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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Ithaca Energy | LSE:IAE | London | Ordinary Share | CA4656761042 | COM SHS NPV (DI) |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 110.75 | 0.00 | 01:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
From Apr 2019 to Apr 2024
TIDMIAE
RNS Number : 1178H
Ithaca Energy Inc
15 August 2016
Not for Distribution to U.S. Newswire Services or for Dissemination in the United States
Ithaca Energy Inc.
2016 Half Year Financial Results
15 August 2016
Ithaca Energy Inc. (TSX: IAE, LSE AIM: IAE) ("Ithaca" or the "Company") announces its quarterly financial results for the three months ended 30 June 2016 ("Q2-2016" or the "Quarter") and half year results for the six months ended 30 June 2016 ("H1-2016").
Highlights
Solid cashflow generation during H1-2016
-- Average production of 9,378 boepd - ahead of 9,000 boepd guidance
-- Sustained reduction in unit operating costs - full year guidance lowered to $25/boe prior to Stella start-up, down $5/boe or 17%, in line with H1-2016 performance
-- $82 million cashflow from operations, driven by reduced operating costs and hedging (cashflow per share $0.20)
-- Earnings of $46 million excluding mark-to-market of future commodity hedges, $6 million unadjusted (earnings per share $0.02)
Continued deleveraging of the business being delivered ahead of Stella start-up - strong liquidity position
-- Net debt reduced from a peak of over $800 million in the first half of 2015 to $606 million at 30 June 2016
-- Over $120 million of funding headroom - total debt availability in excess of $730 million following semi-annual RBL redetermination in April 2016
-- Significant commodity price protection remains in place - 8,200 boepd hedged from end H1-2016 to mid-2017 at an average price of $59/boe
"FPF-1" modifications programme completed and vessel approaching Stella field location
-- On track for Stella first hydrocarbons in November 2016, three months after sail-away
Long term value of the Greater Stella Area ("GSA") hub enhanced by future move to oil pipeline exports and expansion of satellite portfolio
-- Access secured to major oil export pipeline for future production and initial tie-in works completed, allowing switch from tanker loading to pipeline export during 2017 - reduces fixed operating costs, enhances operational uptime and improves reserves recovery
-- Interest in "Vorlich" discovery increased to approximately 33%(1) and a 75% interest and operatorship acquired in the nearby "Austen" discovery
Strong outlook - material near-term step-change in production and cashflow
-- Production set to more than double to 20-25,000 boepd and unit operating costs to reduce to under $20/boe with start-up of production from the Stella field
-- Attractive set of future investment opportunities within the portfolio - ability to tailor the capital investment programme to the prevailing economic outlook
-- Increasing financial flexibility - focus on delivering continued deleveraging of the business within a balanced capital investment programme
Les Thomas, Chief Executive Officer, commented:
"The business has continued to perform well over the first half of the year. Production is running ahead of guidance, operating costs have been further reduced and we have continued deleveraging the business. It has been particularly pleasing to announce the recent sail-away of the FPF-1, the quality and completeness of which means we move forward into the operational phase of the Stella development with confidence. We remain focused on getting to first production safely and efficiently, whilst ensuring we secure the long term value of the hub through our on-going investment activities."
Greater Stella Area Development
The FPF-1 modifications programme, which has been undertaken by Petrofac in the Remontowa shipyard in Poland, was completed in July 2016. Importantly, all the onshore scope and testing work scheduled for completion in the yard has been completed as planned, avoiding costly carry over of unfinished work offshore. The vessel has been materially upgraded to accommodate the requirements of the GSA hub. Additional buoyancy and enhancements to the marine systems have been undertaken to extend the operational life of the vessel and entirely new topside oil and gas processing facilities have been installed.
Following the completion of deep water marine system trials, the FPF-1 commenced its tow to the Stella field location in early August 2016. It is anticipated that the period from sail-away to first hydrocarbons is approximately three months. Following the tow the FPF-1 will be moored on location using twelve pre-installed anchor chains. The dynamic risers and umbilicals that connect the subsea infrastructure to the vessel will then be installed. Thereafter, commissioning of the various processing and utility systems that can only be undertaken on location with hydrocarbons from the field will be completed.
GSA Oil Pipeline
Access to the Norpipe oil pipeline system has been secured for future GSA production, allowing a switch from tanker loading during 2017. This move will significantly reduce the fixed operating costs of the GSA facilities and enhance operational uptime, resulting in improved reserves recovery and increasing the long term value of the GSA as a production hub.
GSA Satellite Acquisitions
As previously announced, the Company has entered into sale and purchase agreements ("SPA") to increase its interest in the Vorlich discovery from approximately 17% to 33%, adding approximately 4 MMboe(1) of net proven and probable reserves. An SPA has also been signed for the acquisition of a 75% interest and operatorship of the Austen discovery. Austen lies approximately 30 kilometres from the GSA hub and is estimated by Ithaca to contain gross contingent resources ("1C" to "3C") in the range of 4-28 MMboe(2) .
Initial considerations are payable at completion of the acquisitions, with additional contingent payments at FDP approval and upon reaching reserves recovery thresholds. The acquisition costs including potential future contingent payments total under $6 million, with the transactions expected to complete in the second half of 2016.
Production & Operations
The producing asset portfolio has performed well over H1 2016, with production running ahead of guidance largely as a result of solid performance from the Cook and Dons Area fields. Average production for the H1 2016 was 9,378 boepd (93% oil).
Full year base production guidance, excluding any contribution from start-up of the Stella field during 2016, remains unchanged at 9,000 boepd. The additional production contribution resulting from the start-up of Stella during the year will depend on the exact timing of first hydrocarbons from the field. Prompt ramp up of production is anticipated following first hydrocarbons, leading to an expected initial annualised production rate of approximately 16,000 boepd net to Ithaca.
Financials
Cashflow from Operations
Despite an approximate 30% fall in Brent and lower production primarily resulting from removal of high cost assets from the portfolio, the business delivered $82 million cashflow from operations in H1-2016. Adjusting for the one-off hedging gains realised in Q1-2015 and onerous contract provisions, H1-2016 cashflow from operations has remained broadly flat compared to the same period in 2015. This performance highlights the benefit of the commodity hedges the Company has in place and significant operating costs savings that have been secured through re-setting of the cost base.
Hedging
The Company's future commodity hedged position remains unchanged from that announced at the previous quarter's financial results. During H1-2016 approximately 13,500 boepd (55% oil) of commodity hedges were realised at an average price of $59/boe. This resulted in hedging cash gains of $58 million during the period.
Approximately 9,400 boepd (48% oil) is hedged in the second half of 2016 at an average price of $58/boe. In the first half of 2017 approximately 7,000 boepd (50% oil) is hedged at an average price of $60/boe. In total, as at the 1 July 2016 these future hedges were valued at $47 million based on prevailing oil and gas forward curves at that time.
Operating Expenditure
Operating costs in H1-2016 continued on the downward trend established in 2015, with an average unit cost of $25/boe delivered during the period. This represents a substantial 17% or $5/boe saving on forecast unit operating expenditure for the existing assets prior to Stella start-up. This has been achieved as a result of cost reductions secured across the portfolio, with the Cook and Wytch Farm fields delivering the most significant savings.
It is anticipated that unit operating costs from the existing producing fields will remain around $25/boe over the course of this year and the guidance is accordingly revised down from $30/boe. The forecast unit operating costs for the Stella field remain unchanged at $10-12/boe.
Capital Expenditure
Total capital expenditure in 2016 is forecast to be approximately $50 million, the majority of which relates to the GSA.
Net Debt
As planned, during H1-2016 the Company continued to delever the business ahead of first hydrocarbons from the Stella field. Net debt at 30 June 2016 was $606 million, down from $665 million at the end of 2015 and over 25% or $200 million since the peak of over $800 million in the first half of 2015.
Deleveraging of the business continues to remain a core priority of the Company, with a step change in the debt reduction profile achievable following the start-up of Stella production.
The business is fully funded with strong liquidity, having over $730 million of available debt ahead of planned first hydrocarbons from the GSA, which provides in excess of $120 million of funding headroom.
Tax
The Company had a UK tax allowances pool of over $1,600 million at 30 June 2016. At current commodity prices the pool is forecast to shelter the Company from the payment of corporation tax over the medium term.
Further Information
GSA Development Film
A short film capturing the work that has been completed on the Stella development and sail-away of the FPF-1 from Gdansk is available on the Company's website (www.ithacaenergy.com).
H1-2016 Financial Results Conference Call
A conference call and webcast for investors and analysts will be held today at 12.00 BST (07.00 EDT). Listen to the call live via the Company's website (www.ithacaenergy.com) or alternatively dial-in on one of the following telephone numbers and request access to the Ithaca Energy conference call: UK +44 203 059 8125; Canada +1 855 287 9927; US +1 866 796 1569. A short presentation to accompany the results will be available on the Company's website prior to the call.
Glossary
boe Barrels of oil equivalent boepd Barrels of oil equivalent per day MMboe Million barrels of oil equivalent RBL Reserves Based Lending facility
-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
Tom Hufton tom.hufton@fticonsulting.com +44 (0)203 727 1625
Cenkos Securities
Neil McDonald nmcdonald@cenkos.com +44 (0)207 397 1953
Nick Tulloch ntulloch@cenkos.com +44 (0)131 220 9772
Beth McKiernan bmckiernan@cenkos.com +44 (0)131 220 9778
RBC Capital Markets
Daniel Conti daniel.conti@rbccm.com +44 (0)207 653 4000
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.
1. The Vorlich field interest and estimated reserves reflect assumed unitisation across licences P1588 and P363. The estimated reserves are based on the independent reserves assessment performed by Sproule International Limited ("Sproule"), effective as of 31 December 2015, and prepared 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.
2. Estimates of the gross 1C to 3C contingent resource (Development Pending) range associated with the Austen discovery have been prepared by Ithaca, effective as of 1 July 2016, and not by an independent qualified reserves evaluator or assessor. These figures are estimates only and the actual results may be greater than or less than the estimates provided herein, with the resource range reflecting uncertainties and risks associated with compartmentalisation of the reservoir. There is no certainty that it will be commercially viable to produce any portion of these resources.
The estimates of reserves and resources stated herein for individual properties may not reflect the same confidence level as estimates of reserves and resources for all properties, due to the effects of aggregation. The well test results disclosed in this press release represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery therefrom.
The Company's total proved and probable reserves at 31 December 2015 plus the estimated reserves associated with the Vorlich licence acquisition from TOTAL, which completed in July 2016, were 57 MMboe. These reserves were independently assessed by Sproule, a qualified reserves evaluator.
References herein to barrels of oil equivalent ("boe") are derived by converting gas to oil in the ratio of six thousand cubic feet ("Mcf") of gas to one barrel ("bbl") of oil. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1 bbl, utilising a conversion ratio at 6 Mcf: 1 bbl may be misleading as an indication of value.
About Ithaca Energy
Ithaca Energy Inc. (TSX: IAE, LSE AIM: IAE) is a North Sea oil and gas operator focused on the delivery of lower risk growth through the appraisal and development of UK undeveloped discoveries and the exploitation of its existing UK producing asset portfolio. Ithaca's strategy is centred on generating sustainable long term shareholder value by building a highly profitable 25kboe/d North Sea oil and gas company. For further information please consult the Company's website www.ithacaenergy.com.
Non-IFRS Measures
"Cashflow from operations" and "cashflow per share" referred to in this press release are not prescribed by IFRS. These non-IFRS financial measures do not have any standardised meanings and therefore are unlikely to be comparable to similar measures presented by other companies. The Company uses these measures to help evaluate its performance. As an indicator of the Company's performance, cashflow from operations should not be considered as an alternative to, or more meaningful than, net cash from operating activities as determined in accordance with IFRS. The Company considers cashflow from operations to be a key measure as it demonstrates the Company's underlying ability to generate the cash necessary to fund operations and support activities related to its major assets. Cashflow from operations is determined by adding back changes in non-cash operating working capital to cash from operating activities.
"Net debt" referred to in this press release is not prescribed by IFRS. The Company uses net drawn debt as a measure to assess its financial position. Net drawn debt includes amounts outstanding under the Company's debt facilities and senior notes, less cash and cash equivalents.
Forward-looking Statements
Some of the statements and information in this press release are forward-looking. Forward-looking statements and forward-looking information (collectively, "forward-looking statements") are based on the Company's internal expectations, estimates, projections, assumptions and beliefs as at the date of such statements or information, including, among other things, assumptions with respect to production, drilling, construction and maintenance times, well completion times, risks associated with operations, required regulatory, partner and other third party approvals, commodity prices, future capital expenditures, continued availability of financing for future capital expenditures, future acquisitions and dispositions and cash flow. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. When used in this press release, the words and phrases like "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe", "could", "target", "in the process of", "on track" ,"set to" and similar expressions, and the negatives thereof, whether used in connection with operational activities, anticipated period from sail-away to Stella first hydrocarbons, production forecasts, anticipated ramp-up of production following Stella first hydrocarbons, , projected operating costs, anticipated capital expenditures and capital programme, anticipated effects of securing access to the GSA oil export pipeline, the anticipated timing of completion of the Vorlich and Austen license acquisitions, expected future payments associated with such license acquisitions, assumed unitisation across licences P1588 and P363 containing the Vorlich discovery, statements related to reserves and resources other than reserves, the planned independent assessment of the Austen property, the planned commissioning and offshore hook up activities associated with the FPF-1, portfolio investment opportunities, expected tax horizon of the Company, or otherwise, are intended to identify forward-looking statements. Such statements are not promises or guarantees, and are subject to known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Company believes that the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations, or the assumptions underlying these expectations, will prove to be correct and such forward-looking statements included in this press release should not be unduly relied upon. These forward-looking statements speak only as of the date of this press release. Ithaca Energy Inc. expressly disclaims any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement contained herein to reflect any change in its expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based except as required by applicable securities laws.
Additional information on these and other factors that could affect Ithaca's operations and financial results are included in the Company's Management Discussion and Analysis for the quarter and six months ended 30 June 2016 and the Company's Annual Information Form for the year ended 31 December 2015 and in reports which are on file with the Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).
