD&A charge for the
period (119,768) (462) (120,230)
Disposals - 613 613
Impairment charge for
the period (353,753) - (353,753)
At 31 December 2015
and 1 January 2016 (1,380,826) (2,544) (1,383,370)
DD&A charge for the
period (70,250) (271) (70,521)
Impairment charge for
the period (note 13) (6,802) - (6,802)
At 31 December 2016 (1,457,878) (2,815) (1,460,693)
NBV at 1 January 2015 1,433,764 1,445 1,435,209
NBV at 31 December
2015 1,101,184 862 1,102,046
NBV at 31 December
2016 1,084,003 596 1,084,599
The net book amount of property, plant and equipment includes $28.5million (2014: $30.2 million) in respect of the Pierce FPSO lease held under finance lease.
12. GOODWILL
2016 2015
US$'000 US$'000
--------------------------- -------------------- ---------
Opening balance 123,510 137,114
Impairments in the period - (13,604)
--------------------------- -------------------- ---------
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 $13.6 million was recorded relating to goodwill.
Goodwill has been tested for impairment by assessing the recoverable amount of the CGU to which the goodwill relates using the fair value less cost of disposal method. No impairment has been recorded in the year. Subsequent to the year end an offer has been received from Delek Group Ltd (note 32) which places a value on the company assets greater than that recoverable amount which is required to support the carrying value of the goodwill balance. The associated recoverable amount of the offer from Delek is based on a FVLCD approach and is categorised within Level 1 of the fair value hierarchy.
13. IMPAIRMENT
2016 2015
US$'000 US$'000
------------------------------ -------------------- ----------
D&P Assets (6,802) (353,753)
E&E assets 1,259 (32,926)
------------------------------ -------------------- ----------
North Sea oil and gas assets (5,543) (386,679)
Goodwill - (13,604)
------------------------------ -------------------- ----------
Total impairment (5,543) (400,283)
During 2016, the Company recorded a $5.5 million pre-tax impairment charge (2015: $386.7 million) relating to oil and gas assets. The impairment was predominantly driven by the cessation of production from both the Causeway and Topaz fields resulting in the carrying value of these assets being fully written off to nil. Additionally downward revisions to the decommissioning liabilities relating to oil and assets previously written to nil has resulted in a negative impairment of E&E assets.
14. INVESTMENT IN ASSOCIATES
2016 2015
US$'000 US$'000
-------------------------- --------- ---------
Investments in FPF-1 and
FPU services 18,337 18,337
Investment in associates comprises shares, acquired by Ithaca Energy (Holdings) Limited, in FPF-1 Limited and FPU Services Limited as part of the completion of the Greater Stella Area transactions in 2012. There has been no change in value during the period with the above investment reflecting the Company's share of the associates' results.
15. BORROWINGS
2016 2015
US$'000 US$'000
----------------------------- ---------- ----------
RBL facility (324,918) (376,793)
Senior notes (300,000) (300,000)
Long term bank fees 3,666 6,779
Long term senior notes fees 2,686 3,884
------------------------------------- ---------- ----------
(618,566) (666,130)
Extension and amendment to bank debt facilities
The Company's bank debt facilities are sized at $535 million: a $475 million senior RBL and a $60 million junior RBL. Both RBL facilities are based on conventional oil and gas industry borrowing base financing terms, with loan maturities in September 2018, and are available to fund on-going development activities and general corporate purposes. The combined interest rate of the two bank debt facilities, fully drawn, is LIBOR plus 3.4% prior to Stella coming on-stream, stepping down to LIBOR plus 2.9% after Stella production has been established.
The availability to draw upon the facilities is reviewed by the bank syndicate on a semi-annual basis, with the results of the October 2016 redetermination resulting in debt availability of $410 million.
Senior Reserves Based Lending Facility
As at 31 December 2016, the Corporation has a Senior Reserved Based Lending ("Senior RBL") Facility of $475 million. As at 31 December 2016, $324.9 million (31 December 2015: $376.8 million) was drawn down under the Senior RBL. $3.7 million (31 December 2015: $6.8 million) of loan fees relating to the RBL have been capitalised and remain to be amortised.
Junior Reserves Based Lending Facility
As at 31 December 2016, the Corporation had a Junior Reserved Based Lending ("Junior RBL") Facility of $60 million. The facility remains undrawn at the quarter end.
