SOURCE: Ithaca Energy Inc

August 12, 2014 02:41 ET

Ithaca Energy Inc.: 2014 Second Quarter & Half Year Results

CALGARY, AB--(Marketwired - Aug 12, 2014) - Ithaca Energy Inc. (TSX: IAE) (LSE: IAE) ("Ithaca" or the "Company") announces its quarterly financial results for the three months ended 30 June 2014 ("Q2-2014") and half yearly results for the six months ended 30 June 2014 ("H1-2014").

Highlights

  • H1-2014 cashflow from operations of $101.8 million (H1-2013: $100.5 million), reflecting a Q2-2014 contribution of $58.1 million (Q2-2013: $65.0 million), resulting in H1-2014 cashflow per share of $0.31 (H1-2013: $0.36)
  • H1-2014 profit after tax of $17.0 million (H1-2013: $57.3 million). Profit after tax during the quarter was $0.7 million (Q2-2013: $53.8 million), after reflecting an unrealised non-cash hedging loss of $6.9 million
  • Broadening of the producing asset portfolio with the acquisition of interests in three high quality, long-life UK oil fields from Sumitomo Corporation (the "Summit Assets")
  • Additional 1.6 million barrels of oil production hedged at approximately $105/barrel to underpin approximately 70% of production associated with the Summit Assets over the next two years
  • Successful completion of a $300 million senior notes offering, providing diversity in the sources and tenor of funding within the capital structure of the business
  • Net drawn debt of $499 million at 30 June 2014 (excluding the Norwegian tax rebate facility) out of total debt facilities of $1,010 million, including the senior notes issued on 3 July 2014
  • Continued progress made on execution and de-risking of the Greater Stella Area ("GSA") development, with a further strong clean-up flow test result achieved on the third Stella development well that was completed during the quarter

Les Thomas, Chief Executive Officer, commented:
"I am pleased with the progress made by the Company over the last quarter, having further strengthened the business in three key areas: the successful third Stella well materially de-risked the on-going field development; the Summit acquisition added high quality assets to the existing producing portfolio; and the successful bond offering introduced important funding diversification and flexibility."

Production & Operations
Average pro-forma production in Q2-2014 was approximately 14,300 barrels of oil equivalent per day ("boepd"), 94% oil, including a contribution of approximately 2,500 boepd from the Summit Assets during the period. Average pro-forma production in H1-2014 was approximately 12,800 boepd including approximately 2,300 boepd from the Summit Assets. 

Total 2014 pro-forma production guidance remains unchanged in the range of 13,500 to 15,500 boepd, approximately 95% oil. As previously guided, 2014 production volumes are forecast to be weighted towards the second half of the year, notably from the later part of Q3-2014 post the completion of planned summer maintenance shutdowns, driven by the close out of on-going production enhancement projects.

Greater Stella Area Development Update
During the quarter, drilling of the third Stella development well was completed. The strong results of the clean-up flow test performed on the well, combined with the corresponding results of the first two wells, have served to de-risk the initial annualised production forecast for the GSA hub of approximately 30,000 boepd (100%), 16,000 boepd net to Ithaca. Operations are currently on-going on the fourth well, the Stella Andrew reservoir crestal gas producer, with completion of the well scheduled for early October 2014.

Offshore operations are currently on-going to install the subsea infrastructure associated with the FPF-1 mooring spread. Installation of the mooring piles has recently been completed, with the work now focused on installation of the anchor chains that will be connected to the piles and left ready for pull-in upon arrival of the FPF-1 on location. On the FPF-1 modification works, construction activities on the main deck of the vessel are advancing. All the main oil and gas processing plant packages have been positioned on the vessel and installation of the associated pipework has commenced. Fit out of the accommodation module is progressing well, with handover for pre-commissioning expected shortly.