Hot Features
Premium
2016 HALF YEAR HIGHLIGHTS
==================================================================
Solid cashflow
generation * Average production of 9,378 boepd - ahead of guidance
during H1-2016
* Sustained reduction in unit operating costs - full
year guidance lowered to $25/boe prior to Stella
start-up, down $5/boe or 17%, in line with H1 2016
performance
* $82 million cashflow from operations, driven by
reduced operating costs and hedging (cashflow per
share $0.20)
* Earnings of $46 million excluding mark-to-market of
future commodity hedges, $6 million unadjusted
(earnings per share $0.02)
------------------------------------------------------------------
Continued
deleveraging * Net debt reduced from a peak of over $800 million in
of the business the first half of 2015 to $606 million at 30 June
ahead of Stella 2016
start-up -
strong liquidity
position * Over $120 million of funding headroom - total debt
availability in excess of $730 million following
semi-annual RBL redetermination in April 2016
* Significant commodity price protection remains in
place - 8,200 boepd hedged from end H1 2016 to
mid-2017 at an average price of $59/boe
------------------------------------------------------------------
FPF-1 modifications
programme * "FPF-1" floating production facility sail-away
completed commenced early August 2016
* On track for Stella first hydrocarbons in November
2016, three months after sail-away
GSA hub enhanced
by future * Access secured to major oil export pipeline for
move to oil future production and initial tie-in works completed,
pipeline exports allowing switch from tanker loading to pipeline
and expansion export during 2017 - reduces fixed operating costs,
of satellite enhances operational uptime and improves reserves
portfolio recovery
* Interest in "Vorlich" discovery increased to
approximately 33% and a 75% interest and operatorship
acquired in the nearby "Austen" discovery
Strong outlook
- material * Production set to more than double to 20-25,000 boepd
near-term and unit operating costs to reduce to under $20/boe
step-change with start-up of production from the Stella field
in production
and cashflow
* Attractive set of future investment opportunities
within the portfolio - ability to tailor the capital
investment programme to the prevailing economic
outlook
* Increasing financial flexibility - focus on
delivering continued deleveraging of the business
within a balanced capital investment programme
SUMMARY STATEMENT OF INCOME
============================================================================================
3-Months Ended 30 June 6-Months Ended 30 June
2016 2015 2016 2015
Average Production kboe/d 9.8 12.7 9.4 12.6
Average Realised Oil
Price(1) $/bbl 46 62 40 60
Revenue(2) M$ 41.8 62.2 68.8 116.4
Hedging Cash Gain M$ 18.8 31.3 58.0 110.1
Revenue(2) (After
Hedging) M$ 60.6 93.5 126.8 226.5
Opex M$ (21.8) (29.5) (42.0) (57.6)
G&A M$ (1.3) (1.7) (3.0) (5.1)
Foreign Exchange(3) M$ (0.3) (2.0) (0.2) (3.6)
Cashflow from
Operations M$ 37.2 60.3 81.6 160.2
DD&A M$ (19.8) (31.7) (37.4) (62.3)
Non-Cash Hedging
(Loss)/Gain M$ (51.6) (41.7) (85.2) (91.2)
Finance Costs M$ (9.3) (10.8) (18.5) (20.9)
Other Non-Cash Costs M$ (0.6) (3.0) (1.1) (4.2)
Taxation - Excluding
Rate Changes M$ 32.6 66.7 42.7 73.7
- Reduced Tax Rates
Impact M$ - - 24.1 (41.5)
Earnings M$ (11.5) 39.9 6.2 13.8
Cashflow Per Share $/Sh. 0.09 0.16 0.20 0.43
Earnings Per Share $/Sh. (0.03) 0.12 0.02 0.04
(1) Average realised price before hedging
(2) Revenue net of stock movements
(3) Foreign exchange net of related realised
hedging gains & losses
SUMMARY BALANCE SHEET
============================================================================================
M$ 30 Jun. 31 Dec.
2016 2015
Cash & Equivalents 26 12
Other Current
Assets 339 372
PP&E 1,104 1,113
Deferred Tax
Asset 421 356
Other Non-Current
Assets 210 211
Total Assets 2,100 2,063
Current Liabilities (337) (283)
Borrowings (623) (666)
Asset Retirement
Obligations (232) (227)
Other Non-Current
Liabilities (107) (93)
Total Liabilities (1,299) (1,270)
Net Assets 801 793
Share Capital 618 617
Other Reserves 24 23
Surplus 159 153
Shareholders'
Equity 801 793
CORPORATE STRATEGY
=============================================================
Ithaca Energy Inc. ("Ithaca" or the "Company")
is a North Sea oil and gas operator focused
on the delivery of lower risk growth through
the appraisal and development of UK undeveloped
discoveries and the exploitation of its
existing UK producing asset portfolio.
Ithaca's goal is to generate sustainable
long term shareholder value by building
a highly profitable 25kboepd North Sea
oil and gas company.
Execution of the Company's strategy is
focused on the following core activities:
* Maximising cashflow and production from the existing
asset base
* Delivering first hydrocarbons from the Ithaca
operated Greater Stella Area development
* Delivery of lower risk, long term development led
growth through the appraisal of undeveloped
discoveries
* Continuing to grow and diversify the cashflow base by
securing new producing, development and appraisal
assets through targeted acquisitions and licence
round participation
* Maintaining capital discipline, financial strength
and a clean balance sheet, supported by lower cost
debt leverage
CORPORATE ACTIVITIES
-----------------------------------------------------
DEBT FACILITIES
Planned April In April 2016 the Company successfully
2016 RBL redetermination completed its routine semi-annual reserves
successfully based lending ("RBL") facilities review,
completed with in excess of $120 million of funding
- over $120M headroom in place as at 30 June 2016,
of headroom ahead of first hydrocarbons from the GSA.
in place as
at 30 June The Company completes a semi-annual redetermination
2016 process with its RBL bank syndicate, at
the end of April and October, to review
the borrowing capacity of its assets under
the RBLs based on the technical and commodity
price assumptions applied by the syndicate.
Following the April 2016 redetermination,
the Company's available borrowing capacity
is over $430 million prior to Stella start-up.
When combined with the $300 million senior
unsecured notes the Company has in place,
the business has a total debt capacity
of over $730 million. This compares to
net debt at the end of Q2 2016 of $606
million.
The Company is focused on maintaining
a solid liquidity position, with substantial
deleveraging having already been delivered
even before first hydrocarbons from the
GSA. Total RBL bank debt has been reduced
by almost 40% from a peak of over $500
million in the first half of 2015 to $306
million at the end of Q2 2016. A robust
financial position has been retained during
the current period of lower and more volatile
oil prices as a result of various proactive
measures taken to increase the financial
strength of the business and ensure that
the Company has sufficient flexibility
to manage downside risks.
As a consequence of the substantial deleveraging,
the Company elected to reduce the size
of the debt facilities from $650 million
to $535 million, saving approximately
$0.5 million in commitment fees, effective
June 2016. This change has no effect on
the current RBL debt capacity of approximately
$430 million, as this is substantially
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.
DIRECTOR & EXECUTIVE CHANGES
Certain director and senior management
changes have been made since the start
of the year. Following the Company's AGM
in June 2016, Jack C. 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
--------------------------------------------------
The producing asset portfolio has performed
H1 2016 production well over H1 2016, with production running
running ahead ahead of guidance largely as a result
of full year of solid performance from the Cook and
guidance Dons Area fields. Average production for
H1 2016 was 9,378 boepd, 93% oil (H1 2015:
12,578 boepd), which compares to full
year base production guidance of approximately
9,000 boepd.
When comparing H1 2016 with the same period
in 2015, production has reduced by approximately
25%. This reflects the specific steps
taken in 2015 to reposition the portfolio
to meet the requirements of the lower
Brent price environment, namely the cessation
of production from the Athena and Anglia
fields, and no significant investment
in the existing production portfolio as
a consequence of the prevailing uncertainty
and volatility in oil prices. Production
rates have also been restricted on the
Pierce field during H1 2016 due to the
requirement to complete remedial works
on the field's subsea gas injection flowline.
The majority of the planned 2016 operational
programmes on the producing asset portfolio
have now been completed, with only the
two week Brent System maintenance shutdown
that is scheduled for October 2016 remaining;
this shutdown will impact production from
the Company's Northern North Sea fields.
The gas injection flowline works were
completed on the Pierce field as planned
at the end of Q2 2016 and unrestricted
production rates have been restored. Within
the Causeway Area a mechanical failure
of the second electrical submersible pump
in the Causeway well has led to the well
being shut-in, with production in the
area now coming exclusively from the Fionn
field. The impact of this on both current
and forecast production is limited given
the performance of the other fields in
the portfolio.
Full year base production guidance, excluding
any contribution associated with start-up
of the Stella field during the year, remains
unchanged at 9,000 boepd. The additional
production contribution during the year
resulting from the start-up of Stella
will depend on the exact timing of first
hydrocarbons from the field. Prompt ramp
up of production is anticipated following
first hydrocarbons, leading to an expected
initial annualised production rate of
approximately 16,000 boepd net to Ithaca.
GREATER STELLA AREA DEVELOPMENT
----------------------------------------------------
GSA development Ithaca's focus on the GSA is driven by
activities the monetisation of over 30MMboe of net
are at an 2P reserves within the existing portfolio
advanced stage and the generation of additional value
of completion via the wider opportunities provided by
- Stella production the range of undeveloped discoveries surrounding
start-up scheduled the Ithaca operated production hub.
for November
2016 The development involves the creation
of a production hub based on deployment
of the Ithaca and JV partner owned FPF-1
floating production facility located over
the Stella field, with onward export of
oil and gas. To maximise initial oil and
condensate production and fill the gas
processing facilities on the FPF-1, the
hub will start-up with five Stella wells.
Further wells will then be drilled in
the GSA post first hydrocarbons to maintain
the gas processing facilities on plateau.
FPF-1 Modification Works
FPF-1 modifications The FPF-1 modifications programme, which
programme has been undertaken by Petrofac in the
completed Remontowa shipyard in Poland, was completed
in July 2016. Importantly, all the onshore
scope and testing work scheduled for completion
in the yard has been completed as planned
avoiding costly carry-over of unfinished
work offshore. The vessel has been materially
upgraded to accommodate the requirements
of the GSA hub. Additional buoyancy and
enhancements to the marine systems have
been undertaken to extend the operational
life of the vessel and entirely new topside
oil and gas processing facilities have
been installed.
Following the completion of deep water
marine system trials, the FPF-1 commenced
its tow to the Stella field location in
early August 2016. It is anticipated that
the period from sail-away to first hydrocarbons
is approximately three months. Following
the tow the FPF-1 will be moored on location
using twelve pre-installed anchor chains.
The dynamic risers and umbilicals that
connect the subsea infrastructure to the
vessel will then be installed. Thereafter,
commissioning of the various processing
and utility systems that can only be undertaken
on location with hydrocarbons from the
field will be completed.
Drilling Programme
Stella development The five well Stella development drilling
drilling programme programme was successfully completed in
successfully April 2015. The wells have all been successfully
completed cleaned up and suspended in a manner that
in 2015 allows production to commence without
the requirement for any further intervention
activity once the FPF-1 is on location
and hooked up. In total the wells have
achieved a combined maximum flow test
rate during clean-up operations of over
53,000 boepd (100%). This well capacity
significantly de-risks the initial annualised
production forecast for the GSA hub of
approximately 30,000 boepd (100%), 16,000
boepd net to Ithaca.
Subsea Infrastructure WORKS
Subsea infrastructure The subsea infrastructure installation
ready for campaign associated with start-up of the
arrival of Stella field was successfully completed
FPF-1 in 2015. The only remaining subsea workscope
to be undertaken prior to first hydrocarbons
relates to the installation and hook-up
of the dynamic risers and umbilicals connecting
the infrastructure on the seabed to the
FPF-1. This activity will be complete
once the vessel has been anchored on location.
GSA OIL EXPORT PIPELINE
Access to Access to the Norpipe oil pipeline system
oil export has been secured for future GSA production,
pipeline secured allowing a switch from tanker loading
from 2017, during 2017. This move will significantly
reducing fixed reduce the fixed operating costs of the
operating GSA facilities and enhance operational
costs and uptime, resulting in improved reserves
increasing recovery and increasing the long term
the long term value of the GSA as a production hub.
value of the
GSA The key work associated with creating
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. In addition the Company took
advantage of the downturn in industry
activity to secure attractive contracting
terms, including a lump sum contract for
the installation of the 44 kilometre pipeline
required from the FPF-1 to the Norpipe
system. The net capital expenditure associated
with the work programme is approximately
$20 million, with the majority being paid
in 2017.
Norpipe runs approximately 350 kilometres
from the Ekofisk offshore production facilities
on the Norwegian Continental Shelf to
a dedicated oil processing facility at
Teesside in the UK, with various UK fields
exporting into the system via a spurline.
LICENCE PORTFOLIO ACTIVITIES
-----------------------------------------------------
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
field sale of the Anasuria floating production,
storage and offloading vessel (and associated
feeder field interests), which serves
as the host facility for the field.
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 entered into four agreements in July 2016
infrastructure to increase its interest in the Vorlich
value discovery from approximately 17% to 33%
and to acquire a 75% interest and operatorship
of the Austen discovery. The Vorlich acquisition
increases the Company's net proven and
probable reserves by approximately 4MMboe,
based on the independent reserves evaluation
performed by Sproule International Limited
("Sproule") as of 31 December 2015, with
Austen resulting in the addition of contingent
resources into the portfolio. The total
acquisition cost including potential future
contingent payments is under $6 million.
VORLICH
Sale and purchase agreements ("SPA") have
been executed with ENGIE E&P UK Limited
("ENGIE E&P"), INEOS UK SNS Limited and
Maersk Oil North Sea Limited to acquire
100% of licence P1588 (Block 30/1f), with
an effective date of 1 January 2016. 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,
execution of the three SPAs increases
Ithaca's overall interest in the Vorlich
discovery by 16% to approximately 33%.
Vorlich was discovered and appraised in
2014 with exploration well 30/1f-13A,Z
and 13Z. The well encountered hydrocarbons
in a Palaeocene sandstone reservoir in
Block 30/1c and a subsequent side-track
into Block 30/1f confirmed the westerly
extension of the discovery. The well was
flow tested at a maximum rate of 5,350
boepd (approximately 80% oil).
Vorlich is located approximately 10 kilometres
north of the Company's GSA production
hub and was estimated as of 31 December
2015 to contain gross proven and probable
undeveloped reserves of approximately
24 Mmboe by Sproule. Following completion
of the Vorlich appraisal programme in
2014, current activities are focused on
planning and preparation of an FDP.
Upon completion of the three SPAs, the
overall Vorlich licence interests will
be as follows:
* Licence P363: BP (Operator), 80%; Ithaca, 20%
* Licence PL1588: Ithaca (Operator), 100%
AUSTEN
An SPA was executed 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 that was flow tested
at a maximum rate of 7,820 boepd (approximately
50% oil). The gross contingent resources
("1C" to "3C") associated with Austen
are estimated by Ithaca to be in the range
of 4-28 MMboe. An independent assessment
will be completed at the end of the year
as part of the usual annual reserves evaluation
exercise.
Upon completion of the acquisition, the
Austen licence interests will be: Ithaca
(Operator), 75%; Premier Oil, 25%. 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.
Initial considerations are payable at
completion of the acquisitions, with additional
contingent payments at FDP approval and
upon reaching reserves recovery thresholds.
The licence acquisitions are expected
to complete in the second half of 2016
and are subject to normal regulatory and
partner approvals, including approval
for the transfer of operatorship. At completion
the considerations paid will be subject
to normal industry adjustments to reflect
costs incurred since the effective dates
of the transactions.
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 (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
-------------------------------------------------------------
12 months As part of its overall risk management
future commodity strategy, Ithaca's commodity hedging policy
price protection is centred on underpinning revenues from
in place for existing producing assets at the time
>90% of production of major capital expenditure programmes
from current and locking in paybacks associated with
producing asset acquisitions. Any hedging is executed
fields at the discretion of the Company, with
no minimum requirements stipulated in
any of the Company's debt finance facilities.
The Company's future commodity hedged
position is unchanged from that announced
at the previous quarter's financial results.
Following the realisation of a $18.8 million
gain in Q2 2016, as of 1 July 2016 the
Company had 8,200 boepd hedged at an average
price of $59/boe for the year to June
2017. This total is comprised of:
* 9,400 boepd (48% oil) at average price of $58/boe for
the remaining six months of 2016
* 7,000 boepd (50% oil) at average price of $60/boe in
the first six months of 2017.
The above figures include 87 million therms
of gas hedging (approximately 9 billion
cubic feet), with a price floor of GBP0.56/therm
($8.30/MMbtu). The gas hedging is in
the form of put options, the financial
benefit of which is realised regardless
of production in the relevant period.
As at 1 July 2016 the Company's commodity
hedges were valued at $46.6 million, $25.6
million for oil hedges and $21.0 million
for gas hedges, based on valuations relative
to the respective oil and gas forward
curves.
OPERATING EXPITURE
--------------------------------------------------
Forecast full Operating costs in H1 2016 continued on
year operating the downward trend established in 2015,
costs for with a unit cost of $25/boe being delivered
current producing during the period. This represents a substantial
assets reduced 17% saving on the $30/boe level forecast
to $25/boe for the existing assets prior to Stella
start-up. Cost reductions have been achieved
across the portfolio, with the Cook and
Wytch Farm fields delivering the most
significant savings.