Senior Notes
As at 31 December 2016, the Corporation had $300 million 8.125% senior unsecured notes due July 2019, with interest payable semi-annually. $2.7 million of loan fees (31 December 2015: $3.9 million) have been capitalised and remain to be amortised.
Covenants
The Corporation is subject to financial and operating covenants related to the facilities. Failure to meet the terms of one or more of these covenants may constitute an event of default as defined in the facility agreements, potentially resulting in accelerated repayment of the debt obligations.
The Corporation was in compliance with all its relevant financial and operating covenants during the period.
The key covenants in both the Senior and Junior RBLs are:
- A corporate cashflow projection showing total sources of funds must exceed total forecast uses of funds for the later of the following 12 months or until forecast first oil from the Stella field.
- The ratio of the net present value of cashflows secured under the RBL for the economic life of the fields to the amount drawn under the facility must not fall below 1.15:1
- The ratio of the net present value of cashflows secured under the RBL for the life of the debt facility to the amount drawn under the facility must not fall below 1.05:1.
There are no financial maintenance covenants tests under the senior notes.
Security provided against the facilities
The RBL facilities are secured by the assets of the guarantor members of the Ithaca Group, such security including share pledges, floating charges and/or debentures.
16. TRADE AND OTHER PAYABLES
2016 2015
US$'000 US$'000
------------------------------ ---------- ----------
Trade payables (96,762) (129,719)
Accruals and deferred income (140,166) (146,188)
------------------------------ ---------- ----------
(236,928) (275,907)
17. EXPLORATION OBLIGATIONS
2016 2015
US$'000 US$'000
------------------------- ---------- ---------
Exploration obligations - (4,000)
The above reflects the fair value of E&E commitments assumed as part of the Valiant transaction. As at 31 December 2016, $4 million was released reflecting the Company's decision to relinquish these licences.
18. DECOMMISSIONING LIABILITIES
2016 2015
US$'000 US$'000
------------------------------------ ------------------- --------------------------
Balance, beginning of period (226,915) (213,105)
Additions (2,279) -
Accretion (9,215) (9,092)
Revision to estimates 27,248 (4,718)
Decommissioning provision utilised 4,228 -
Balance, end of period (206,933) (226,915)
The total future decommissioning liability was calculated by management based on its net ownership interest in all wells and facilities, estimated costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. The Corporation uses a risk free rate of 4.0 percent (31 December 2015: 4.0 percent) and an inflation rate of 2.0 percent (31 December 2015: 2.0 percent) over the varying lives of the assets to calculate the present value of the decommissioning liabilities. These costs are expected to be incurred at various intervals over the next 24 years.
The economic life and the timing of the obligations are dependent on Government legislation, commodity price and the future production profiles of the respective production and development facilities.
19. OTHER LONG-TERM LIABILITIES
2016 2015
US$'000 US$'000
---------------------- ---------- --------------------------
Shell prepayment (64,017) (62,227)
BP prepayment (13,212) -
Finance lease (30,199) (30,316)
---------------------- ---------- --------------------------
Balance, end of year (107,428) (92,543)
The prepayment balances relate to cash advances under the Shell oil sales agreement and BP gas sales agreement which have been classified as long-term liabilities as short-term repayment is not due in the current oil price environment. The finance lease relates to the Pierce FPSO acquired as part of the Summit acquisition.
20. FINANCE LEASE LIABILITY
2016 2015
US$'000 US$'000
Total minimum lease payments
Less than 1 year (2,595) (2,602)
Between 1 and 5 years (12,434) (12,570)
5 years and later (21,043) (23,502)
Interest
Less than 1 year (939) (994)
Between 1 and 5 years (3,834) (4,123)
5 years and later (2,919) (3,569)
Present value of minimum lease
payments
Less than 1 year (1,656) (1,608)
Between 1 and 5 years (8,600) (8,447)
5 years and later (18,124) (19,933)
-------------------------------- --------- ---------
The finance lease relates to the Pierce FPSO acquired as part of the Summit acquisition in July 2014.
21. CONTINGENT CONSIDERATION
2016 2015
Current US$'000 US$'000
--------------------- --------- ---------
Balance outstanding (4,000) (4,000)
The current contingent consideration at the end of the year relates to the acquisition of the Stella field and is payable upon first oil.