Corporate Activities
In July 2014 the Company entered into an agreement with Sumitomo Corporation to acquire non-operated interests in the Cook (20.00%), Pierce (7.48%) and Wytch Farm (7.43%) producing oil fields. The acquisition further broadens the Company's portfolio, adding quality assets with clearly defined upsides, and delivers a further step-up in reserves and acceleration in the monetisation of the existing UK tax allowances pool. The acquisition was completed on 31 July 2014 for a net consideration of $163 million and the assets will be consolidated into the Company's financial statements from that date.

In July 2014, the Company also successfully completed an offering of $300 million senior unsecured notes due 2019, with a coupon of 8.125%. The diversification in funding sources and tenor that the notes bring into the capital structure compliment the long term production, appraisal and development growth focus of the business.

Further Information
A presentation to accompany the financial results is available on the Company's website at www.ithacaenergy.com.

A short conference call for European research analysts will take place at 09.00 UK time on 12 August 2014 and again at 14.00 UK time for North American analysts. For further information contact FTI Consulting.

Notes
In accordance with AIM Guidelines, John Horsburgh, BSc (Hons) Geophysics (Edinburgh), MSc Petroleum Geology (Aberdeen) and Subsurface Manager at Ithaca is the qualified person that has reviewed the technical information contained in this press release. Mr Horsburgh has over 15 years operating experience in the upstream oil and gas industry.

References herein to barrels of oil equivalent ("boe") are derived by converting gas to oil in the ratio of six thousand cubic feet ("Mcf") of gas to one barrel ("bbl") of oil. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1 bbl, utilising a conversion ratio at 6 Mcf: 1 bbl may be misleading as an indication of value.

About Ithaca Energy
Ithaca Energy Inc. (TSX: IAE) (LSE: 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, the exploitation of its existing UK producing asset portfolio and a Norwegian exploration and appraisal business targeting the generation of discoveries capable of monetisation prior to development. 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.

Not for Distribution to U.S. Newswire Services or for Dissemination in the United States

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 times, well completion times, risks associated with operations, future capital expenditures, continued availability of financing for future capital expenditures, future acquisitions 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 "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe", "could", "target" and similar expressions, and the negatives thereof, whether used in connection with operational activities, drilling plans, production forecasts, budgetary figures, potential developments 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 and 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. 

This press release contains non-International Financial Reporting Standards ("IFRS") industry benchmarks and terms, such as "cashflow from operations". "Cashflow from operations" does not have any standardized meaning and therefore is unlikely to be comparable to similar measures presented by other companies. The Company uses this measure 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.

Additional information on these and other factors that could affect Ithaca's operations and financial results are included in the Company's Management's Discussion and Analysis for the quarter ended June 30, 2014, and the Company's Annual Information Form for the year ended December 31, 2013 and in reports which are on file with the Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).

HIGHLIGHTS SECOND QUARTER 2014
Strong underlying cash generative assets     

  • H1-2014 cashflow from operations of $101.8 million (H1-2013: $100.5 million), reflecting a Q2-2014 contribution of $58.1 million (Q2-2013: $65.0 million), resulting in H1-2014 cashflow per share of $0.31 (H1-2013: $0.36)
  • H1-2014 profit after tax of $17.0 million (H1-2013: $57.3 million).  Profit after tax during the quarter was $0.7 million (Q2-2013: $53.8 million), after reflecting an unrealised non-cash hedging loss of $6.9 million
  • Q2 2014 average realised oil price of $109/bbl (Q2 2013: $103/bbl) before hedging
  • Approximately 3.6 million barrels of oil production hedged, 70% swaps / 30% puts, over the next 2 years at a weighted average price of around $102/bbl ($100/bbl net of put premiums)
  • Net drawn debt of $499.4 million at June 30, 2014 (December 31, 2013: $346.6 million), excluding the Norwegian tax rebate facility, out of total debt facilities of $1,010 million
  • UK tax allowances pool of $1,246 million at June 30, 2014. Norwegian tax receivable of $79 million

Continued production growth and further financial strengthening of the business delivered

  • Further broadening of the Company's asset base delivered during the quarter through the acquisition of three high quality, non-operated UK producing oil field interests from Sumitomo Corporation ("Sumitomo"). The transaction was completed on July 31, 2014 for a net consideration of $163 million.
  • Successful completion of a $300 million senior unsecured notes offering on July 3, 2014. The notes provide diversification in terms of both funding sources and tenor, complimenting the long term production, appraisal and development growth focus of the business. The weighted average cost of all the Company's debt facilities remains under 5%.