It is expected that the cost savings achieved
across the existing producing asset base
in H1 2016 can be sustained throughout
the year. 2016 unit operating cost guidance
prior to Stella start-up is therefore
reduced from $30/boe down to $25/boe.
CAPITAL EXPITURE
-------------------------------------------------
$50 million Total 2016 capital expenditure is anticipated
2016 capital to be approximately $50 million (2015:
expenditure $117 million), the majority of which relates
programme, to the GSA, including activities associated
60% lower with planning and preparation of a Field
than 2015 Development Plan for the Vorlich discovery.
Of this total, $15.2 million was incurred
in H1 2016.
Beyond 2016 Ithaca forecast an average
underlying capital expenditure of $10-25
million per annum on its producing asset
portfolio. This relates to facilities
maintenance and low cost production enhancement
activities. In addition to this, the Company
has a diverse set of further investment
opportunities within its existing portfolio
and the flexibility to tailor its capital
programme to the economic outlook at the
time. It is anticipated that the average
annual capital expenditure required to
develop these opportunities will be between
$25 -75 million.
The Company is in the process of developing
its capital investment plans for the period
following the start-up of production from
the Stella field and the 2017 expenditure
associated with such activities will be
finalised with its joint venture partners
later in the year. Planning of the Harrier
development well programme is well advanced
and work continues on assessing the options
for drilling infill wells on the Cook
field and the Don NE licence area. The
nature of these programmes, being drilling
targets that take advantage of existing
infrastructure, and the opportunities
to secure lower than previously anticipated
investment costs mean that these are expected
to represent high value targets in the
current environment.
DEBT
---------------------------------------------------------------
Further deleveraging DEBT SUMMARY (M$) 30 Jun. 31 Dec.
in 2016 - 2016 2015
net debt reduced RBL Facility 331.8 376.8
to $606M at Senior Notes 300.0 300.0
end Q2 2016 Total Debt 631.8 676.8
UK Cash and Cash Equivalents (25.9) (11.5)
Net Drawn Debt 605.9 665.3
Note this table shows debt repayable as
opposed to the reported balance sheet
debt which nets off capitalised RBL and
senior note costs
Since net debt peaked as anticipated in
the first half of 2015 at over $800 million,
the Company has significantly delevered
the business. Net debt was reduced by
a further $60 million in the first half
of 2016 to $606 million at 30 June 2016.
This reduction reflects the benefit of
continuing strong operating cashflow generation
from the base producing assets combined
with lower capital expenditures across
the portfolio.
Deleveraging of the business remains a
core priority of the Company, with a step
change in the debt reduction profile forecast
upon the start-up of Stella production.
TRADING ENVIRONMENT
-----------------------------------------------------------------
COMMODITY PRICES
-----------------------------------------------------------------
3-Months Ended 6-Months Ended
30 June 30 June
2016 2015 2016 2015
Average Brent
Price $/bbl 46 62 40 58
The Q2 2016 financial results reflect
the impact of the continued fall in Brent
prices that has dominated the sector since
the middle of 2014. On a year-on-year
basis, the average annual Brent price
has decreased by $16/bbl or 26% between
Q2 2015 and Q2 2016. When comparing H1
2016 with the same period in 2015, this
fall increases to $18/bbl or 31%. While
this has had a significant negative impact
on revenues, the fall in Brent has been
materially mitigated during the period
by the significant oil and gas price hedging
protection the Company had put in place.
FOREIGN EXCHANGE RATES
-----------------------------------------------------------------
3-Months Ended 6-Months Ended
30 June 30 June
2016 2015 2016 2015
GBP : USD
average 1.43 1.53 1.43 1.52
GBP : USD
period end
spot 1.34 1.57 1.34 1.57
The company seeks to minimise currency
volatility through active hedging of pounds
sterling. Ahead of the introduction of
gas sales from the Stella field in the
fourth quarter of 2016, the majority of
the Company's revenue is US dollar denominated
oil sales while approximately 80% of costs
are incurred in pounds sterling. The recent
sharp fall in GBP vs USD of approximately
10%, following the result of the UK referendum
to leave the European Union, is however
not expected to have a material net effect
on the results of the business in 2016
as a result of the Company's active hedging
programme (refer below).
Q2 2016 RESULTS OF OPERATIONS
------------------------------------------------------------------------
REVENUE
------------------------------------------------------------------------
THREE MONTHSED 30 JUNE 2016
Revenue decreased by $34.7 million in
Q2 2016 to $24.5 million (Q2 2015: $59.2
million) as a consequence of a $16/bbl
or 26% decrease in the realised oil price
prior to taking into account hedging,
combined with a 51% reduction in sales
volumes. While produced volumes decreased
by 23% in Q2 2016 compared to Q2 2015,
primarily driven by the cessation of production
from the Athena and Anglia fields and
natural decline in the Causeway Area,
sales volumes decreased more significantly
due to lifting schedules. In particular,
the drop in sales volumes was attributable
to the fact there were no oil liftings
from the Cook field in Q2 2016.
The reduction in realised price for the
period was offset to a significant extent
by realised oil and gas hedging gains
of $33 per sales barrel of oil equivalent
in the quarter, resulting in an $18.8
million gain being reported through Foreign
Exchange and Financial Instruments (see
below).
While realised oil prices for each of
the fields in the Company's portfolio
do not strictly follow the Brent price
pattern, with some fields sold at a discount
or premium to Brent and under contracts
with differing timescales for pricing,
the average realised price for all the
fields trades broadly in line with Brent.
SIX MONTHSED 30 JUNE 2016
Revenue decreased by $71.7 million in
H1 2016 to $57.8 million (H1 2015: $129.5
million). This 55% reduction was driven
by a decrease of $20/bbl or 33% in the
pre-hedging realised oil price associated
with the fall in Brent during the period,
coupled with a 38% decrease in underlying
sales volumes.
As noted above, production volumes decreased
in H1 2016 primarily due to the cessation
of production from the Athena and Anglia
fields as well as reduced production on
the Cook field and natural decline in
the Causeway Area. Sales volumes were
down primarily due to the timing of liftings
on the Cook and Pierce fields.
In terms of average realised oil prices,
there was a decrease to $40/bbl in H1
2016 from $60/bbl in H1 2015. The average
Brent price for the six months ended 30
June 2016 was $40/bbl compared to $58/bbl
for H1 2015. As noted above, the Company's
realised oil prices do not strictly follow
the Brent price pattern. The decrease
in realised oil price was partially offset
by a realised hedging gain of $38 per
sales barrel of oil equivalent in the
period.
3-Months Ended 6-Months Ended
30 June 30 June
Average Realised 2016 2015 2016 2015
Price
Oil Pre-Hedging $/bbl 46 62 40 60
Oil Post-Hedging $/bbl 65 96 63 84
COST OF SALES
--------------------------------------------------------------------
3-Months Ended 6-Months Ended
30 June 30 June
$'000 2016 2015 2016 2015
Operating Expenditure 21,848 29,499 42,033 57,622
DD&A 19,776 31,702 37,384 62,259
Movement in Oil
& Gas Inventory (17,314) (3,068) (10,990) 13,123
Total 24,310 58,133 68,427 133,004
THREE MONTHSED 30 JUNE 2016
Cost of sales decreased in Q2 2016 by
approximately 60% to $24.3 million (Q2
2015: $58.1 million). This was attributable
to decreases in operating costs, depletion,
depreciation and amortisation ("DD&A")
and movement in oil and gas inventory.
OPERATING EXPITURE
Reported operating costs decreased by
26% in the quarter to $21.8 million (Q2
2015: $29.5 million). Cost reductions
were achieved across the portfolio, with
the Cook and Wytch Farm fields in particular
delivering the most significant savings.
This continued focus on driving down costs
delivered a unit operating cost of $25/boe
for Q2 2016, representing a reduction
of 32% compared to the equivalent rate
of $37/boe for Q2 2015 and 17% ahead of
2016 guidance levels of $30/boe prior
to first oil from the Stella field.
DD&A
The unit DD&A rate for the quarter decreased
to $22/boe (Q2 2015: $27/boe), resulting
in a total DD&A expense for the period
of $19.8 million (Q2 2015: $31.7 million).
This reduction in expense was due to a
combination of lower production in the
quarter compared to the same period in
2015 and impairment write downs booked
in Q4 2015 as a result of the change in
the oil price environment, which also
lowered average DD&A/boe rates.
MOVEMENT IN INVENTORY
An oil and gas inventory movement of $17.3
million was credited to cost of sales
in Q2 2016 (Q2 2015: credit of $3.1 million).
This credit arose as a result of an underlift
in the quarter, predominantly due to the
build-up of inventory on the Cook and
Pierce fields, combined with an over 30%
increase in the valuation of all inventory
held due to the increase in oil prices
in the quarter.
SIX MONTHSED 30 JUNE 2016
Cost of sales decreased in H1 2016 to
$68.4 million (H1 2015: $133.0 million)
due to decreases in operating costs, DD&A
and the movement in oil and gas inventory.
OPERATING EXPITURE
Operating costs decreased in the period
to $42.0 million (H1 2015: $57.6 million)
primarily as a result of the previously
noted effect of cost savings achieved
across the portfolio as a consequence
of the supply chain cost reduction initiatives.
DD&A
DD&A for the period decreased to $37.4
million (H1 2015: $62.3 million). As noted
above, this decrease was primarily due
to a combination of lower production and
the impact of the write downs booked in
2015 as a consequence of the change in
oil price environment.
MOVEMENT IN INVENTORY
An oil and gas inventory movement of $11.0
million was credited to cost of sales
in H1 2016 (H1 2015: charge of $13.1 million).
In H1 2016 more barrels of oil were produced
(1,577 kbbls) than sold (1,391 kbbls),
mainly due to the timing of Cook, Dons
and Pierce field liftings, resulting in
an underlift position and associated build-up
in inventory. This inventory build combined
with an over 20% increase in valuation
of inventory to generate a credit to the
income statement.
Movement in Oil Gas Total
Operating kbbls kboe kboe
Oil & Gas Inventory
Opening inventory 472 (3) 469
Production 1,577 130 1,707
Liftings/sales (1,391) (130) (1,521)
Transfers/other 2 - 2
Closing volumes 660 (3) 657
ADMINISTRATION EXPENSES AND EXPLORATION
& EVALUATION EXPENSES
---------------------------------------------------------------
3-Months 6-Months
Ended 30 Ended 30
June June
$'000 2016 2015 2016 2015
General & Administration
("G&A") 1,302 1,697 2,960 5,102
Share Based Payments
("SBP") 220 209 331 389
Total Administration
Expenses 1,522 1,906 3,291 5,491
Exploration &
Administration Evaluation ("E&E")
expenses reduced write off 399 28,057 819 29,101
through on-going
cost reduction
measures THREE MONTHSED 30 JUNE 2016
ADMINISTRATION EXPENSES
Total administration expenses were reduced
by 20% to $1.5 million in Q2 2016 (Q2
2015: $1.9 million). This was largely
attributable to the sale of the Norwegian
operations in July 2015 as well as a continued
focus on cost saving initiatives across
the business. Costs incurred in the quarter
reflect further reductions in contractor
rates and a decrease in both employee
and contractor numbers from Q2 2015.
E&E EXPENSES
A minor write off of E&E assets was made
at the period end relating to non-commercial
prospects. The 2015 comparative reflects
the write off of the Snømus well
costs drilled as part of the since disposed
Norwegian operations.
SIX MONTHSED 30 JUNE 2016
Total administrative expenses decreased
in the period to $3.3 million (H1 2015:
$5.5 million) primarily due to the cost
saving drive initiated as a result of
the lower oil price environment as well
as the abovementioned absence of Norwegian
administrative expenses.
FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS
---------------------------------------------------------------------------
3-Months 6-Months
Ended 30 Ended 30
June June
$'000 2016 2015 2016 2015
Gain / (Loss) on Foreign
Exchange 405 (2,513) 906 (4,009)
---------------------------- --------- --------- --------- ---------
Total Gain/(Loss) on
Foreign Exchange 405 (2,513) 906 (4,009)
---------------------------- --------- --------- --------- ---------
Revaluation Forex Forward
Contracts (4,058) 6,665 (5,278) 5,039
Revaluation of Interest
Rate Swaps 52 (23) 43 (265)
Revaluation of Other
Liability - - - 307
Revaluation of Commodity
Hedges (47,582) (48,303) (79,918) (96,297)
---------------------------- --------- --------- --------- ---------
Total Revaluation (Loss) (51,588) (41,661) (85,153) (91,216)
---------------------------- --------- --------- --------- ---------
Realised (Loss)/Gain
on Forex Contracts (532) 607 (951) 607
Realised Gain on Commodity
Hedges 18,824 31,330 57,987 110,106
Realised (Loss) on
Interest Rate swaps (157) (107) (157) (206)
Total Realised Gain 18,135 31,830 56,879 110,507
---------------------------- --------- --------- --------- ---------
Total Foreign Exchange
& Financial Instruments (33,048) (12,344) (27,368) 15,283
---------------------------- --------- --------- --------- ---------
THREE MONTHSED 30 JUNE 2016
FOREIGN EXCHANGE
While the majority of the Company's revenue
is US dollar denominated, expenditures
are predominantly incurred in British
pounds (some US dollar and Euro denominated
costs are also incurred). Consequently,
general volatility in the GBP:USD exchange
rate is the primary factor underlying
foreign exchange gains and losses.
In Q2 2016, a modest foreign exchange
gain of $0.4 million was recorded (Q2
2015: $2.5 million loss). This was driven
by the GBP:USD exchange rate moving from
1.44 at 1 April 2016 to 1.34 at 30 June
2016 and fluctuations throughout the quarter
of between 1.33 and 1.48.
FINANCIAL INSTRUMENTS
The Company recorded an overall loss of
$33.5 million on financial instruments
for the quarter ended 30 June 2016 (Q2
2015: $9.8 million loss).
An $18.1 million realised gain was made
in Q2 2016. This comprised a $9.3 million
gain on oil hedges maturing during the
quarter (at an average exercise price
of $63/bbl compared to an average Brent
price of $46/bbl) and a $9.5 million gain
on gas hedges (at an average price of
58p/therm compared to an average NBP price
of 31p/therm), partially offset by a $0.7
million loss on foreign exchange and interest
rate instruments. The total realised gain
of $18.1 million in the period was offset
by a $51.6 million negative revaluation
of instruments as at 30 June 2016. This
resulted from a negative revaluation of
oil hedges of $23.6 million, gas hedges
of $24.0 million and other hedges of $4.0
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 $23.6 million negative revaluation
of oil hedges was due to a combination
of the realisation of hedged oil volumes
during the quarter (i.e. the transfer
of previously unrealised gains to realised
gains), coupled with a decrease in the
value of the remaining oil hedges at the
end of Q2 2016 as a result of an increase
in the oil price forward curve from 31
March 2016 to 30 June 2016. The $24.0
million negative revaluation of gas hedges
arises in the same way, being a combination
of realisations during the quarter and
a negative revaluation of the remaining
gas hedges at the end of Q2 2016 due to
an increase in the gas forward curve in
the three months to 30 June 2016.
SIX MONTHSED 30 JUNE 2016
FOREIGN EXCHANGE
A modest foreign exchange gain of $0.9
million was recorded in H1 2016 (H1 2015:
$4.0 million loss) primarily due to volatility
in the GBP:USD exchange rate, with fluctuations
between 1.33 and 1.48 during the period
and a closing rate of 1.34 on 30 June
2016.
FINANCIAL INSTRUMENTS
The Company recorded an overall $28.3
million loss on financial instruments
for the six month period ended 30 June
2016 (H1 2015: $19.0 million gain).