2016 2015
Non-current US$'000 US$'000
-------------------- --------- ---------
Balance outstanding (8,650) -
The non-current contingent consideration balance at the end of the year relates to the acquisition of the Vorlich and Austen fields based on the probability of certain future criteria being met.
22. SHARE CAPITAL
Number of Amount
Authorised share capital ordinary US$'000
shares
------------------------------------- ----------------- -------------------------
At 31 December 2015 and 31 December Unlimited -
2016
(a) Issued
The issued share capital is
as follows:
Issued Number of Amount
common shares US$'000
------------------------------------- ----------------- -------------------------
Balance 1 January 2016 411,384,045 617,375
Issued for cash - options exercised 1,714,997 1,832
------------------------------------- ----------------- -------------------------
Balance 31 December 2016 413,099,042 619,207
Capital Management
The Corporation's objectives when managing capital are:
-- to safeguard the Corporation's ability to continue as a going concern;
-- to maintain balance sheet strength and optimal capital structure, while ensuring the Corporation's strategic--objectives are met; and
-- to provide an appropriate return to shareholders relative to the risk of the Corporation's underlying assets.
Capital is defined as shareholders' equity and net debt. Shareholders' equity includes share capital, share based payment reserve, warrants issued, retained earnings or deficit and other comprehensive income.
2016 2015
US$'000 US$'000
----------------------------- --------- ---------
Share capital 619,207 617,375
Share based payment reserve 25,185 22,678
Retained earnings 99,337 153,136
----------------------------- --------- ---------
Total Equity 743,729 793,189
----------------------------- --------- ---------
The Corporation maintains and adjusts its capital structure based on changes in economic conditions and the Corporation's planned requirements. The Board of Directors reviews the Corporation's capital structure and monitors requirements. The Corporation may adjust its capital structure by issuing new equity and/or debt, selling and/or acquiring assets, and controlling capital expenditure programs.
The Company assesses its capital structure mainly on a forward-looking basis by modelling net cash flows over the next few years and considering the economic conditions and operational factors which could lead to financial stress. A range of measurement tools is used, including gearing (calculated at year end below), net cash flow coverage of net interest payments, and the time to repay net debt from net cash flow. No specific numerical range for each of these parameters is targeted, as the overall assessment reflects a consideration of a wide range of factors.
2016 2015
US$'000 US$'000
--------------------------------- ---------- ----------
Total borrowings 618,566 666,130
Less: cash and cash equivalents (27,199) (11,543)
Net debt 591,367 654,587
Equity 743,729 793,189
--------------------------------- ---------- ----------
Net debt plus equity 1,335,096 1,482,422
Net debt as a % Net Debt plus
Equity 44% 44%
(b) Stock options
In the year ended 31 December 2016, the Corporation's Board of Directors granted 12,000,000 options at an exercise price of $0.40 (C$0.55).
The Corporation's stock options and exercise prices are denominated in Canadian Dollars when granted. As at 31 December 2016, 24,413,139 stock options to purchase common shares were outstanding, having an exercise price range of $0.40 to $2.51 (C$0.55 to C$2.71) per share and a vesting period of up to 3 years in the future.
Changes to the Corporation's stock options are summarised as follows:
31 December 2016 31 December 2015
---------------------- ------------------------ ---------------------------------------
Wt. Avg Wt. Avg
No. of Exercise No. of Exercise
Options Price* Options Price*
---------------------- ------------ ---------- ------------------ -------------------
Balance, beginning
of year 19,216,206 $1.70 24,232,428 $1.81
Granted 12,000,000 $0.40 950,000 $0.84
Forfeited / expired (5,088,070) $1.81 (5,966,222) $2.05
Exercised (1,714,997) $0.85 - -
---------------------- ------------ ---------- ------------------ -------------------
Options outstanding,
end of year 24,413,139 $1.10 19,216,206 $1.70
---------------------- ------------ ---------- ------------------ -------------------
* The weighted average exercise price has been converted into U.S. dollars based on the foreign exchange rate in effect at the date of issuance.
The following is a summary of stock options as at 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
================= =========== ========= ========== ================ ========== =========== ============
The following is a summary of stock options as at 31 December 2015:
Options Outstanding Options Exercisable
---------------------------------------------------------- ------------------------------------------------------------
Wt. Wt. Wt. Wt.