Operations on-track to achieve pro-forma 2014 production guidance of 13.5-15.5kboe/d     

  • Pro-forma 2014 production guidance increased to 13,500 to 15,500 barrels of oil equivalent per day ("boepd"), approximately 95% oil, following the announcement of the assets acquisition from Sumitomo (the "Summit Assets").
  • Average pro-forma production in Q2-2014 was approximately 14,300 barrels of oil equivalent per day ("boepd"), 94% oil, including the contribution from the "Summit Assets".
  • Solid progress was made during the quarter on completion of the main 2014 production enhancement projects, with full year pro-forma production forecast to be within the guidance range.

Further significant Stella field production de-risking achieved with completion of third development well       

  • Drilling of the third Stella field development well was completed during the quarter, with the well producing strongly during the clean-up flow test period. The combined test results of the first three Stella development wells have served to de-risk the initial annualised production forecast for the Greater Stella Area ("GSA") hub of approximately 30,000 boepd (100%), 16,000 boepd net to Ithaca.
  • Offshore operations are underway on the 2014 subsea infrastructure installation programme, with installation of the FPF-1 mooring spread currently on-going. Construction activities on the FPF-1 modifications programme remain centred on the main deck of the vessel. The key processing plant packages have all now been positioned on the deck and installation of the associated pipework has commenced.
   
   
SUMMARY FINANCIAL STATEMENTS  
   
INCOME STATEMENT (M$)       6-Months Ended June 30th  
        2014     2013  
Average Brent Oil Price   $/bbl   107     108  
Average Realised Oil Price(1)   $/bbl   109     106  
                 
Revenue   M$   199.6     188.1  
Cost of Sales - excluding DD&A   M$   (90.2 )   (89.0 )
G&A etc   M$   (5.1 )   (12.7 )
Realised Derivatives (Loss) / Gain   M$   (2.5 )   14.1  
Cashflow From Operations   M$   101.8     100.5  
DD&A   M$   (83.8 )   (65.7 )
Unrealised Derivatives (Loss)   M$   (4.7 )   (3.8 )
Non-recurring Negative Goodwill   M$   -     55.3  
Other Non-Cash Costs   M$   (15.8 )   (13.3 )
Profit/(Loss) Before Tax   M$   (2.5 )   73.0  
Deferred Tax Credit / (Charge)   M$   19.5     (15.7 )
Profit After Tax   M$   17.0     57.3  
Earnings Per Share   $/Sh.   0.05     0.20  
Cashflow Per Share   $/Sh.   0.31     0.36  
  (1) Average realized price before hedging                
                 
BALANCE SHEET (M$)       Q2-2014     Q4-2013  
Cash & Equivalents       51     63  
Other Current Assets       463     375  
PP&E       1,626     1,481  
Other Non-Current Assets       79     59  
Total Assets       2,219     1,979  
Current Liabilities       (524 )   (485 )
Bank Debt       (606 )   (432 )
Asset Retirement Obligations       (177 )   (172 )
Deferred Tax Liabilities       (8 )   (10 )
Other Non-Current Liabilities       (22 )   (26 )
Total Liabilities       (1,337 )   (1,125 )
                 
Net Assets       882     854  
Share Capital       548     536  
Other Reserves       18     19  
Surplus / (Deficit)       316     299  
Shareholders' Equity       882     854  
   
   
DEBT SUMMARY (M$)       Q2-2014     Q4-2013  
RBL Facility       550.2     410.0  
Corporate Facility       -     -  
Norwegian Facility       65.6     34.0  
Total Debt       615.8     444.0  
Cash and cash equivalents       50.8     63.4  
Net debt       565.0     380.6  
Adjusted net debt (1)       499.4     346.6  
(1) Adjusted net debt excludes amounts outstanding under the Norwegian Facility  
   
   

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, the exploitation of its existing UK producing asset portfolio and a Norwegian exploration and appraisal business centred on the generation of discoveries capable of monetisation prior to development.