A $58.0 million gain was recorded in respect
of realised commodity hedges, comprising
$32.1 million on oil hedges and $25.9
million on gas hedges maturing during
the period.
Offsetting the realised gain was the revaluation
of instruments as at 30 June 2016, which
values instruments still held at quarter
end. This $85.2 million revaluation related
to a negative revaluation of oil hedges
of $43.1 million, a negative revaluation
of gas hedges of $36.9 million and a negative
revaluation of foreign exchange and interest
rate instruments of $5.2 million. The
loss on commodity instruments was primarily
due to the realisation of the amounts
noted above (i.e. where they are no longer
still held at the period end), combined
with a decrease in value of the remaining
swaps based on the movement in the forward
curve from the start of the year to the
end of the reporting period.
As of 1 July 2016, the Company's commodity
hedges were valued at $46.6 million, $25.6
million for oil hedges and $21.0 million
for gas hedges, based on valuations relative
to the respective oil and gas forward
curves. This asset is partly offset by
a liability relating to the value of foreign
exchange and interest rate hedging instruments
held at the period end of $5.3 million.
FINANCE COSTS
------------------------------------------------------------------------
3-Months 6-Months
Ended 30 Ended 30
June June
Reducing finance $'000 2016 2015 2016 2015
cost profile Bank interest and
driven by charges (1,131) (2,117) (2,283) (4,627)
decreasing Senior notes interest (3,830) (3,444) (7,659) (7,349)
net debt Finance lease interest (250) (264) (504) (530)
Non-operated asset
finance fees (7) (27) (12) (51)
Prepayment interest (782) (781) (1,404) (781)
(1,
Loan fee amortisation (1,040) 881) (2,080) (3,058)
Accretion (2,294) (2,261) (4,567) (4,499)
Total Finance
Costs (9,334) (10,775) (18,507) (20,895)
THREE MONTHSED 30 JUNE 2016
Finance costs decreased to $9.3 million
in Q2 2016 (Q2 2015: $10.8 million). This
reduction is primarily attributable to
the decrease in RBL bank interest resulting
from the significant deleveraging of the
business over the last twelve months,
with drawn bank debt having fallen from
$513 million at 30 June 2015 to $332 million
at 30 June 2016. All other finance costs
have remained relatively stable quarter
on quarter.
SIX MONTHSED 30 JUNE 2016
Finance costs decreased to $18.5 million
in H1 2016 (H1 2015: $20.9 million). As
noted above, this reduction primarily
reflects lower RBL interest costs as a
result of the reduced drawn debt.
TAXATION
-------------------------------------------------------------------
3-Months Ended 6-Months Ended
30 June 30 June
$'000 2016 2015 2016 2015
UK & Norway Corporation
Tax - excluding
Rate Changes 32,614 67,651 42,693 75,694
Impact of Change
in Tax Rates - - 24,155 (41,501)
Petroleum Revenue
Tax - (847) - (1,990)
Total Taxation 32,614 66,714 66,848 32,203
No UK tax
anticipated
to be payable THREE MONTHSED 30 JUNE 2016
prior to 2020 A tax credit of $32.6 million was recognised
in the three months ended 30 June 2016
(Q2 2015: $66.7 million credit). Significant
components of the $32.6 million Corporation
Tax ("CT") credit include a $15.2 million
credit relating to the UK Ring Fence Expenditure
Supplement and $8.1 million in respect
of additional capital allowances recognised
in relation to Stella for expenditure
incurred by Ithaca but paid by Petrofac
(refer to note 24 in the Q2 2016 Consolidated
Financial Statements).
The Q2 2015 UK and Norway credit included
adjustments to the tax charge relating
to the UK Ring Fence Expenditure Supplement
and additional Stella related capital
allowances as above and also incorporated
the non-taxable gain on disposal of Norway.
As a result of the above factors, the
Q2 2016 loss before tax of $44.1 million
becomes a loss after tax of $11.5 million
(Q2 2015: $39.9 million loss).
SIX MONTHSED 30 JUNE 2016
A tax credit of $66.8 million was recognised
in the six months ended 30 June 2016 (H1
2015: $32.2 million credit). Significant
components of the $42.7 million Corporation
Tax ("CT") credit include a $29.4 million
credit relating to the UK Ring Fence Expenditure
Supplement and $11.7 million in respect
of additional capital allowances recognised
in relation to Stella for expenditure
incurred by Ithaca but paid by Petrofac
(refer to note 24 in the Q2 2016 Consolidated
Financial Statements), offset by the impact
of the removal of PRT on CT of $11.1 million.
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
in H1 2016.
Further, it was also announced in the
UK Budget that the Supplementary Charge
in respect of ring fence trades ("SCT")
will 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 will reduce the net
deferred tax assets by approximately $87
million and is expected to impact the
financial statements in the second half
of 2016 when the rate change is enacted.
Note that the H1 2015 comparative contains
a charge of $41.5 million relating to
the previous changes in the Supplementary
charge and PRT rates enacted in Q1 2015.
CAPITAL INVESTMENTS
===========================================
$'000 Additions
2016 capital H1 2016
investment Development & Production
programme ("D&P") 27,919
primarily Exploration & Evaluation
focused on ("E&E") 1,137
GSA development Other Fixed Assets 3
activities Total 29,059
Capital additions in H1 2016 totalled
$29.1 million, with the major component
being development and production ("D&P")
assets. Excluding capitalised interest
costs and non-cash additions relating
to decommissioning, capital expenditure
was approximately $15.2 million. This
mainly related to activities on the GSA.
WORKING CAPITAL
---------------------------------------------------------------------------
$'000 30 Jun. 31 Dec. Increase
2016 2015 / (Decrease)
Cash & Cash Equivalents 25,852 11,543 14,309
Trade & Other Receivables 260,834 223,749 37,085
Inventory 31,802 20,900 10,902
Derivative Financial
Instruments (current) 41,308 126,887 (85,579)
Trade & Other Payables (323,398) (275,907) (47,491)
Net Working Capital* 36,398 107,172 (70,774)
*Working capital being total current assets
less trade and other payables
As at 30 June 2016 Ithaca had a net working
capital balance of $36.4 million, including
an unrestricted cash balance of $25.9
million held with BNP Paribas. Substantially
all of the accounts receivable are current,
being defined as less than 90 days. The
Company regularly monitors all receivable
balances outstanding in excess of 90 days.
No credit loss has historically been experienced
in the collection of accounts receivable.
Working capital movements are driven by
the timing of receipts and payments of
balances and fluctuate in any given quarter.
A significant proportion of Ithaca's accounts
receivable balance is with customers and
co-venturers in the oil and gas industry
and is subject to normal joint venture/industry
credit risks.
Net working capital has decreased over
the six month period to 30 June 2016 mainly
as a result of a reduction in the commodity
hedging instrument asset values of $86
million noted above, offset by a build
in inventory.
CAPITAL RESOURCES
-------------------------------------------------------------
DEBT FACILITIES
As at 30 June 2016, the Company has debt
Over $120 facilities totalling $535 million ($475
million funding million senior RBL Facility and $60 million
headroom with junior RBL), following the voluntary reduction
net debt reduced in the facilities size from a total of
to $606 million $650 million (see "Corporate Activities"
at end Q2 above). The Company has funding headroom
2016 of over $120 million following the completion
of the April 2016 RBL redetermination
process where bank debt capacity was set
at over $430 million. The facilities are
both due September 2018. The Company also
has $300 million senior unsecured notes,
due July 2019.
The Company's debt facilities are expected
to be sufficient to ensure that adequate
financial resources are available to cover
anticipated future commitments when combined
with existing cash balances and forecast
cashflow from operations. As noted above,
the bank debt facilities are subject to
semi-annual redeterminations of available
debt capacity using forward looking assumptions,
of which future oil and gas prices are
a key component. Movements in forecast
commodity prices can therefore have a
significant impact on available debt capacity
and limit the Company's ability to borrow.
The Company was in compliance with all
its relevant financial and operating covenants
during the quarter. The key covenants
in the senior and junior RBL facilities
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 H1 2016 CASHFLOW MOVEMENTS
inflow and During the six months ended 30 June 2016
reduction there was a cash inflow from operating,
in net debt investing and financing activities of
delivered approximately $14.3 million (H1 2015 inflow
in H1 2016 of $6.0 million).
Cashflow from operations
Cash generated from operating activities
was $81.6 million. Revenues from the producing
asset portfolio were bolstered by the
substantial hedging programme in place,
while operating costs reduced by almost
30% period on period.
Cashflow from financing activities
Cash used in financing activities was
$46.1 million, being primarily repayments
of the debt facilities during the period.
Cashflow from investing activities
Cash used in investing activities was
$27.3 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 240 180 -
Licence Fees 607 - -
Engineering 30,647 - -
Total 31,494 180 -
The Company's commitments relate primarily
to completion of the capital investment
programme on the GSA development, along
with other on-going operational commitments
across the portfolio. Given the highly
advanced status of the GSA development,
these commitments are relatively modest
and are forecast to be funded from the
operating cashflows of the business.
FINANCIAL INSTRUMENTS
---------------------------------------------------------------------
All financial instruments are initially
measured in the balance sheet at fair
value. Subsequent measurement of the financial
instruments is based on their classification.
The Company has classified each financial
instrument into one of these categories:
Financial 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 30 June
2016.
COMMODITIES
The following table summarises the commodity
hedges in place at 30 June 2016.
Derivative Term Volume Average
bbl Price
$/bbl
July 2016 -
Oil Swaps June 2017 1,464,427 68
Derivative Term Volume Average
Therms Price
p/therm
July 2016 -
Gas Puts June 2017 86,800,000 62
July 2016 -
Gas Swaps March 2017 4,658,321 47
FOREIGN EXCHANGE
The Company enters into forward contracts
as a means of hedging its exposure to
foreign exchange rate risks. As at the
end of the quarter, the Company had the
following hedged position:
Instrument Value Rate Term
Forward contracts GBP31.2 1.47 July -
million Dec 2016
Swaps GBP4.8 1.47 July 2016
million
------------------ --------- ----- ----------
INTEREST RATES
The Company enters into interest rate
swaps as a means of hedging its exposure
to interest rate risks on the loan facilities.
As at the end of the quarter, the Company
had hedged interest payments on $50 million
of drawn debt at 1.24% for the period
to December 2016.
QUARTERLY RESULTS SUMMARY
-------------------------------------------------------------------------------------------------------
$'000 30 31 31 30 30 31 31 30
Jun Mar Dec Sep Jun Mar Dec Sep
2016 2016 2015 2015 2015 2015 2014 2014
Revenue 24,511 33,250 35,340 42,108 59,125 70,375 88,928 90,094
Profit/(Loss)
After
Tax (11,468) 17,712 (177,625) 42,812 39,888 (26,078) (49,517) 7,954
Earnings
per share
"EPS"
- Basic(1) (0.03) 0.04 (0.35) 0.13 0.12 (0.08) (0.15) 0.02
EPS -
Diluted(1) (0.03) 0.04 (0.35) 0.13 0.12 (0.08) (0.15) 0.02
Common
shares
outstanding
(000) 411,784 411,384 411,384 329,519 329,519 329,519 329,519 329,519
--------------- --------- -------- ---------- -------- -------- --------- --------- --------
(1) Based on weighted average number of
shares
The most significant factors to have affected
the Company's results during the above
quarters are fluctuations in underlying
commodity prices and movement in production
volumes. The Company has utilised hedging
and foreign exchange contracts to take
advantage of higher commodity prices and
beneficial exchange rates and reduce its
exposure to volatility associated with
these key factors. However, these contracts
can cause volatility in profit after tax
as a result of unrealised gains and losses
due to movements in the oil price and
GBP:USD exchange rate. In addition, the
significant reduction in underlying commodity
prices over the period has resulted in
impairment write downs in Q4 2014 and
Q4 2015.
OUTSTANDING SHARE INFORMATION
-------------------------------------------------------------------
The Company's common shares are traded
on the Toronto Stock Exchange ("TSX")
in Canada and on the Alternative Investment
Market ("AIM") in the United Kingdom,
both under the symbol "IAE".
As at 30 June 2016 Ithaca had 411,784,045
common shares outstanding along with 28,746,470
options outstanding to employees and directors
to acquire common shares.
30 June
2016
Common Shares Outstanding 411,784,045
Share Price((1) $0.96 /
Share
Total Market Capitalisation $395,312,683
(1) Represents the TSX close price (CAD$1.25)
on 30 June 2016. US$:CAD$ 0.77 on 30 June2016
CONSOLIDATION
==============================================
The consolidated financial statements
of the Company and the financial data
contained in this management's discussion
and analysis ("MD&A") are prepared in
accordance with IFRS.
The consolidated financial statements
include the accounts of Ithaca and its
wholly--owned subsidiaries, listed below,
and its associates FPU Services Limited
("FPU") and FPF--1 Limited ("FPF--1").
Wholly owned subsidiaries:
* Ithaca Energy (Holdings) Limited
* Ithaca Energy (UK) Limited
* Ithaca Minerals North Sea Limited
* Ithaca Energy Holdings (UK) Limited
* Ithaca Petroleum Limited
* Ithaca Causeway Limited
* Ithaca Exploration Limited
* Ithaca Alpha (NI) Limited
* Ithaca Gamma Limited
* Ithaca Epsilon Limited
* Ithaca Delta Limited
* Ithaca North Sea Limited
* Ithaca Petroleum Norge AS*
* Ithaca Petroleum Holdings AS
* Ithaca Technology AS
* Ithaca AS
* Ithaca Petroleum EHF
* Ithaca SPL Limited
* Ithaca SP UK Limited
* Ithaca Dorset Limited
* Ithaca Pipeline Limited
All inter--company transactions and balances
have been eliminated on consolidation.
A significant portion of the Company's
North Sea oil and gas activities are carried
out jointly with others. The consolidated
financial statements reflect only the
Company's proportionate interest in such
activities.
* Following the sale of the Company's
Norwegian operations in Q2 2015, Ithaca
Petroleum Norge AS has been divested and
as of Q3 2015, no longer features in the
financial results of the Company.
CRITICAL ACCOUNTING ESTIMATES
--------------------------------------------------
Certain accounting policies require that
management make appropriate decisions
with respect to the formulation of estimates
and assumptions that affect the reported
amounts of assets, liabilities, revenues
and expenses. These accounting policies
are discussed below and are included to
aid the reader in assessing the critical
accounting policies and practices of the
Company and the likelihood of materially
different results being reported. Ithaca's
management reviews these estimates regularly.
The emergence of new information and changed
circumstances may result in actual results
or changes to estimated amounts that differ
materially from current estimates.
The following assessment of significant
accounting policies and associated estimates
is not meant to be exhaustive. The Company
might realize different results from the
application of new accounting standards
promulgated, from time to time, by various
rule-making bodies.
Capitalised costs relating to the exploration
and development of oil and gas reserves,
along with estimated future capital expenditures
required in order to develop proved and
probable reserves are depreciated on a
unit-of-production basis, by asset, using
estimated proved and probable reserves
as adjusted for production.
A review is carried out each reporting
date for any indication that the carrying
value of the Company's D&P and E&E assets
may be impaired. For assets where there
are such indications, an impairment test
is carried out on the Cash Generating
Unit ("CGU"). Each CGU is identified in
accordance with IAS 36. The Company's
CGUs are those assets which generate largely
independent cash flows and are normally,
but not always, single developments or
production areas. The impairment test
involves comparing the carrying value
with the recoverable value of an asset.
The recoverable amount of an asset is
determined as the higher of its fair value
less costs of disposal and value in use,
where the value in use is determined from
estimated future net cash flows. Any additional
depreciation resulting from the impairment
testing is charged to the Statement of
Income.