Range of Avg Avg Range of Avg Avg
Exercise No. of Life Exercise Exercise No. of Life Exercise
Price Options (Years) Price* Price Options (Years) Price*
----------------- ----------- -------------- ---------- ------------------ ---------- ---------------- ----------
$2.28-$2.52
$2.28-$2.52
(C$2.31-C$2.71) 7,326,205 1.9 $2.46 (C$2.31-C$2.71) 2,953,333 1.6 $2.44
$0.84-$2.03
$0.84-$2.03
(C$1.04-C$1.99) 11,890,001 2.4 $1.22 (C$1.04-C$1.99) 5,800,001 1.7 $1.54
----------------- ----------- -------------- ---------- ------------------ ---------- ---------------- ----------
19,216,206 2.2 $1.70 8,753,334 1.7 $1.84
================= =========== ============== ========== ================== ========== ================ ==========
(c) Share based payments
Options granted are accounted for using the fair value method. The compensation cost during the year ended 31 December 2016 for total stock options granted was $3.1 million (2015: $3.4 million). $0.7 million was charged through the income statement for share based payment for the year ended 31 December 2016 (2015: $0.2 million), being the Corporation's share of share based payment chargeable through the income statement. The remainder of the Corporation's share of share based payment has been capitalised. The fair value of each stock option granted was estimated at the date of grant, using the Black-Scholes option pricing model with the following assumptions:
2016 2015 2013 2012
--------------------------- -------- -------- --------
Risk free interest
rate 0.53% 0.65% 1.37% 0.40%
Expected stock volatility 60% 59% 51% 74%
Expected life of options 3 years 3 years 2 years 3 years
Weighted Average Fair
Value C$0.22 $0.43 $0.82 $1.08
23. SHARE BASED PAYMENT RESERVE
2016 2015
US$'000 US$'000
---------------------------- ------------------- ---------
Balance, beginning of year 22,678 19,234
Share based payment cost 3,058 3,444
Transfer to share capital
on exercise of options (551) -
---------------------------- ------------------- ---------
Balance, end of year 25,185 22,678
24. EARNINGS PER SHARE
The calculation of basic earnings per share is based on the profit after tax and the weighted average number of common shares in issue during the period. The calculation of diluted earnings per share is based on the profit after tax and the weighted average number of potential common shares in issue during the year.
2016 2015
------------------------------- ------------ ------------
Weighted av. number of common
shares (basic) 411,643,995 345,667,416
Weighted av. number of common
shares (diluted) 412,077,353 345,667,416
25. TAXATION
2016 2015
US$'000 US$'000
------------------------------------------ -------------------- ----------
Current tax
Corporation tax - 30,873
Petroleum revenue tax 1,920 (4,839)
------------------------------------------ -------------------- ----------
Total current credit 1,920 26,034
Deferred tax
Corporation tax 5,702 (166,540)
Petroleum revenue tax 22,235 (12,839)
------------------------------------------ -------------------- ----------
Total deferred credit 27,937 (179,379)
Total tax credit 29,857 (205,413)
CORPORATION TAX 2016 2015
US$'000 US$'000
------------------------------------------ -------------------- ----------
Current tax
Current tax on profits for the year - (18,580) Adjustment in respect of prior periods - (12,293) Deferred tax Relating to the origination and reversal of temporary differences 111,042 220,046 Relating to changes in tax rates (82,116) (50,854) Adjustment in respect of prior periods (23,224) (2,652) ------------------------------------------ -------------------- ---------- Total tax credit 5,702 197,413
The tax on the group's profit before tax differs from the theoretical amount that would arise using the effective rate of tax applicable for UK ring fence oil and gas activities as follows:
2016 2015
US$'000 US$'000
----------------------------------------------- -------------------- ----------
Accounting loss before tax (83,656) (326,417)
At tax rate of 40% (2015: 50%) (33,462) (163,209)
Non taxable income (19,500) (50,779)
Financing costs not allowed for SCT 2,587 5,165
Ring Fence Expenditure Supplement (44,731) (73,900)
Deferred tax effect of small field
allowance (21,842) 43,640
Under/(over) provided in prior years 23,224 (9,641)
Unrecognised tax losses 4,701 7,345
Petroleum Revenue Tax - (1,261)
Movement due to the rate change 82,116 50,854
Difference in rate of tax 1,205 (5,627)
----------------------------------------------- -------------------- ----------
Total tax credit recorded in the consolidated
statement of income (5,702) (197,413)
The effective rate of tax applicable for UK ring fence oil and gas activities in 2016 was 40% (2015: 50%).