The Company has a solid and diversified UK producing asset base generating significant cashflow from operations.

Ithaca's goal is to generate sustainable long term shareholder value by building a highly profitable 25kboepd North Sea oil and gas company.

Execution of the Company's strategy is focused on the following core activities:

  • Maximising cashflow and production from the existing asset base.
  • Delivery of lower risk development led growth through the appraisal of undeveloped discoveries.
  • Delivering first hydrocarbons from the Ithaca operated GSA development.
  • Monetising proven Norwegian asset reserves derived from exploration and appraisal drilling prior to the development phase.
  • Continuing to grow and diversify the cashflow base by securing new producing, development and appraisal assets through targeted acquisitions and licence round participation.
  • Maintaining financial strength and a clean balance sheet, supported by lower cost debt leverage.

CORPORATE ACTIVITIES
Further broadening of the producing asset base delivered by the assets acquired from Sumitomo      

SUMMIT ACQUISITION
In June 2014, the Company entered into an agreement with Sumitomo to acquire interests in three non-operated UK producing oil fields, with an effective date of January 1, 2014. The acquisition further broadens the Company's producing asset base with high quality, long-life oil assets with clear upsides and enables acceleration in the monetisation of existing UK tax allowances. The acquired assets are: a further 20% interest in the Cook field in which the Company already has a 41.346% interest; a 7.480% interest in the Pierce field; and, a 7.430% interest in the Wytch Farm field.

The acquisition is estimated to increase net proved and probable ("2P") reserves by approximately 12.0 million barrels of oil equivalent (Ithaca management estimate) from the transaction effective date, equating to an increase in total Company 2P reserves of approximately 20%. Incremental 2014 pro-forma production from the field interests from the transaction effective date is estimated by management to be approximately 2,500 boepd.

The acquisition was completed on July 31, 2014, with the net consideration paid at completion being $163 million, taking into account working capital and net cashflows since the transaction effective date.

SENIOR NOTES OFFERING
Following the quarter end, the Company successfully completed an offering of $300 million 8.125% senior unsecured notes due July 2019, with interest payable semi-annually. The net proceeds of the notes were used to partially repay (without cancelling) the Company's senior secured reserves based lending ("RBL") facility, with a portion of it subsequently redrawn to finance the acquisition of the Summit assets on July 31, 2014.

Given the Company's long term appraisal and development growth focus, the senior notes provide important diversity into the sources and tenor of funding within the overall capital structure of the business, as well as putting in place additional financial resources to deliver flexibility in the timing of continued growth. The notes also reduce bank funding dependency and provide cost of finance certainty through the fixed rate coupon.

The Company seeks to maintain a conservative financial profile and strong balance sheet, with ample liquidity, in order to prudently deliver its planned development activities and continue to grow the business through acceleration of upsides within the existing portfolio and by the ability to secure further valuable North Sea asset acquisitions (undeveloped discoveries and producing assets).

PRODUCTION & OPERATIONS UPDATE

Pro-forma 2014 production guidance raised to 13.5-15.5kboe/d following announcement of the Summit acquisition      

PRODUCTION
Average pro-forma production in Q2-2014 was approximately 14,300 barrels of oil equivalent per day ("boepd"), 94% oil, including the contribution from the assets acquired from Sumitomo Corporation (the "Summit Assets"). This performance is in line with the Company's pro-forma 2014 production guidance range of 13,500 to 15,500 boepd.