Goodwill is tested annually for impairment
and also when circumstances indicate that
the carrying value may be at risk of being
impaired. Impairment is determined for
goodwill by assessing the recoverable
amount of each CGU to which the goodwill
relates. Where the recoverable amount
of the CGU is less than its carrying amount,
an impairment loss is recognised in the
Statement of Income. Impairment losses
relating to goodwill cannot be reversed
in future periods.
Recognition of decommissioning liabilities
associated with oil and gas wells are
determined using estimated costs discounted
based on the estimated life of the asset.
In periods following recognition, the
liability and associated asset are adjusted
for any changes in the estimated amount
or timing of the settlement of the obligations.
The liability is accreted up to the actual
expected cash outlay to perform the abandonment
and reclamation. The carrying amounts
of the associated assets are depleted
using the unit of production method, in
accordance with the depreciation policy
for development and production assets.
Actual costs to retire tangible assets
are deducted from the liability as incurred.
All financial instruments are initially
recognised at fair value on the balance
sheet. The Company's financial instruments
consist of cash, accounts receivable,
deposits, derivatives, accounts payable,
accrued liabilities, contingent consideration
and borrowings. Measurement in subsequent
periods is dependent on the classification
of the respective financial instrument.
In order to recognise share based payment
expense, the Company estimates the fair
value of stock options granted using assumptions
related to interest rates, expected life
of the option, volatility of the underlying
security and expected dividend yields.
These assumptions may vary over time.
The determination of the Company's income
and other tax liabilities / assets requires
interpretation of complex laws and regulations.
Tax filings are subject to audit and potential
reassessment after the lapse of considerable
time. Accordingly, the actual income tax
liability may differ significantly from
that estimated and recorded on the financial
statements.
The accrual method of accounting will
require management to incorporate certain
estimates of revenues, production costs
and other costs as at a specific reporting
date. In addition, the Company must estimate
capital expenditures on capital projects
that are in progress or recently completed
where actual costs have not been received
as of the reporting date.
CONTROL ENVIRONMENT
---------------------------------------------------
The Chief Executive Officer and Chief
Financial Officer evaluated the effectiveness
of the Company's disclosure controls and
procedures as at 30 June 2016, and concluded
that such disclosure controls and procedures
are effective to ensure that information
required to be disclosed by the Company
in its annual filings, interim filings
and other reports filed or submitted under
securities legislation is recorded, processed,
summarised and reported within the time
periods specified in the securities legislation
and such information is accumulated and
communicated to the Company's management,
including its certifying officers, as
appropriate to allow timely decisions
regarding required disclosures.
The Chief Executive Officer and Chief
Financial Officer have designed, or have
caused such internal controls over financial
reporting to be designed under their supervision,
to provide reasonable assurance regarding
the reliability of financial reporting
and preparation of the Company's financial
statements for external purposes in accordance
with IFRS including those policies and
procedures that:
(a) pertain to the maintenance of records
that in reasonable detail accurately and
fairly reflect the transactions and dispositions
of the Company's assets;
(b) are designed to provide reasonable
assurance that transactions are recorded
as necessary to permit preparation of
financial statements in accordance with
IFRS, and that receipts and expenditures
of the Company are being made only in
accordance with authorisations of management
and directors of the Company; and
(c) are designed to provide reasonable
assurance regarding prevention or timely
detection of unauthorised acquisition,
use or disposition of the Company's assets
that could have a material effect on the
annual financial statements or interim
financial statements.
The Chief Executive Officer and Chief
Financial Officer performed an assessment
of internal control over financial reporting
as at 30 June 2016, based on the criteria
established in Internal Control - Integrated
Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway
Commission ("COSO"), and concluded that
internal control over financial reporting
is effective with no material weaknesses
identified.
Based on their inherent limitations, disclosure
controls and procedures and internal controls
over financial reporting may not prevent
or detect misstatements and even those
options determined to be effective can
provide only reasonable assurance with
respect to financial statement preparation
and presentation.
As of 30 June 2016, there were no changes
in the Company's internal control over
financial reporting that occurred during
the quarter ended 30 June 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 30 June 2016, finance lease assets
of $29.6 million and related liabilities
of $29.9 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 Q2 2016 was $0.0 million (Q2 2015:
$0.0 million). These transactions are
in the normal course of business and are
conducted on normal commercial terms with
consideration comparable to those charged
by third parties.
As at 30 June 2016 the Company had loans
receivable from FPF-1 Limited and FPU
Services Limited, associates of the Company,
for $60.2 million and $0.1 million, respectively
(30 June 2015: $58.8 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 and resources
Resources stated herein for individual properties
may not reflect the same confidence level
as estimates of reserves and resources
for all properties, due to the effects
of aggregation.
The Company's total proved and probable
reserves at 31 December 2015 plus the
estimated reserves associated with the
Vorlich licence acquisition from TOTAL,
which completed in July 2016, were 57
MMboe. These reserves were independently
assessed by Sproule, a qualified reserves
evaluator, as of December 31, 2015 in
accordance with the Canadian Oil and Gas
Evaluation Handbook maintained by the
Society of Petroleum Engineers (Calgary
Chapter), as amended from time to time.
The Vorlich field interest and estimated
reserves reflect assumed unitisation across
licences P1588 and P363. Estimates of
the gross 1C to 3C contingent resource
(Development Pending) range associated
with the Austen discovery have been prepared
by Ithaca, effective as of 1 July 2016,
and not by an independent qualified reserves
evaluator or assessor. These figures are
estimates only and the actual results
may be greater than or less than the estimates
provided herein, with the resource range
reflecting uncertainties and risks associated
with compartmentalisation of the reservoir.
There is no certainty that it will be
commercially viable to produce any portion
of these resources.
--------------------------------------------------
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 2015, (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,
predominantly in relation to oil production,
as a means of establishing a floor in
realised prices.
---------------------------------------------------
Foreign Exchange RISK: The Company is exposed to financial
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
Stella 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.
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, depending on the field, to either
Shell Trading International Ltd or BP
Oil International Limited. Gas production
is sold through contracts with Hartree
Partners Power and Gas Company (UK) Limited,
Shell UK Ltd. and Esso Exploration & Production
UK Ltd. Each of these parties has historically
demonstrated their ability to pay amounts
owing to Ithaca.
----------------------------------------------------
Property Risk RISK: The Company's properties will be
generally held in the form of licences,
concessions, permits and regulatory consents
("Authorisations"). The Company's activities
are dependent upon the grant and maintenance
of appropriate Authorisations, which may
not be granted; may be made subject to
limitations which, if not met, will result
in the termination or withdrawal of the
Authorisation; or may be otherwise withdrawn.
Also, in the majority of its licences,
the Company is a joint interest-holder
with other third parties over which it
has no control. An Authorisation may be
revoked by the relevant regulatory authority
if the other interest-holder is no longer
deemed to be financially credible. There
can be no assurance that any of the obligations
required to maintain each Authorisation
will be met. Although the Company believes
that the Authorisations will be renewed
following expiry or granted (as the case
may be), there can be no assurance that
such authorisations will be renewed or
granted or as to the terms of such renewals
or grants. The termination or expiration
of the Company's Authorisations may have
a material adverse effect on the Company's
results of operations and business.
MITIGATIONS: The Company has routine ongoing
communications with the UK oil and gas
regulatory body, the Department of Energy
and Climate Change ("DECC") as well as
Norwegian authorities. Regular communication
allows all parties to an Authorisation
to be fully informed as to the status
of any Authorisation and ensures the Company
remains updated regarding fulfilment of
any applicable requirements.
----------------------------------------------------
Operational RISK: 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 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 ("Sproule") 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 offshore incident
Risk were to occur in respect of a property
in which the Company has an interest,
the Company's reputation could be severely
harmed
MITIGATIONS: The Company's operational
activities are conducted in accordance
with approved policies, standards and
procedures, which are then passed on to
the Company's subcontractors. In addition,
Ithaca regularly audits its operations
to ensure compliance with established
policies, standards and procedures.
---------------------------------------------------
FORWARD-LOOKING INFORMATION
----------------------------------------------------------------
Forward-Looking This MD&A and any documents incorporated
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", "approximately" and similar
expressions are intended to identify forward-looking
statements and forward-looking information.
These statements are not guarantees of
future performance and involve known and
unknown risks, uncertainties and other
factors that may cause actual results
or events to differ materially from those
anticipated in such forward-looking statements
or information. The Company believes that
the expectations reflected in those forward-looking
statements and information are reasonable
but no assurance can be given that these
expectations, or the assumptions underlying
these expectations, will prove to be correct
and such forward-looking statements and
information included in this MD&A and
any documents incorporated by reference
herein should not be unduly relied upon.
Such forward-looking statements and information
speak only as of the date of this MD&A
and any documents incorporated by reference
herein and the Company does not undertake
any obligation to publicly update or revise
any forward-looking statements or information,
except as required by applicable laws.
In particular, this MD&A and any documents
incorporated by reference herein, contains
specific forward-looking statements and
information pertaining to the following:
* The quality of and future net revenues from the
Company's reserves;
* Oil, natural gas liquids ("NGLs") and natural gas
production levels;
* Commodity prices, foreign currency exchange rates and
interest rates;
* Capital expenditure programs and other expenditures;
* Future operating costs;
* The sale, farming in, farming out or development of
certain exploration properties using third party
resources;
* Supply and demand for oil, NGLs and natural gas;
* The Company's ability to raise capital and the
potential sources thereof;
* The continued availability of the Facilities;
* Funding requirements prior to Stella start up;
* The sufficiency of the Facilities, cash balances and
forecast cash flow to cover anticipated future
commitments;
* Expected future net debt and continued deleveraging;
* The timing of Stella first hydrocarbons;
* Stella production ramp up time following first
hydrocarbons;
* Stella commissioning, offshore hook up and drilling
plans;
* The Company's acquisition and disposition strategy,
the criteria to be considered in connection therewith
and the benefits to be derived therefrom;
* The realisation of anticipated benefits from
acquisitions and dispositions;
* The anticipated effects of securing access to the GSA
oil export pipeline;
* The 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 planned independent assessment of the Austen
property;
* 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;
* 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;
* 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;
* Risks associated with satisfying conditions to
closing acquisitions and dispositions;
* Risks associated with realisation of anticipated
benefits of acquisitions and dispositions;
* Risks related to changes to government policy with
regard to offshore drilling;
* The Company's reliance on key operational and
management personnel;
* The ability of the Company to obtain and maintain all
of its required permits and licences;
* Competition for, among other things, capital,
drilling equipment, acquisitions of reserves,
undeveloped lands and skilled personnel;
* Changes in general economic, market and business
conditions in Canada, North America, the United
Kingdom, Europe and worldwide;
* Actions by governmental or regulatory authorities
including changes in income tax laws or changes in
tax laws, royalty rates and incentive programs
relating to the oil and gas industry including any
increase in UK or Norwegian taxes;
* Adverse regulatory or court rulings, orders and
decisions; and,
* Risks associated with the nature of the common
shares.
Additional The information in this MD&A is provided
Reader Advisories as of 12 August 2016. The Q2 2016 results
have been compared to the results of the
comparative period in 2015. This MD&A
should be read in conjunction with the
Company's unaudited consolidated financial
statements as at 30 June 2016 and 2015
together with the accompanying notes and
Annual Information Form ("AIF") for the
year ended 31 December 2015. These documents,
and additional information regarding Ithaca,
are available electronically from the
Company's website (www.ithacaenergy.com)
or SEDAR profile at www.sedar.com.
----------------------------------------------------------------
Consolidated Statement of Income
For the three and six months ended
30 June 2016 and 2015
(unaudited)
Three months Six months
ended 30 June ended 30 June
2016 2015 2016 2015
Note US$'000 US$'000 US$'000 US$'000
---------------------------- ---------- --------- ----------------- --------- ----------
Revenue 5 24,511 59,152 57,761 129,527
- Operating costs (21,848) (29,499) (42,033) (57,622)
- Movement in oil
and gas inventory 17,314 3,068 10,990 (13,123)
- Depletion, depreciation
and amortisation (19,776) (31,702) (37,384) (62,259)
---------------------------- ---------- --------- ----------------- --------- ----------
Cost of sales (24,310) (58,133) (68,427) (133,004)
Gross Profit/ (Loss) 201 1,019 (10,666) (3,477)
Exploration and evaluation
expenses 10 (399) (28,057) (819) (29,101)
Gain on disposal - 25,237 - 25,237
(Loss)/gain on financial
instruments 26 (33,453) (9,831) (28,274) 19,291
Administrative expenses 6 (1,522) (1,906) (3,291) (5,491)
Foreign exchange 405 (2,513) 906 (4,009)
Finance costs 7 (9,334) (10,775) (18,507) (20,895)
Interest income 20 - 49 50
---------------------------- ---------- --------- ----------------- --------- ----------
(Loss) Before Tax (44,082) (26,826) (60,602) (18,395)
Taxation 24 32,614 66,714 66,848 32,203
---------------------------- ---------- --------- ----------------- --------- ----------
(Loss)/ Profit After
Tax (11,468) 39,888 6,246 13,808
Earnings per share
Basic 23 (0.03) 0.12 0.02 0.04
Diluted 23 (0.03) 0.12 0.02 0.04
No separate statement of comprehensive income has been prepared as all such gains and losses have been incorporated in the consolidated statement of income above.
The accompanying notes on pages 6 to 22 are an integral part of the financial statements.
Consolidated Statement of Financial
Position
(unaudited)
30 June 31 December
2016 2015
US$'000
----------------------------- --------- ---------------------------------------------
Note US$'000
--------------------------- --------- -------------------- ---------- ----------- ------------
ASSETS
Current assets
Cash and cash equivalents 25,852 11,543
Accounts receivable 8 258,833 223,006
Deposits, prepaid expenses
and other 2,001 743
Inventory 9 31,802 20,900
Derivative financial
instruments 27 46,579 126,887
365,067 383,079
Non current assets
Long-term receivable 29 60,261 61,052
Long-term inventory 9 7,908 7,908
Investment in associate 13 18,337 18,337
Exploration and evaluation
assets 10 11,541 11,223
Property, plant & equipment 11 1,092,584 1,102,046
Deferred tax assets 420,654 355,726
Goodwill 12 123,510 123,510
----------------------------- --------- --------------------------------------------- ------------
1,734,795 1,679,802
Total assets 2,099,862 2,062,881
LIABILITIES AND EQUITY
Current liabilities
Trade and other payables 15 (323,398) (275,907)
Exploration obligation 16 (4,000) (4,000)
Contingent consideration 20 (4,000) (4,000)
Derivative financial
instruments 27 (5,271) -
--------------------------------------------- ------------
(336,669) (283,907)
Non current liabilities
Borrowings 14 (623,260) (666,130)
Decommissioning liabilities 17 (231,597) (226,915)
Other long term liabilities 18 (106,921) (92,543)
Derivative financial
instruments 27 - (197)
(961,778) (985,785)
Net Assets 801,415 793,189
----------------------------- --------- --------------------------------------------- ------------
Shareholders' equity
Share capital 21 617,721 617,375
Share based payment reserve 22 24,312 22,678
Retained earnings 159,382 153,136
------------
Total equity 801,415 793,189
----------------------------- --------- --------------------------------------------- ------------
The financial statements were approved by the Board
of Directors on 12 August 2016 and signed on its
behalf by:
"Les Thomas"
-----------------------------
Director
"Alec Carstairs"
-----------------------------
Director
The accompanying notes on pages 6 to 22
are an integral part of the financial statements.