Deferred income tax at 31 December 2016 relates to the following:
2016 2015
US$'000 US$'000
------------------------ ---------------- ----------
Deferred tax liability (353,512) (493,947)
Deferred tax asset 737,175 871,908
------------------------ ---------------- ----------
Net deferred tax asset 383,663 377,961
The gross movement on the deferred income tax account is as follows:
2016 2015
US$'000 US$'000
--------------------------------------- ------------------ ----------
At 1 January 377,961 174,475
Disposals - 36,947
Income statement credit 5,702 166,539
--------------------------------------- ------------------ ----------
At 31 December 383,663 377,961
Accelerated
Other tax dep'n Total
Deferred tax liability US$'000 US$'000 US$'000
--------------------------- --------- ------------------ ----------
At 1 January 2016 (48,490) (445,457) (493,947)
Prior year adjustment (17,199) 2,653 (14,546)
Movement for rate change 13,050 77,635 90,685
Origination and reversal
of temporary differences (28,629) 47,815 16,481
---------------------------- --------- ------------------ ----------
At 31 December 2016 (4,824) (348,688) (353,512)
Deferred
CT
On Deferred Abandonment
PRT Tax losses provision Total
Deferred tax assets US$'000 US$'000 US$'000 US$'000
--------------------------- -------------- ----------- ------------ ----------
At 1 January 2016 11,118 778,730 82,059 871,907
Prior year adjustment - (5,148) (3,530) (8,678)
Movement for rate change (11,118) (145,977) (15,706) (172,801)
Origination and reversal
of temporary differences - 44,974 1,773 46,747
---------------------------- ------------- ----------- ------------ ----------
At 31 December 2016 - 672,579 64,596 737,175
Deferred income tax assets are recognised for the carry-forward of unused tax losses and unused tax credits to the extent that it is probable that taxable profits will be available in the future against which the unused tax losses/credits can be utilised.
The Budget on 16 March 2016 announced that the Supplementary Charge in respect of ring fence trades ("SCT") will be reduced from 20% to 10% with effect from 1st January 2016. The reduction was enacted in September 2016.This will reduce the Company's future SCT charge accordingly. The impact of the 10% reduction in the Supplementary Charge was to reduce the deferred tax assets by $172.8 million and reduce the deferred tax liabilities by $90.7 million.
The Budget on 16 March 2016 also further reduced the rate of Petroleum Revenue Tax ("PRT") for chargeable periods beginning on or after 1 January 2016. The Budget on 18 March 2015 had reduced the rate from 50% to 35%. The rate was further reduced from 35% to 0%. This eliminated the Company's future PRT tax charge from 1 January 2016. The PRT rate change has been enacted and therefore the deferred PRT provision was fully released giving rise to a credit in the year of $24.2 million.
The UK related tax losses of $1,681 million do not expire under UK tax legislation and may be carried forward indefinitely. In addition to these losses, the Company will also benefit from the carry forward of capital allowances of $52 million, which are included in the calculation of accelerated tax depreciation above, giving a total pool of losses and allowances of $1,733 million.
Based on current production and price assumptions and a continuing business model whereby the Corporation reinvests capital, incurs general, administrative and interest costs, together with the non-capital losses available to the Corporation, Ithaca does not expect to pay corporation or supplementary tax within the next 5 years.
In accordance with the Stella Sale and Purchase Agreement ("SPA"), Ithaca receives the right to claim a tax benefit for additional capital allowances on certain capital expenditures incurred by Ithaca and paid for by Petrofac on the Stella project.
The tax benefit of these capital allowances is received by Ithaca as the expenditure is incurred. In recognition of the benefit Ithaca receives from the additional capital allowances a payment is expected to be made to Petrofac 5 years after Stella first oil of a sum calculated at the prevailing tax rate applied to the relevant capital allowances, in accordance with the SPA. The 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 credit in the year of $25.7 million resulting in a related deferred tax asset at 31 December 2016 of $95.0million.