  • Production in Q2-2014 excluding the Summit Assets was 11,820 boepd, in line with the 2014 guidance range of 11,000 to 13,000 boepd for the Company's existing assets.  This represents a 2% decrease on the same quarter in 2013 (Q2-2013: 12,100 boepd), resulting primarily from shutdowns for maintenance and planned production enhancement activities.
  • Production in Q2-2014 for the Summit Assets was calculated to be approximately 2,500 boepd, based on available operator data, in line with the forecast 2014 pro-forma production guidance for the acquired assets.  

While the Company derives the economic benefit of production from the Summit Assets from the acquisition effective date of January 1, 2014, these assets will only be consolidated into Ithaca's financial statements from the transaction completion date of July 31, 2014.

Average pro-forma production in H1-2014, including a contribution of approximately 2,300 boepd from the Summit Assets, was approximately 12,800 boepd, 94% oil. Excluding the Summit Assets, this represents a 15% increase on the same period in 2013 (H1-2013: 9,138 boepd). The increase is primarily attributable to the inclusion of a full period's contribution from the assets acquired as a result of the Valiant Petroleum plc ("Valiant") acquisition, which completed on April 19, 2013, partially offset by an unplanned shutdown of the Cook field in Q1-2014 to repair the gas export compressor on the host facility for the field.

OPERATIONS UPDATE
During the quarter, continued progress was made on completion of the main 2014 production enhancement projects. In the Causeway Area, the Fionn sidetrack was completed along with the platform modification works required to enable start-up of the electrical submersible pumps installed in the Causeway and Fionn production wells. The platform modifications to enable start-up of water injection on the Causeway field are substantially complete, with injection expected to commence in August 2014 following close-out of on-going general water injection system refurbishment activities on the platform. Drilling operations were also completed on the Don Southwest "TJ" infill production well, with only installation of a spool piece between the wellhead and the existing drilling centre manifold required to enable start-up of the well, which is now expected in September 2014.

As previously guided, 2014 production volumes are forecast to be weighted towards the second half of the year, notably from the later part of Q3-2014 post the completion of planned summer maintenance shutdowns, as a result of the following activities:

  • Start-up of the Don Southwest "TJ" infill well and incremental production resulting from chemical treatments on a number of other wells on the field.
  • Re-start of production from the Fionn field, which is currently shut in due to the presence of a gas hydrate in the subsea line connecting the well to the main Causeway flowline.
  • Commencement of water injection on the Causeway field.
  • Re-commencement of production from the Pierce field following completion of the on-going modification works being performed on the field's floating production, storage and offloading vessel to enable tie-in of a third party field.
  • Completion of the planned well workover on the Athena field.

GREATER STELLA AREA DEVELOPMENT UPDATE
Third Stella development well completed, with strong flow test results further de-risking forecast field production performance     

DRILLING PROGRAMME
The third Stella development well, "B1", was completed in June 2014. The well was drilled to a total measured depth subsea of 16,185 feet, with a 2,147 foot gross horizontal reservoir section completed in the Palaeocene Andrew sandstone reservoir. The well intersected high quality sands across a net reservoir interval of 2,034 feet, equating to 95% net pay. As with the previous two Stella development wells, a clean-up flow test was performed on the B1 well. The well flowed at a maximum rate of 12,492 boepd (7,565 bopd and 29.6 MMscf/d of gas) on a 48/64-inch choke, with the full production potential of the well limited by the capacity of the well test equipment on the drilling rig. This compares to the results of the Stella "A1" and "A2" wells that achieved maximum flow rates of 10,835 boepd and 10,442 boepd, respectively.

The test results achieved on the first three Stella development wells have served to de-risk the initial annualised production forecast for the GSA hub of approximately 30,000 boepd (100%), 16,000 boepd net to Ithaca.

Drilling operations commenced on the fourth Stella development well in early July 2014. The well, which is targeting the gas cap on the crest of the structure, is being drilled from the same location as the third well and is scheduled to be completed in October 2014.