Consolidated Statement
of Changes in Equity
(unaudited)
Share Share Retained Total
Capital based Earnings
payment
reserve
US$'000 US$'000 US$'000 US$'000
------------------------------ --------- -------------------- ---------- -----------
Balance, 1 Jan
2015 551,632 19,234 274,141 845,007
Share based payment - 2,018 - 2,018
Profit for the
period - - 13,808 13,808
Balance, 30 June
2015 551,632 21,252 287,949 860,833
------------------------------ --------- -------------------- ---------- -----------
Balance, 1 Jan
2016 617,375 22,678 153,136 793,189
Share based payment - 1,634 - 1,634
Shares exercised 346 - - 346
Profit for the
period - - 6,246 6,246
Balance, 30 June
2016 617,721 24,312 159,382 801,415
------------------------------ --------- -------------------- ---------- -----------
The accompanying notes on pages 6 to 22 are an integral part of the financial statements.
Consolidated Statement of Cash Flow
For the three and six months ended 30
June 2016 and 2015
(unaudited)
Three months Six months
ended 30 June ended 30 June
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
----------------------- --- -------------------------- ----------- --------------- -----------------
CASH PROVIDED BY
(USED IN):
Operating activities
Loss Before Tax (44,082) (26,826) (60,602) (18,395)
Adjustments for:
Depletion,
depreciation
and amortisation 11 19,776 31,702 37,384 62,259
Exploration and
evaluation
expenses 10 399 28,057 819 29,101
Onerous contracts - (8,611) - (20,002)
Share based
payment 21 220 209 331 389
Loan fee
amortisation 7 1,040 1,881 2,078 3,058
Revaluation of
financial
instruments 26 51,588 41,661 85,153 91,216
Gain on disposal - (25,237) - (25,237)
Accretion 17 2,294 2,261 4,567 4,499
Bank interest &
charges 6,000 6,632 11,861 13,339
------------------------ ------------------- --------- ----------- --------------- -----------------
Cashflow from
operations 37,235 51,729 81,591 140,227
------------------------ ------------------- --------- ----------- --------------- -----------------
Changes in inventory, receivables
and payables relating to
operating activities (1,604) (4,169) 393 25,086
Petroleum Revenue Tax refunded
/ ( paid) 324 (2,711) (916) (4,443)
Corporation Tax refunded - - 6,009 -
Net cash from operating
activities 35,955 44,849 87,079 110,698
------------------------ ------------------- --------- ----------- --------------- -----------------
Investing activities
Capital
expenditure (17,306) (57,700) (26,124) (117,946)
Loan to associate 316 (679) 1,001 (462)
Decommissioning 17 (128) - (2,165) -
Changes in receivables and
payables relating to investing
activities 7,131 (14,130) 1,335 (29,293)
--------------------------------------------- --------- ----------- --------------- -----------------
Net cash used in investing
activities (9,987) (72,509) (25,953) (147,701)
---------------------------- --------------- --------- ----------- --------------- -----------------
Financing activities
Proceeds from
issuance
of shares 346 - 346 -
Loan (repayment)/draw
down (20,000) 28,908 (45,000) 55,188
Bank interest and
charges (1,401) (1,732) (1,401) (11,311)
---------------------------- --------------- --------- ----------- --------------- -----------------
Net cash from financing
activities (21,055) 27,176 (46,055) 43,877
---------------------------- --------------- --------- ----------- --------------- -----------------
Currency translation
differences
relating to cash (920) (2) (760) (833)
Increase / (decrease) in
cash and cash equiv. 3,993 (486) 14,309 6,041
---------------------------- --------------- --------- ----------- ---------------
Cash and cash
equivalents,
beginning of period 21,859 25,909 11,543 19,381
Cash and cash equivalents,
end of period 25,852 25,423 25,852 25,423
---------------------------- --------------- --------- ----------- ---------------
The accompanying notes on pages 6 to 22 are an integral part of the financial statements.
1. NATURE OF OPERATIONS
Ithaca Energy Inc. (the "Corporation" or "Ithaca"), incorporated and domiciled in Alberta, Canada on 27 April 2004, is a publicly traded company involved in the development and production of oil and gas in the North Sea. The Corporation's registered office is 1600, 333 - 7th Avenue S.W., Calgary, Alberta, Canada, T2P 2Z1. The Corporation's shares trade on the Toronto Stock Exchange in Canada and the London Stock Exchange's Alternative Investment Market in the United Kingdom under the symbol "IAE".
2. BASIS OF PREPARATION
These interim consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) applicable to the preparation of interim financial statements, including IAS 34 Interim Financial Reporting. These interim consolidated financial statements do not include all the necessary annual disclosures in accordance with IFRS.
The policies applied in these condensed interim consolidated financial statements are based on IFRS issued and outstanding as of 12 August 2016, the date the Board of Directors approved the statements. Any subsequent changes to IFRS that are given effect in the Corporation's annual consolidated financial statements for the year ending 31 December 2016 could result in restatement of these interim consolidated financial statements.
The consolidated financial statements have been prepared on a going concern basis using the historical cost convention, except for financial instruments which are measured at fair value.
The consolidated financial statements are presented in US dollars and all values are rounded to the nearest thousand (US$'000), except when otherwise indicated.
The condensed interim consolidated financial statements should be read in conjunction with the Corporation's annual financial statements for the year ended 31 December 2015.
3. SIGNIFICANT ACCOUNTING POLICIES, JUDGEMENTS AND ESTIMATION UNCERTAINTY
Basis of measurement
The interim consolidated financial statements have been prepared under the historical cost convention, except for the revaluation of certain financial assets and financial liabilities (under IFRS) to fair value, including derivative instruments.
Basis of consolidation
The interim consolidated financial statements of the Corporation include the financial statements of Ithaca Energy Inc. and all wholly-owned subsidiaries as listed per note 29. Ithaca has twenty wholly-owned subsidiaries. All inter-company transactions and balances have been eliminated on consolidation.
Subsidiaries are all entities, including structured entities, over which the group has control. The group controls an entity when the group is exposed to or has rights to variable returns from its investments with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the group. They are deconsolidated on the date that control ceases.
Business Combinations
Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair value of the assets acquired, equity instruments issued and liabilities incurred or assumed at the date of completion of the acquisition. Acquisition costs incurred are expensed and included in administrative expenses. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the cost of acquisition over the fair value of the Corporation's share of the identifiable net assets acquired is recorded as goodwill. If the cost of the acquisition is less than the Corporation's share of the net assets acquired, the difference is recognised directly in the statement of income as negative goodwill.
Goodwill
Capitalisation
Goodwill acquired through business combinations is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised as the fair value of the Corporation's share of the identifiable net assets acquired and liabilities assumed. If this consideration is lower than the fair value of the identifiable assets acquired, the difference is recognised in the statement of income.
Impairment
Goodwill is tested annually for impairment and also when circumstances indicate that the carrying value may be at risk of being impaired. Impairment is determined for goodwill by assessing the recoverable amount of each cash generating unit ("CGU") to which the goodwill relates. Where the recoverable amount of the CGU is less than its carrying amount, an impairment loss is recognised in the statement of income. Impairment losses relating to goodwill cannot be reversed in future periods.
Interest in joint arrangements and associates
Under IFRS 11, joint arrangements are those that convey joint control which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. Associates are investments over which the Corporation has significant influence but not control or joint control, and generally holds between 20% and 50% of the voting rights.
Under the equity method, investments are carried at cost plus post-acquisition changes in the Corporation's share of net assets, less any impairment in value in individual investments. The consolidated statement of income reflects the Corporation's share of the results and operations after tax and interest.
The Corporation's interest in joint operations (eg exploration and production arrangements) are accounted for by recognising its assets (including its share of assets held jointly), its liabilities (including its share of liabilities incurred jointly), its revenue from the sale of its share of the output arising from the joint operation, its share of revenue from the sale of output by the joint operation and its expenses (including its share of any expenses incurred jointly).
Revenue
Oil, gas and condensate revenues associated with the sale of the Corporation's crude oil and natural gas are recognised when title passes to the customer. This generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism. Revenues from the production of oil and natural gas properties in which the Corporation has an interest with joint venture partners are recognised on the basis of the Corporation's working interest in those properties (the entitlement method). Differences between the production sold and the Corporation's share of production are recognised within cost of sales at market value.
Interest income is recognised on an accruals basis and is separately recorded on the face of the statement of income.
Foreign currency translation
Items included in the financial statements are measured using the currency of the primary economic environment in which the Corporation and its subsidiary operate (the 'functional currency'). The consolidated financial statements are presented in United States Dollars, which is the Corporation's functional and presentation currency.
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of income.
Share based payments
The Corporation has a share based payment plan as described in note 21 (c). The expense is recorded in the consolidated statement of income or capitalised for all options granted in the year, with the gross increase recorded in the share based payment reserve. Compensation costs are based on the estimated fair values at the time of the grant and the expense or capitalised amount is recognised over the vesting period of the options. Upon the exercise of the stock options, consideration paid together with the amount previously recognised in share based compensation reserve is recorded as an increase in share capital. In the event that vested options expire unexercised, previously recognised compensation expense associated with such stock options is not reversed. In the event that unvested options are forfeited or expired, previously recognised compensation expense associated with the unvested portion of such stock options is reversed.
Cash and Cash Equivalents
For the purpose of the statement of cash flow, cash and cash equivalents include investments with an original maturity of three months or less.
Financial Instruments
All financial instruments, other than those designated as effective hedging instruments, are initially recognised at fair value in the statement of financial position. The Corporation's financial instruments consist of cash, accounts receivable, deposits, derivatives, accounts payable, accrued liabilities, contingent consideration and borrowings. The Corporation classifies its financial instruments into one of the following categories: held-for-trading financial assets and financial liabilities; held-to-maturity investments; loans and receivables; and other financial liabilities. All financial instruments are required to be measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.
Held-for-trading financial instruments are subsequently measured at fair value with changes in fair value recognised in net earnings. All other categories of financial instruments are measured at amortised cost using the effective interest method. Cash and cash equivalents are classified as held-for-trading and are measured at fair value. Accounts receivable are classified as loans and receivables. Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classified as other financial liabilities. Although the Corporation does not intend to trade its derivative financial instruments, they are classified as held-for-trading for accounting purposes.
Transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability and original issue discounts on long-term debt have been included in the carrying value of the related financial asset or liability and are amortised to consolidated net earnings over the life of the financial instrument using the effective interest method.
Analysis of the fair values of financial instruments and further details as to how they are measured are provided in notes 26 to 28.
Inventory
Inventories of materials and product inventory supplies are stated at the lower of cost and net realisable value. Cost is determined on the first-in, first-out method. Current oil and gas inventories are stated at fair value less cost to sell. Non-current oil and gas inventories are stated at historic cost.
Trade receivables
Trade receivables are recognised and carried at the original invoiced amount, less any provision for estimated irrecoverable amounts.
Trade payables
Trade payables are measured at cost.
Property, Plant and Equipment
Oil and gas expenditure - exploration and evaluation assets
Capitalisation
Pre-acquisition costs on oil and gas assets are recognised in the statement of income when incurred. Costs incurred after rights to explore have been obtained, such as geological and geophysical surveys, drilling and commercial appraisal costs and other directly attributable costs of exploration and evaluation including technical, administrative and share based payment expenses are capitalised as intangible exploration and evaluation ("E&E") assets.
E&E costs are not amortised prior to the conclusion of evaluation activities. At completion of evaluation activities, if technical feasibility is demonstrated and commercial reserves are discovered then, following development sanction, the carrying value of the E&E asset is reclassified as a development and production ("D&P") asset, but only after the carrying value is assessed for impairment and where appropriate its carrying value adjusted. If after completion of evaluation activities in an area, it is not possible to determine technical feasibility and commercial viability or if the legal right to explore expires or if the Corporation decides not to continue exploration and evaluation activity, then the costs of such unsuccessful exploration and evaluation is written off to the statement of income in the period the relevant events occur.
Impairment
The Corporation's oil and gas assets are analysed into CGUs for impairment review purposes, with E&E asset impairment testing being performed at a grouped CGU level. The current E&E CGU consists of the Corporation's whole E&E portfolio. E&E assets are reviewed for impairment when circumstances arise which indicate that the carrying value of an E&E asset exceeds the recoverable amount. When reviewing E&E assets for impairment, the combined carrying value of the grouped CGU is compared with the grouped CGU's recoverable amount. The recoverable amount of a grouped CGU is determined as the higher of its fair value less costs to sell and value in use. Impairment losses resulting from an impairment review are written off to the statement of income.
Oil and gas expenditure - development and production assets
Capitalisation
Costs of bringing a field into production, including the cost of facilities, wells and sub-sea equipment, direct costs including staff costs and share based payment expense together with E&E assets reclassified in accordance with the above policy, are capitalised as a D&P asset. Normally each individual field development will form an individual D&P asset but there may be cases, such as phased developments, or multiple fields around a single production facility when fields are grouped together to form a single D&P asset.
Depreciation
All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is calculated on a unit of production basis based on the proved and probable reserves of the asset. Any re-assessment of reserves affects the depreciation rate prospectively. Significant items of plant and equipment will normally be fully depreciated over the life of the field. However, these items are assessed to consider if their useful lives differ from the expected life of the D&P asset and should this occur a different depreciation rate would be charged.
Impairment
A review is carried out each reporting date for any indication that the carrying value of the Corporation's D&P assets may be impaired. For D&P assets where there are such indications, an impairment test is carried out on the CGU. Each CGU is identified in accordance with IAS 36. The Corporation's CGUs are those assets which generate largely independent cash flows and are normally, but not always, single developments or production areas. The impairment test involves comparing the carrying value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use, where the value in use is determined from estimated future net cash flows. Any additional depreciation resulting from the impairment testing is charged to the statement of income.
Non Oil and Natural Gas Operations
Computer and office equipment is recorded at cost and depreciated over its estimated useful life on a straight-line basis over three years. Furniture and fixtures are recorded at cost and depreciated over their estimated useful lives on a straight-line basis over five years.
Borrowings
All interest-bearing loans and other borrowings with banks are initially recognised at fair value net of directly attributable transaction costs. After initial recognition, interest-bearing loans and other borrowings are subsequently measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs, discount or premium.
Loan origination fees are capitalised and amortised over the term of the loan. Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets until such time as the assets are substantially ready for their intended use of sale. All other borrowing costs are expensed as incurred.
Senior notes are measured at amortised cost.
Decommissioning liabilities
The Corporation records the present value of legal obligations associated with the retirement of long term tangible assets, such as producing well sites and processing plants, in the period in which they are incurred with a corresponding increase in the carrying amount of the related long term asset. The obligation generally arises when the asset is installed or the ground/environment is disturbed at the field location. In subsequent periods, the asset is adjusted for any changes in the estimated amount or timing of the settlement of the obligations. The carrying amounts of the associated assets are depleted using the unit of production method, in accordance with the depreciation policy for development and production assets. Actual costs to retire tangible assets are deducted from the liability as incurred.
Onerous contracts
Onerous contract provisions are recognised where the unavoidable costs of meeting the obligations under a contract exceed the economic benefits expected to be received under it.
Contingent consideration
Contingent consideration is accounted for as a financial liability and measured at fair value at the date of acquisition with any subsequent remeasurements recognised either in the statement of income or in other comprehensive income in accordance with IAS 39.
Taxation
Current income tax
Current income tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amounts are those that are enacted or substantively enacted by the reporting date.
Deferred income tax
Deferred tax is recognised for all deductible temporary differences and the carry-forward of unused tax losses. Deferred tax assets and liabilities are measured using enacted or substantively enacted income tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in rates is included in earnings in the period of the enactment date. Deferred tax assets are recorded in the consolidated financial statements if realisation is considered more likely than not.
Deferred tax assets and liabilities are offset only when a legally enforceable right of offset exists and the deferred tax assets and liabilities arose in the same tax jurisdiction.
Petroleum Revenue Tax
In addition to corporate income taxes, the Group's financial statements also include and disclose Petroleum Revenue Tax (PRT) on net income determined from oil and gas production.