PETROLEUM REVENUE TAX 2016 2015
US$000 US$000
------------------------------------------ ------- ---------
Current tax
Current tax on profits for the year 1,920 4,839
Deferred tax
Relating to the origination and reversal
of accelerated tax depreciation - (2,317)
Relating to changes in tax rates 22,235 (10,522)
------------------------------------------ ------- ---------
Total tax credit/(charge) 24,155 (8,000)
Deferred PRT 2016 2015
Deferred PRT liability US$000 US$000
-------------------------- --------- ---------
At 1 January (22,235) (35,209)
Prior year adjustment - 135
Movement for rate change 22,235 10,522
Income statement charge - 2,317
-------------------------- --------- ---------
At 31 December - (22,235)
26. COMMITMENTS
2016 2015
US$'000 US$'000
----------------------------- --------- ---------
Operating lease commitments
Within one year 216 240
Two to five years 30 300
Capital commitments
2016 2015
US$'000 US$'000
--------------------------------------- --------- ---------
Capital commitments incurred jointly
with other ventures (Ithaca's share) 18,912 9,534
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 first production 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 first production from the Stella field.
27. 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 December 2016:
Total
Level Level Level Fair
1 2 3 Value
US$'000 US$'000 US$'000 US$'000
-------------------------- ---------- --------- --------- ----------
Contingent consideration - (4,329) - (4,329)
Derivative financial
instrument liability - (12,650) - (12,650)
Derivative financial
instrument asset - 11,512 - 11,512
-------------------------- ---------- --------- --------- ----------
The table below presents the total (loss)/gain on financial instruments that has been disclosed through the consolidated statement of comprehensive income:
2016 2015
US$'000 US$'000
---------------------------- ------------------- ---------
Revaluation of forex
forward contracts (227) 609
Revaluation of other
long term liability - 307
Revaluation of commodity
hedges (119,248) (23,338)
Revaluation of interest
rate swaps 195 (180)
(119,280) (22,602)
Realised (loss)/ gain
on forex contracts (8,758) 1,512
Realised gain on commodity
hedges 87,908 176,773
Realised (loss) on
interest rate swaps (286) (357)
------------------------------ ------------------- ---------
78,864 177,928
Total (loss)/ gain
on financial instruments (40,416) 155,326
The Corporation has identified that it is exposed principally to these areas of market risk.
i) Commodity Risk
The table below presents the total (loss)/gain on commodity hedges that has been disclosed through the statement of income at the year end:
2016 2015
US$'000 US$'000
----------------------------------- ---------- ---------
Revaluation of commodity hedges (119,248) (23,338)
Realised gain on commodity hedges 87,908 176,773
----------------------------------- ---------- ---------
Total (loss)/gain on commodity
hedges (31,340) 153,435
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 year end:
Derivative Term Volume Average price
------------ -------------- ----------- ------- ------------------
Jan 17 - June bbls
Oil swaps 17 632,040 $69.3/bbl
Jan 17 - June bbls
Oil puts 18 1,891,600 $53.9/bbl
Jan 17 - June bbls $46.5 - $60.0/bbl
Oil Collars 18 1,000,007 *
Jan 17 - Mar therms
Gas swaps 17 1,501,537 47p/therm
Jan 17 - June therms
Gas puts 17 36,200,000 62p/therm
* hedged with an average floor price of $46.5/bbl and a celling price of $60/bbl.
ii) Interest Risk
The table below presents the total loss on interest financial instruments that has been disclosed statement of income at the year end:
2016 2015
US$'000 US$'000
--------------------------------------- -------------------- ---------
Revaluation of interest contracts 195 (180)
Realised (loss) on interest contracts (286) (357)
--------------------------------------- -------------------- ---------
Total (loss) on interest contracts (91) (537)
Calculation of interest payments for the RBL Facility agreement incorporates LIBOR. The Corporation is therefore exposed to interest rate risk to the extent that LIBOR may fluctuate.
There were no interest rate financial instruments in place at the year end.
iii) Foreign Exchange Rate Risk
The table below presents the total (loss)/gain on foreign exchange financial instruments that has been disclosed through the statement of income at the year end:
2016 2015
US$'000 US$'000
------------------------------------ --------- ---------
Revaluation of forex forward
contracts (227) 609
Realised (loss)/gain on forex
forward contracts (8,758) 1,512
------------------------------------ --------- ---------
Total (loss)/gain on forex forward
contracts (8,985) 2,121
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 year 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 December 2016 substantially all accounts receivables are current, being defined as less than 90 days. The Corporation has no allowance for doubtful accounts as at 31 December 2016 (31 December 2015: $Nil).