The first four wells on the Stella field are in the Andrew reservoir. A fifth well on the field is included in the Field Development Plan, targeting the Stella Ekofisk chalk reservoir that lies beneath the principal Andrew reservoir. This well will now be drilled in continuation with the current programme to capitalise on the strong operational experience of the ENSCO 100 rig and associated cost efficiencies, as well as enabling the addition of further oil production capacity at the start-up of the hub to take advantage of spare oil processing capacity on the FPF-1.

The fifth well will be drilled from the Stella Main Drill Centre. Prior to commencing drilling of the Ekofisk well, ENSCO will take advantage of the required rig move from the Northern Drill Centre to demobilise the rig to harbour for approximately one month to complete a routine 5-year rig inspection programme that it is required to perform.

Management of the drilling and completion operations is being performed by Applied Drilling Technology International ("ADTI") under "turnkey" contract arrangements.    

2014 subsea installation works progressing well

SUBSEA INFRASTRUCTURE WORKS
Over two thirds of the overall subsea infrastructure installation activities have now been completed. The key outstanding workscopes involve the tie-in of the wells, installation of the vessel mooring spread, the mid-water arch over which the risers and umbilicals are laid, the Single Anchor Loading ("SAL") oil export facilities and the dynamic flexible risers and umbilicals that will connect the riser bases to the FPF-1.

Offshore operations re-commenced in April 2014, with the tie in of the first two Stella development wells at the Main Drill Centre. Installation of the FPF-1 mooring piles to which the vessel will be anchored, along with the pile for the oil export SAL, has recently been completed. Installation of the anchor chains that will be connected to the piles and left ready for pull-in upon arrival of the FPF-1 on location will commence shortly.

It is now planned for installation of the mid-water arch and the oil export pipeline and associated SAL system to be completed next year in order to accommodate Technip's vessel availabilities and take advantage of operational synergies in preparing for arrival of the FPF-1 on location. Execution of the main subsea infrastructure manufacturing and installation programme is being completed by Technip under an integrated Engineering, Procurement, Installation and Construction contract.

Focus on FPF-1 processing plant construction activities      

FPF-1 MODIFICATION WORKS
Completion of the FPF-1 modifications programme is the key development activity dictating the overall schedule for first hydrocarbons from the GSA hub. As highlighted in May 2014, whilst progress was being made on the topsides processing plant construction programme, it was advancing more slowly than planned. As a consequence, it was announced that the vessel would be ready for sail-away from the Remontowa yard in Poland to the Stella field in spring 2015. This schedule is anticipated to result in first hydrocarbons from the GSA hub in mid-2015. Since the schedule update, Petrofac has made good progress implementing changes to expedite completion of the remaining modification works, including managerial changes in the yard team and the deployment of increased manpower on the construction workscopes.

The key focus of the on-going modification works is centred on construction activities on the main deck of the FPF-1, along with fit out of the accommodation module, following which commissioning operations will be completed. The main oil and gas processing plant packages (power generation, gas export compressors, etc.) have been positioned on the vessel and installation of the associated pipework has commenced. Fit out of the accommodation module is progressing well, with handover for pre-commissioning expected shortly.

During the quarter, the FPF-1 Operational Safety Case was approved by the UK Health and Safety Executive. This is a key regulatory approval required to enable the start-up of FPF-1 once on location.

Execution of the FPF-1 modifications work programme is being performed by Petrofac under the terms of a lump sum incentivised contract with the GSA co-venturers.

PORTFOLIO ACTIVITIES
Continued restructuring of former Valiant Norwegian portfolio completed      

As part of restructuring the Norwegian portfolio transferred as part of the Valiant Petroleum plc ("Valiant") acquisition into a small, focused exploration and appraisal operation centred on lower risk geological and geographic opportunities capable of monetisation prior to development, the Company has entered into an agreement with Talisman to acquire two non-operated interests in the Norwegian North Sea. The interests are: a 25% interest in Licence PL672 containing the "SnØmus" prospect, which lies approximately 7 kilometres from the Varg field and associated FPSO facilities; and, a 20% interest in license PL019C containing the "Kark" prospect, which lies approximately 7 kilometres from the Gyda platform. It is anticipated that a well will be drilled on SnØmus in 2015 and Kark in 2016. Completion of the transaction is subject to normal regulatory consents.