PRT is accounted for under IAS 12 since it has the characteristics of an income tax as it is imposed under Government authority and the amount payable is based on taxable profits of the relevant field. Deferred PRT is accounted for on a temporary difference basis.
Operating leases
Rentals under operating leases are charged to the statement of income on a straight line basis over the period of the lease.
Finance leases
Finance leases that transfer substantially all the risks and benefits incidental to ownership of the leased item to the Corporation, are capitalised at the commencement of the lease at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Lease payments are apportioned between finance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are recognised in finance costs in the income statement. A leased asset is depreciated over the useful life of the asset. However, if there is no reasonable certainty that the Corporation will obtain ownership by the end of the lease term, the asset is depreciated over the shorter of the estimated useful life of the asset and the lease term.
Maintenance expenditure
Expenditure on major maintenance refits or repairs is capitalised where it enhances the life or performance of an asset above its originally assessed standard of performance; replaces an asset or part of an asset which was separately depreciated and which is then written off, or restores the economic benefits of an asset which has been fully depreciated. All other maintenance expenditure is charged to the statement of income as incurred.
Recent accounting pronouncements
New and amended standards and interpretations need to be adopted in the first interim financial statements issued after their effective date (or date of early adoption). There are no new IFRSs or IFRICs that are effective for the first time for this interim period that would be expected to have a material impact on the Corporation.
Significant accounting judgements and estimation uncertainties
The preparation of financial statements in conformity with IFRS requires management to make estimates and assumptions regarding certain assets, liabilities, revenues and expenses. Such estimates must often be made based on unsettled transactions and other events and a precise determination of many assets and liabilities is dependent upon future events. Actual results may differ from estimated amounts.
The amounts recorded for depletion, depreciation of property and equipment, long-term liability, stock-based compensation, contingent consideration, decommissioning liabilities, derivatives and deferred taxes are based on estimates. The depreciation charge and any impairment tests are based on estimates of proved and probable reserves, production rates, prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be material. Further information on each of these estimates is included within the notes to the financial statements.
4. SEGMENTAL REPORTING
The Company operates a single class of business being oil and gas exploration, development and production and related activities in a single geographical area presently being the North Sea.
5. REVENUE
Three months Six months ended
ended 30 June 30 June
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
------------------ --------- --------- --------- ---------
Oil sales 23,504 57,404 55,534 125,675
Gas sales 824 1,841 1,895 3,240
Condensate sales 150 136 278 289
Other income 33 (229) 54 323
------------------ --------- --------- --------- ---------
24,511 59,152 57,761 129,527
6. ADMINISTRATIVE EXPENSES
Three months ended 30 June Six months ended
30 June
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
-------------------------- --------- --------- --------- ---------
General & administrative (1,302) (1,697) (2,960) (5,102)
Share based payment (220) (209) (331) (389)
-------------------------- --------- --------- --------- ---------
(1,522) (1,906) (3,291) (5,491)
7. FINANCE COSTS
Three months Six months ended
ended 30 June 30 June
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
--------------------------- --------- --------- --------- ---------
Bank interest and charges (1,131) (2,117) (2,283) (4,627)
Senior notes interest (3,830) (3,444) (7,659) (7,349)
Finance lease interest (250) (264) (504) (530)
Non-operated asset
finance fees (7) (27) (12) (51)
Prepayment interest (782) (781) (1,404) (781)
Loan fee amortisation (1,040) (1,881) (2,078) (3,058)
Accretion (2,294) (2,261) (4,567) (4,499)
--------------------------- --------- --------- --------- ---------
(9,334) (10,775) (18,507) (20,895)
8. ACCOUNTS RECEIVABLE
30 June 31 Dec
2016 2015
US$'000 US$'000
---------------- ---------------------- ---------
Trade debtors 258,338 222,010
Accrued income 495 996
---------------- ---------------------- ---------
258,833 223,006
9. INVENTORY
30 June 31 Dec
2016 2015
Current US$'000 US$'000
--------------------- --------------------- ---------
Crude oil inventory 29,947 18,721
Materials inventory 1,855 2,179
--------------------- --------------------- ---------
31,802 20,900
30 June 31 Dec
2016 2015
Non-current US$'000 US$'000
--------------------- --------------------- ---------
Crude oil inventory 7,908 7,908
The non-current portion of inventory relates to long term stocks at the Sullom Voe Terminal.
10. EXPLORATION AND EVALUATION ASSETS
US$'000
------------------------------------ ---------------------
At 1 January 2015 89,844
Additions 30,263
Disposals (44,005)
Release of exploration obligations (1,431)
Write offs/relinquishments (30,522)
Impairment (32,926)
At 31 December 2015 and 1 January
2016 11,223
Additions 1,137
Write offs/relinquishments (819)
------------------------------------ ---------------------
At 30 June 2016 11,541
Following completion of geotechnical evaluation activity, certain North Sea licences were declared unsuccessful and certain prospects were declared non-commercial. This resulted in the carrying value of these licences being fully written off to nil with $0.8 million being expensed in the period to 30 June 2016.
11. PROPERY, PLANT AND EQUIPMENT
Development &
Production Other fixed
Oil and Gas Assets assets Total
US$'000 US$'000 US$'000
----------------------------- ---------------------- ----------------------- -------------------
Cost
At 1 January 2015 2,341,069 4,140 2,345,209
Additions 141,318 717 142,035
Disposals - (1,451) (1,451)
Release of onerous contract
provision (377) - (377)
At 31 December 2015
and 1 January 2016 2,482,010 3,406 2,485,416
Additions 27,919 3 27,922
At 30 June 2016 2,509,929 3,409 2,513,338
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 (37,244) (140) (37,384)
At 30 June 2016 (1,418,070) (2,684) (1,420,754)
NBV at 1 January
2015 1,433,764 1,445 1,435,209
NBV at 1 January
2016 1,101,184 862 1,102,046
NBV at 30 June 2016 1,091,859 725 1,092,584
The net book amount of property, plant and equipment includes $29.9 million (31 December 2015: $30.2 million) in respect of the Pierce FPSO lease held under finance lease.
12. GOODWILL
30 June 31 Dec
2016 2015
US$'000 US$'000
----------------- --------- ---------
Closing balance 123,510 123,510
Goodwill represents $136.1 million recognised on the acquisition of Summit Petroleum Limited as a result of recognising a $136.9 million deferred tax liability as required under IFRS 3 fair value accounting for business combinations. Absent the deferred tax liability the price paid for the Summit assets equated to the fair value of the assets. $1.0 million represented goodwill recognised on the acquisition of gas assets from GDF in December 2010. As at 31 December 2015 a non-taxable impairment of $13.6 million was recorded relating to goodwill.
13. INVESTMENT IN ASSOCIATES
30 31 Dec
June 2015
2016 US$'000
US$'000
--------------------------------------- --------- ---------
Investments in FPF-1 and FPU services 18,337 18,337
Investment in associates comprises shares, acquired by Ithaca Energy (Holdings) Limited, in FPF-1 Limited and FPU Services Limited as part of the completion of the Greater Stella Area transactions in 2012. There has been no change in value during the period with the above investment reflecting the Corporation's share of the associates' results.
14. BORROWINGS
31 June 31 Dec
2016 2015
US$'000 US$'000
----------------------------- ---------- ----------
RBL facility (331,793) (376,793)
Senior
notes (300,000) (300,000)
Long term
bank fees 5,211 6,779
Long term senior notes fees 3,322 3,884
----------------------------------- ---------- ----------
(623,260) (666,130)
Bank debt facilities
The Company's bank debt facilities were initially sized at $650 million: a $575 million senior RBL and a $75 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 April 2016 redetermination resulting in debt availability of over $430 million.
With debt requirements and availability now substantially below the initial facility sizes the Corporation elected to reduce the size of the facilities during Q2 thereby reducing commitment fees.
Senior Reserves Based Lending Facility
As at 30 June 2016, the Corporation has a Senior Reserved Based Lending ("Senior RBL") Facility of $475 million (31 December 2015: $575 million). As at 30 June 2016, $332 million (31 December 2015: $377 million) was drawn down under the Senior RBL. $5.2 million (31 December 2015: $6.8 million) of loan fees relating to the RBL have been capitalised and remain to be amortised.
Junior Reserves Based Lending Facility
As at 30 June 2016, the Corporation had a Junior Reserved Based Lending ("Junior RBL") Facility of $60 million (31 December 2015: $75 million). The facility remains undrawn at the quarter end.
Senior Notes
As at 30 June 2016, the Corporation had $300 million 8.125% senior unsecured notes due July 2019, with interest payable semi-annually. $3.3million of loan fees (31 December 2015: $3.9 million) have been capitalised and remain to be amortised.
Covenants
The Corporation is subject to financial and operating covenants related to the facilities. Failure to meet the terms of one or more of these covenants may constitute an event of default as defined in the facility agreements, potentially resulting in accelerated repayment of the debt obligations.
The Corporation was in compliance with all its relevant financial and operating covenants during the period.
The key covenants in both the Senior and Junior RBLs are:
- A corporate cashflow projection showing total sources of funds must exceed total forecast uses of funds for the later of the following 12 months or until forecast first oil from the Stella field.
- The ratio of the net present value of cashflows secured under the RBL for the economic life of the fields to the amount drawn under the facility must not fall below 1.15:1
- The ratio of the net present value of cashflows secured under the RBL for the life of the debt facility to the amount drawn under the facility must not fall below 1.05:1.
There are no financial maintenance covenants tests under the senior notes.
Security provided against the facilities
The RBL facilities are secured by the assets of the guarantor member of the Ithaca Group, such security including share pledges, floating charges and/or debentures.
The Senior notes are unsecured senior debt of Ithaca Energy Inc., guaranteed by certain members of the Ithaca Group and subordinated to existing and future secured obligations.
15. TRADE AND OTHER PAYABLES
30 June 31 Dec
2016 2015
US$'000 US$'000
------------------------------ ---------- ----------
Trade payables (146,355) (129,719)
Accruals and deferred income (177,043) (146,188)
(323,398) (275,907)
16. EXPLORATION OBLIGATIONS
30 June 31 Dec
2016 2015
US$'000 US$'000
------------------------- --------- ---------
Exploration obligations (4,000) (4,000)
The above reflects the fair value of E&E commitments assumed as part of the Valiant transaction.
17. DECOMMISSIONING LIABILITIES
30 June 31 Dec
2016 2015
US$'000 US$'000
------------------------------------ ---------------------- ----------------------
Balance, beginning of period (226,915) (213,105)
Additions (2,280) -
Accretion (4,567) (9,092)
Revision to estimates - (4,718)
Decommissioning provision utilised 2,165 -
Balance, end of period (231,597) (226,915)
The total future decommissioning liability was calculated by management based on its net ownership interest in all wells and facilities, estimated costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. The Corporation uses a risk free rate of 4.0 percent (31 December 2015: 4.0 percent) and an inflation rate of 2.0 percent (31 December 2015: 2.0 percent) over the varying lives of the assets to calculate the present value of the decommissioning liabilities. These costs are expected to be incurred at various intervals over the next 21 years.
The economic life and the timing of the obligations are dependent on Government legislation, commodity price and the future production profiles of the respective production and development facilities.
18. OTHER LONG TERM LIABILITIES
30 June 31 Dec
2016 2015
US$'000 US$'000
------------------------ ---------- ----------------------
Shell prepayment (63,158) (62,227)
BP gas prepayment (13,851) -
Finance lease acquired (29,912) (30,316)
Balance, end of period (106,921) (92,543)
The prepayment balance relates to cash advances under the Shell oil sales agreement and BP gas sales agreement which have been classified as long-term liabilities as short-term repayment is not due in the current oil price environment. The finance lease relates to the Pierce FPSO acquired as part of the Summit acquisition.
19. FINANCE LEASE LIABILITIES
30 June 31 Dec
2016 2015
US$'000 US$'000
-------------------------------- --------- ---------
Total minimum lease payments
Less than 1 year (2,595) (2,602)
Between 1 and 5 years (12,503) (12,570)
5 years and later (22,282) (23,502)
Interest
Less than 1 year (967) (994)
Between 1 and 5 years (3,979) (4,123)
5 years and later (3,237) (3,569)
Present value of minimum lease
payments
Less than 1 year (1,628) (1,608)
Between 1 and 5 years (8,523) (8,447)
5 years and later (19,046) (19,933)
-------------------------------- --------- ---------
The finance lease relates to the Pierce FPSO acquired as part of the Summit acquisition in July 2014.
20. CONTINGENT CONSIDERATION
30 June 31 Dec
2016 2015
US$'000 US$'000
--------------------- --------- ---------
Balance outstanding (4,000) (4,000)
The contingent consideration at the end of the period relates to the acquisition of the Stella field and is payable upon first oil.
21. SHARE CAPITAL
No. of common Amount
Authorised share capital shares US$'000
-------------------------------- -------------- ---------
At 30 June 2016 and 31 December Unlimited -
2015
(a) Issued
The issued share capital is
as follows:
Issued Number of common Amount
shares US$'000
------------------------------------- ------------------- ----------------------
Balance 1 January 2016 411,384,045 617,375
Issued for cash - options exercised 400,000 346
Balance 30 June 2016 411,784,045 617,721
(b) Stock options
In the six months ended 30 June 2016, the Corporation's Board of Directors granted 12,000,000 options at an exercise price of $0.40 (C$0.55).
The Corporation's stock options and exercise prices are denominated in Canadian Dollars when granted. As at 30 June 2016, 28,746,470 stock options to purchase common shares were outstanding, having an exercise price range of $0.40 to $2.51 (C$0.55 to C$2.71) per share and a vesting period of up to 3 years in the future.
Changes to the Corporation's stock options are summarised as follows.
30 June 2016 31 December 2015
--------------------- ------------------------------ ------------------------
Wt. Avg Wt. Avg
No. of Exercise No. of Exercise
Options Price* Options Price*
--------------------- ------------------ ---------- ------------ ----------
Balance, beginning
of period 19,216,206 $1.70 24,232,428 $1.81
Granted 12,000,000 $0.40 950,000 $0.84
Forfeited / expired (2,069,736) $1.52 (5,966,222) $2.05
Exercised (400,000) $0.62 - -
--------------------- ------------------ ---------- ------------ ----------
Options 28,746,470 $1.18 19,216,206 $1.70
--------------------- ------------------ ---------- ------------ ----------
* The weighted average exercise price has been converted into U.S. dollars based on the foreign exchange rate in effect at the date of issuance.
The following is a summary of stock options as at 30 June 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*
----------------- ----------- ------------------- ---------- ---------------- ---------- ------------ ----------
$2.45-$2.51 $2.45-$2.51
(C$2.53-C$2.71) 6,506,469 1.4 $2.47 (C$2.53-C$2.71) 4,091,667 1.4 $2.47
$1.06-$2.03 $1.06-$2.03
(C$1.04-C$1.99) 10,790,001 1.9 $1.23 (C$1.04-C$1.99) 5,680,001 1.3 $1.50
$0.40 (C$0.55) 11,450,000 3.5 $0.40 $0.40 (C$0.55) 200,000 1.0 $0.40
----------------- ----------- ------------------- ---------- ---------------- ---------- ------------ ------------
28,746,470 2.7 $1.18 9,971,668 1.3 $1.88
================= =========== =================== ========== ================ ========== ============ ============
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 cost during the three months and six months ended 30 June 2016 for total stock options granted was $1.0 million and $1.7 million respectively (Q2 2015: $0.9 million, Q2 YTD: $2.0 million). $0.2 million and $0.3 million were charged through the statement of income for stock based compensation for the three months and six months ended 30 June 2016 (Q2 2015: $0.2 million, Q2 YTD: $0.4 million), being the Corporation's share of stock based compensation chargeable through the statement of income. The remainder of the Corporation's share of stock based compensation has been capitalised. The fair value of each stock option granted was estimated at the date of grant, using the Black-Scholes option pricing model with the following assumptions:
For the six months For the year
ended 30 June ended 31 December
2016 2015
--------------------------- ------------------- -------------------
Risk free interest
rate 0.53% 0.65%
Expected stock volatility 60% 59%
Expected life of options 3 years 3 years
Weighted Average Fair
Value $0.22 $0.43
22. SHARE BASED PAYMENT RESERVE
30 June 31 Dec
2016 2015
US$'000 US$'000
------------------------------ --------------------- ---------------------
Balance, beginning of period 22,678 19,234
Share based payment cost 1,634 3,444
Balance, end of period 24,312 22,678
23. EARNINGS PER SHARE
The calculation of basic earnings per share is based on the profit after tax and the weighted average number of common shares in issue during the period. The calculation of diluted earnings per share is based on the profit after tax and the weighted average number of potential common shares in issue during the period.