The Corporation may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to meet the terms of the contracts. The Corporation's exposure is limited to those counterparties holding derivative contracts with positive fair values at the reporting date. As at 31 December 2016, the exposure is $11.5 million (31 December 2015: $126.9 million) and is with eight investment grade banks, all members of the company's RBL syndicate.
The Corporation also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values.
v) Liquidity Risk
Liquidity risk includes the risk that as a result of its operational liquidity requirements the Corporation will not have sufficient funds to settle a transaction on the due date. The Corporation manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Corporation considers the maturity profiles of its financial assets and liabilities. As at 31 December 2016, substantially all accounts payable are current.
The following table shows the timing of contractual cash outflows relating to trade and other payables.
Within 1 1 to 5 years
year US$'000
US$'000
------------------------------ -------------------- ---------------------
Accounts payable and accrued
liabilities (236,928) -
Other long term liabilities - (107,428)
Borrowings - (618,566)
------------------------------ -------------------- ---------------------
(236,928) (725,994)
28. DERIVATIVE FINANCIAL INSTRUMENTS
2016 2015
US$'000 US$'000
------------------ --------------------- ---------------------
Oil swaps 7,786 61,602
Oil puts (1,797) -
Oil capped swaps (2,422) 7,117
Gas swaps (110) 1,690
Gas puts 3,709 56,352
Other 17 (71)
------------------ --------------------- ---------------------
7,183 126,690
29. FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES
Financial instruments of the Corporation consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in these financial statements. At 31 December 2016, the classification of financial instruments and the carrying amounts reported on the statement of financial position and their estimated fair values are as follows:
2016 2015
US$'000 US$'000
----------------------------- ---------------------- ----------------------
Carrying Fair Carrying Fair
Classification Amount Value Amount Value
----------------------------- ---------- ---------- ---------- ----------
Cash and cash equivalents
(Held for trading) 27,199 27,199 11,543 11,543
Derivative financial
instruments (Held for
trading) 11,512 11,512 126,887 126,887
Accounts receivable (Loans
and Receivables) 157,912 157,912 223,006 223,006
Deposits 667 667 743 743
Long-term receivable
(Loans and Receivables) 59,922 59,922 61,052 61,052
Borrowings (Loans and
Receivables) (618,566) (618,566) (666,130) (666,130)
Contingent consideration (12,650) (12,650) (4,000) (4,000)
Derivative financial
instruments (Held for
trading) (4,329) (4,329) (197) (197)
Other long term liabilities (107,428) (107,428) (92,543) (92,543)
Accounts payable (Other
financial liabilities) (236,928) (236,928) (275,907) (275,907)
30. 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 Dec
2016 2015
-------------------------- -------------------------- --------- ---------
Ithaca Energy (UK)
Limited Scotland 100% 100%
Ithaca Minerals (North
Sea) Limited Scotland 100% 100%
Ithaca Energy (Holdings)
Limited Bermuda 100% 100%
Ithaca Energy Holdings
(UK) Limited Scotland 100% 100%
Ithaca Petroleum
Limited England and Wales 100% 100%
Ithaca North Sea
Limited England and Wales 100% 100%
Ithaca Exploration
Limited England and Wales 100% 100%
Ithaca Causeway Limited England and Wales 100% 100%
Ithaca Gamma Limited England and Wales 100% 100%
Ithaca Alpha Limited Northern Ireland 100% 100%
Ithaca Epsilon Limited England and Wales 100% 100%
Ithaca Delta Limited England and Wales 100% 100%
Ithaca Petroleum
Holdings AS Norway 100% 100%
Ithaca Petroleum
Norge AS* Norway 0% 0%
Ithaca Technology
AS Norway 100% 100%
Ithaca AS Norway 100% 100%
Ithaca Petroleum
EHF Iceland 100% 100%
Ithaca SPL Limited England and Wales 100% 100%
Ithaca Dorset Limited England and Wales 100% 100%
Ithaca SP UK Limited England and Wales 100% 100%
Ithaca Pipeline Limited England and Wales 100% 100%
Transactions between subsidiaries are eliminated on consolidation.
*Ithaca Petroleum Norge AS was disposed of in Q2 2015.