Three months Six months ended
ended 30 June 30 June
2016 2015 2016 2015
-------------------------- ------------ ------------ ------------ ------------
Wtd av. number of common
shares (basic) 411,388,441 329,518,620 411,386,243 329,518,620
Wtd av. number of common
shares (diluted) 411,389,565 329,518,620 411,386,805 329,518,620
24. TAXATION
Three months Six months
ended 30 June ended 30 June
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
---------- ------------------- --------- --------- ---------
Taxation 32,614 66,714 66,848 32,203
It was announced in the UK Budget on 16 March 2016 that the rate of Petroleum Revenue Tax ("PRT") was effectively abolished from 1 January 2016 with the introduction of a 0% PRT rate. This eliminated the Company's future PRT tax charge from 1 January 2016. The PRT rate change has been enacted and was therefore reflected in the Q1 2016 results.
Further, it was also announced that the Supplementary Charge in respect of ring fence trades ("SCT") will 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 will reduce the net deferred tax assets by approximately $87 million and is expected to impact the financial statements later in H2 2016 when the rate change is enacted.
In accordance with the Stella Sale and Purchase Agreement ("SPA"), Ithaca receives the right to claim a tax benefit for additional capital allowances on certain capital expenditures incurred by Ithaca and paid for by Petrofac on the Stella project.
The tax benefit of these capital allowances is received by Ithaca as the expenditure is incurred. In recognition of the benefit Ithaca receives from the additional capital allowances a payment is expected to be made to Petrofac 5 years after Stella first oil of a sum calculated at the prevailing tax rate applied to the relevant capital allowances, in accordance with the SPA. The taxation credit above includes a deferred tax credit of $8.2 million for the three months ended 30 June 2016 resulting in a related deferred tax asset at 30 June 2016 of $98.3 million.
25. COMMITMENTS
30 June 31 Dec
2016 2015
US$'000 US$'000
----------------------------- ---------------------- -------------
Operating lease commitments
Within one year 240 240
Two to five years 180 300
30 June 31 Dec
2016 2015
US$'000 US$'000
---------------------------------------- --------- ---------
Capital commitments
Capital commitments incurred jointly
with other ventures (Ithaca's share) 31,254 9,534
Ithaca will pay Petrofac $13.7 million in respect of final payment on variations to the contract, with payment deferred until three and a half years after first production from the Stella field. A further payment to Petrofac of up to $34 million was to be made by Ithaca dependent on the timing of sail-away of the FPF-1. This further payment has been revised to $17 million. This payment will also be deferred until three and a half years after first production from the Stella field.
26. FINANCIAL INSTRUMENTS
To estimate fair value of financial instruments, the Corporation uses quoted market prices when available, or industry accepted third-party models and valuation methodologies that utilise observable market data. In addition to market information, the Corporation incorporates transaction specific details that market participants would utilise in a fair value measurement, including the impact of non-performance risk. The Corporation characterises inputs used in determining fair value using a hierarchy that prioritises inputs depending on the degree to which they are observable. However, these fair value estimates may not necessarily be indicative of the amounts that could be realised or settled in a current market transaction. The three levels of the fair value hierarchy are as follows:
-- Level 1 - inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
-- Level 2 - inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, market interest rates, and volatility factors, which can be observed or corroborated in the marketplace. The Corporation obtains information from sources such as the New York Mercantile Exchange and independent price publications.
-- Level 3 - inputs that are less observable, unavailable or where the observable data does not support the majority of the instrument's fair value.
In forming estimates, the Corporation utilises the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorised based upon the lowest level of input that is significant to the fair value measurement. The valuation of over-the-counter financial swaps and collars is based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. These are categorised as Level 2.
The following table presents the Corporation's material financial instruments measured at fair value for each hierarchy level as of 30 June 2016:
Total
Level Level Level Fair
1 2 3 Value
US$'000 US$'000 US$'000 US$'000
-------------------------- ---------- --------- --------- ---------
Derivative financial
instrument asset - 46,579 - 46,579
Contingent consideration - (4,000) - (4,000)
Derivative financial
instrument liability - (5,271) - (5,271)
-------------------------- ---------- --------- --------- ---------
The table below presents the total (loss)/gain on financial instruments that has been disclosed through the statement of comprehensive income:
Three months Six months ended
ended 30 June 30 June
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
----------------------------- --------------------- -------------------- --------------------- ---------
Revaluation of forex
forward contracts (4,058) 6,665 (5,278) 5,039
Revaluation of other
long term liability - - - 307
Revaluation of commodity
hedges (47,582) (48,303) (79,918) (96,297)
Revaluation of interest
rate swaps 52 (23) 43 (265)
----------------------------- --------------------- -------------------- --------------------- ---------
(51,588) (41,661) (85,153) (91,216)
Realised (loss)/gain
on forex contracts (532) 607 (951) 607
Realised gain on commodity
hedges 18,824 31,330 57,987 110,106
Realised (loss) on
interest rate swaps (157) (107) (157) (206)
----------------------------- --------------------- -------------------- --------------------- ---------
18,135 31,830 56,879 110,507
-------------------- --------------------- ---------
Total (loss)/gain
on financial instruments (33,453) (9,831) (28,274) 19,291
The Corporation has identified that it is exposed principally to these areas of market risk.
i) Commodity Risk
The table below presents the total (loss)/gain on commodity hedges that has been disclosed through the statement of income at the quarter end:
Three months ended 30 June Six months ended
30 June
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
---------------------------- ------------------ --------- --------- ---------
Revaluation of commodity
hedges (47,582) (48,303) (79,918) (96,297)
Realised gain on commodity
hedges 18,824 31,330 57,987 110,106
---------------------------- ------------------ --------- --------- ---------
Total (loss)/gain on
commodity hedges (28,758) (16,973) (21,931) 13,809
Commodity price risk related to crude oil prices is the Corporation's most significant market risk exposure. Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. The Corporation is also exposed to natural gas price movements on uncontracted gas sales. Natural gas prices, in addition to the worldwide factors noted above, can also be influenced by local market conditions. The Corporation's expenditures are subject to the effects of inflation, and prices received for the product sold are not readily adjustable to cover any increase in expenses from inflation. The Corporation may periodically use different types of derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows.
The below represents commodity hedges in place at the quarter end:
Derivative Term Volume Average
price
----------- --------- ----------- ------- -----------
Oil swaps Jul 16 -
Jun 17 1,464,427 bbls $68.4/bbl
Gas swaps Jul 16 - therms
Mar 17 4,658,321 47p/therm
Gas puts Jul 16 - therms
Jun 17 86,800,000 61.9/therm
ii) Interest Risk
The table below presents the total (loss) on interest financial instruments that has been disclosed statement of income at the quarter end:
Three months ended 30 June Six months ended
30 June
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
-------------------------- --------------------- --------- --------------------- ---------
Revaluation of interest
contracts 52 (23) 43 (265)
Realised (loss) on
interest contracts (157) (107) (157) 206
-------------------------- --------------------- --------- --------------------- ---------
Total (loss) on interest
contracts (105) (130) (114) (471)
Calculation of interest payments for the RBL Facilities agreement incorporates LIBOR. The Corporation is therefore exposed to interest rate risk to the extent that LIBOR may fluctuate. The below represents interest rate financial instruments in place:
Derivative Term Value Rate --------------- ----------------- ------------ ------ Interest rate swap Jul 16 - Dec 16 $50 million 1.24%
iii) Foreign Exchange Rate Risk
The table below presents the total (loss)/ gain on foreign exchange financial instruments that has been disclosed through the statement of income at the quarter end:
Three months ended 30 June Six months ended
30 June
2016 2015 2016 2015
US$'000 US$'000 US$'000 US$'000
------------------------------------------- --------- --------- ---------
Revaluation of foreign exchange
forward contracts (4,058) 6,665 (5,278) 5,039
Realised (loss)/gain on foreign
exchange forward contracts (532) 607 (951) 607
---------------------------------- -------- --------- --------- ---------
Total (loss)/gain on forex
forward contracts (4,590) 7,272 (6,229) 5,646
The Corporation is exposed to foreign exchange risks to the extent it transacts in various currencies, while measuring and reporting its results in US Dollars. Since time passes between the recording of a receivable or payable transaction and its collection or payment, the Corporation is exposed to gains or losses on non USD amounts and on balance sheet translation of monetary accounts denominated in non USD amounts upon spot rate fluctuations from quarter to quarter.
Derivative Term Value Forward rate
----------- ------------- --------------------- --------------
Jul 16 - Dec
Forward 16 GBP1.6 million/month $1.47/GBP1.00
Jul 16 - Dec
Forward 16 GBP1.6 million/month $1.48/GBP1.00
Forward Sep 16 GBP12 million $1.47/GBP1.00
Swap Jul 16 GBP4.8 million $1.47/GBP1.00
iv) Credit Risk
The Corporation's accounts receivable with customers in the oil and gas industry are subject to normal industry credit risks and are unsecured. Oil production from Cook, Broom, Dons, Pierce, Causeway and Fionn is sold to Shell Trading International Ltd. Wytch Farm oil production is sold on the spot market. Topaz gas production is sold to Hartree Partners Oil and Gas. Cook gas is sold to Shell UK Ltd and Esso Exploration & Production UK Ltd.
The Corporation assesses partners' credit worthiness before entering into farm-in or joint venture agreements. In the past, the Corporation has not experienced credit loss in the collection of accounts receivable. As the Corporation's exploration, drilling and development activities expand with existing and new joint venture partners, the Corporation will assess and continuously update its management of associated credit risk and related procedures.
The Corporation regularly monitors all customer receivable balances outstanding in excess of 90 days. As at 30 June 2016, substantially all accounts receivables are current, being defined as less than 90 days. The Corporation has no allowance for doubtful accounts as at 30 June 2016 (31 December 2015: $Nil).
The Corporation may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to meet the terms of the contracts. The Corporation's exposure is limited to those counterparties holding derivative contracts with positive fair values at the reporting date. As at 30 June 2016, exposure is $46.6 million (31 December 2015: $126.9 million).
The Corporation also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values.
v) Liquidity Risk
Liquidity risk includes the risk that as a result of its operational liquidity requirements the Corporation will not have sufficient funds to settle a transaction on the due date. The Corporation manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Corporation considers the maturity profiles of its financial assets and liabilities. As at 30 June 2016, substantially all accounts payable are current.
The following table shows the timing of cash outflows relating to trade and other payables.
Within 1 1 to 5 years
year US$'000
US$'000
------------------------------ ---------------------- ----------------------
Accounts payable and accrued
liabilities (323,398) -
Other long term liabilities - (106,921)
Borrowings - (623,260)
------------------------------ ---------------------- ----------------------
(323,398) (730,181)
27. DERIVATIVE FINANCIAL INSTRUMENTS
30 June 31 December
2016 2015
US$'000 US$'000
----------------------------------- ---------------------- ------------
Oil swaps 25,568 61,602
Oil capped swaps - 7,117
Gas swaps 421 1,690
Gas puts 20,590 56,352
Interest rate swaps (153) (197)
Foreign exchange forward contract (5,118) 126
----------------------------------- ---------------------- ------------
41,308 126,690
28. FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES
Financial instruments of the Corporation consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in these financial statements. At 30 June 2016, the classification of financial instruments and the carrying amounts reported on the balance sheet and their estimated fair values are as follows:
30 June 2016 31 December
US$'000 2015
US$'000
----------------------------- -------------------------------- ----------------------
Carrying Fair Carrying Fair
Classification Amount Value Amount Value
----------------------------- -------------------- ---------- ---------- ----------
Cash and cash equivalents
(Held for trading) 25,852 25,852 11,543 11,543
Derivative financial
instruments (Held for
trading) 46,579 46,579 126,887 126,887
Accounts receivable (Loans
and Receivables) 258,833 258,833 223,006 223,006
Deposits 2,001 2,001 743 743
Long-term receivable
(Loans and Receivables) 60,261 60,261 61,052 61,052
Bank debt (Loans and
Receivables) (623,260) (623,260) (666,130) (666,130)
Contingent consideration (4,000) (4,000) (4,000) (4,000)
Derivative financial
instruments (Held for
trading) (5,271) (5,271) (197) (197)
Other long term liabilities (106,921) (106,921) (92,543) (92,543)
Accounts payable (Other
financial liabilities) (323,398) (323,398) (275,907) (275,907)
29. RELATED PARTY TRANSACTIONS
The consolidated financial statements include the financial statements of Ithaca Energy Inc. and the subsidiaries listed in the following table:
Country of incorporation % equity interest
at 30 June
2016 2015
-------------------------- -------------------------- --------- ---------
Ithaca Energy (UK)
Limited Scotland 100% 100%
Ithaca Minerals (North
Sea) Limited Scotland 100% 100%
Ithaca Energy (Holdings)
Limited Bermuda 100% 100%
Ithaca Energy Holdings
(UK) Limited Scotland 100% 100%
Ithaca Petroleum
Limited England and Wales 100% 100%
Ithaca North Sea
Limited England and Wales 100% 100%
Ithaca Exploration
Limited England and Wales 100% 100%
Ithaca Causeway Limited England and Wales 100% 100%
Ithaca Gamma Limited England and Wales 100% 100%
Ithaca Alpha (NI)
Limited Northern Ireland 100% 100%
Ithaca Epsilon Limited England and Wales 100% 100%
Ithaca Delta Limited England and Wales 100% 100%
Ithaca Petroleum
Holdings AS Norway 100% 100%
Ithaca Petroleum
Norge AS* Norway 100% 100%
Ithaca Technology
AS Norway 100% 100%
Ithaca AS Norway 100% 100%
Ithaca Petroleum
EHF Iceland 100% 100%
Ithaca SPL Limited England and Wales 100% 100%
Ithaca Dorset Limited England and Wales 100% 100%
Ithaca SP UK Limited England and Wales 100% 100%
Ithaca Pipeline Limited England and Wales 100% 100%
Transactions between subsidiaries are eliminated on consolidation.
*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 six month period ending 30 June 2016 and 30 June 2015, as well as balances with related parties as of 30 June 2016 and 31 December 2015:
Sales Purchases Accounts Accounts
receivable payable
US$'000 US$'000 US$'000 US$'000
----------------- ------ --------- ---------- ------------ ---------
Burstall Winger
LLP 2016 - 149 - (38)
2015 - 69 - (22)
Loans to related Amounts owed from related
parties parties
30 June 31 Dec
2016 2015
US$'000 US$'000
------------------ ---------------------- --------
FPF-1 Limited 60,211 60,842
FPU Services
Limited 50 210
30. SEASONALITY
The effect of seasonality on the Corporation's financial results for any individual quarter is not material.
This information is provided by RNS
The company news service from the London Stock Exchange
END
IR EAXPAFFKKEFF
(END) Dow Jones Newswires
August 15, 2016 02:00 ET (06:00 GMT)
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