The following table provides the total amount of transactions that have been entered into with related parties during the year ending 31 December 2016 and 31 December 2015, as well as balances with related parties as of 31 December 2016 and 31 December 2015:
Sales Purchases Accounts receivable Accounts
payable
US$'000 US$'000 US$'000 US$'000
------------------ ------------ ---------- -------------------- ---------
Burstall Winger
Zammit LLP 2016 - (171) 273 -
2015 - (182) - -
A director of the Corporation is a partner of Burstall Winger Zammit LLP who acts as counsel for the Corporation.
Loans to related Amounts owed from related
parties parties
2016 2015
US$'000 US$'000
------------------ ------------- -------------
FPF-1 Limited 59,876 60,842
FPU Services
Limited 46 210
--------------------- ------------- -------------
59,922 61,052
Key management compensation
Key management includes the Chief Executive Officer, the Chief Financial Officer, the Chief Operations Officer, the Chief Technical Officer and the Non-Executive Directors. The compensation paid or payable to key management for employee services is shown below:
2016 2015
US$'000 US$'000
------------------------------- --------- ---------
Aggregate remuneration 3,548 3,953
Company pension contributions 97 264
Share based payment 953 328
------------------------------- ---------
4,598 4,545
Share based payment reflects the value of options granted in 2016 as per the Black Scholes option pricing model. This does not represent a cash payment to key management personnel.
31. JOINT OPERATIONS
Joint control is defined as "the contractually agreed sharing of control of an arrangement, which exists only when the decisions about the relevant activities require the unanimous consent of the parties sharing control". All of the joint operations of the Company are subject to Joint Operating Agreements ("JOA"s) which fall into this category and where the participants in the agreements are entitled to a share of all the assets, and obligations of all the liabilities of the operations, rather than to a share of the net assets.
The contractual arrangements for the license interests in which the Company has an investment do not typically convey control of the underlying joint arrangement to any one party, even where one party has a greater than 50% equity ownership of the area of interest. UK North Sea assets are commonly operated and governed through JOAs under which joint control of the decisions regarding the relevant activities (e.g. the approval of exploration and development, production and abandonment work programmes and budgets) is exercised by the unanimous consent of the controlling parties, regardless of the individual equity interests held in the underlying asset by those parties sharing the control.
The Corporation's material joint operations as at 31 December 2016 are set out below:
Block Licence Field/Discovery Name Operator Ithaca Country
Net % Interest
-------- ----------------
2/4a P902 Broom EnQuest 8.00 UK
2/5 P242 Broom EnQuest 8.00 UK
14/18b P1293 Athena Ithaca 22.50 UK
21/20a P185 Cook Ithaca 61.35 UK
29/10b P1665 Hurricane Ithaca 54.66 UK
29/10a (upper) P011 Stella/Harrier Ithaca 68.33 UK
30/6a (Upper) P011 Stella/Harrier Ithaca 68.33 UK
48/18b P128 Anglia Ithaca 30.00 UK
48/19b P128 Anglia Ithaca 30.00 UK
48/19e P1011 Anglia Ithaca 30.00 UK
49/2a P1013 Topaz RWE 35.00 UK
9/28a D P209 Crawford EnQuest 29.00 UK
211/18b A P236 West Don EnQuest 17.28 UK
211/18a B P236 SW Don EnQuest 40.00 UK
211/22a B P201 Fionn Ithaca 100.00 UK
211/23d P1383 Causeway Ithaca 64.50 UK
23/22a P111 Pierce Shell 7.48 UK
98/6,98/7 P.534 Wytch Farm Perenco 7.42 UK
SY/88b,SY/98a,SZ/8a PL089 Wytch Farm Perenco 7.42 UK
211/18e, 211/19c P2137 Ythan EnQuest 40.00 UK
32. SUBSEQUENT EVENTS
On 6 February 2016 the Corporation announced that it has 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.
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR EAFDAADKXEAF
(END) Dow Jones Newswires
March 23, 2017 03:01 ET (07:01 GMT)
1 Year Ithaca Energy Chart |
1 Month Ithaca Energy Chart |
It looks like you are not logged in. Click the button below to log in and keep track of your recent history.
Support: +44 (0) 203 8794 460 | support@advfn.com
By accessing the services available at ADVFN you are agreeing to be bound by ADVFN's Terms & Conditions