Lupus (Norway): Drilling operations were concluded on the Tullow Oil Norge AS ("Tullow") operated Lupus exploration well in the Norwegian North Sea in July 2014 in which the Company had a 10% working interest. While the well identified good quality reservoir sandstone in the target formation, no hydrocarbons were encountered. The drilling programme was completed slightly ahead of the planned duration, with the final net cost of the well anticipated to be approximately $1.1 million, net of the 78% Norwegian tax refund. The Company established its position in the Lupus prospect as part of a licence interest swap with Tullow that enabled it to exit the Barents Sea licences transferred from Valiant.

Q2 2014 RESULTS OF OPERATIONS

REVENUE
Revenue up 6% on H1-2013      

Three months ended June 30, 2014
Revenue decreased by $28.5 million from Q2 2013 to $99.9 million (Q2 2013: $128.4 million). This was primarily driven by a decrease in oil sales volumes partially offset by a modest increase in revenue associated with a higher realised oil price.

Oil sales volumes decreased primarily due to the changes in the timing of liftings from Q2 2013. There were no liftings on the Cook field in Q2 2014 as seen from the build-up of inventory described below.

The decrease in gas sales in Q2 2014 compared to Q2 2013 was primarily due to the reduction in realised gas prices per boe, driven by a reduction in the spot gas market.

There was an increase in average realized oil prices from $103/bbl in Q2 2013 to $109/bbl in Q2 2014. The average Brent price for the quarter ended 30 June 2014 was $110/bbl compared to $102 for Q2 2013. The Company's realized oil prices do not strictly follow the Brent price pattern given the various oil sales contracts in place, with some fields sold at a discount or premium to Brent and also impacted by differing timescales for pricing. This increase in realized oil price was partially offset by a realized hedging loss of $4/bbl in the quarter.

Six Months Ended June 30, 2014
Revenue increased by $11.5 million in H1 2014 to $199.6 million (H1 2013: $188.1 million). This movement is predominantly due to an increase in oil sales volumes combined with an increase in realised oil price. The sales volumes in H1 2014 were higher than the comparable period in 2013 primarily due to inclusion of a full period's contribution from the assets acquired from Valiant Petroleum plc in April 2013 (production consolidated from April 19, 2013).

There was an increase in average realized oil prices from $104/bbl in H1 2013 to $109/bbl in H1 2014. The average Brent price for the six months ended 30 June 2014 was $107/bbl compared to $108/bbl for H1 2013. As above, the Company's realized oil prices do not strictly follow the Brent price pattern. The increase in realized oil price was partially offset by a realized hedging loss of $4/bbl in the period.

Total gas sales decreased largely as a result of lower production volumes in the period due to the Topaz field being shut-in for a period to repair a hydraulic leak. 

             
        3-Months Ended June 30th   6-Months Ended June 30th
Average Price   Realised   2014   2013   2014   2013
Oil Pre-Hedging   $/bbl   109   103   109   104
Oil Post-Hedging   $/bbl   104   111   105   112
Gas   $/boe   29   41   37   44
                     
                     
                     
COST OF SALES                    
                     
    3-Months Ended June 30th   6-Months Ended June 30th
          Restated         Restated
$'000   2014     2013   2014     2013
Operating Expenditure   51,896     43,155   93,159     66,382
DD&A   51,307     46,221   83,772     65,719
Movement in Oil & Gas Inventory   (15,596 )   18,137   (3,735 )   21,713
Oil Purchases   373     790   793     947
Total   87,980     108,303   173,989     154,761
                     
                     

Three months ended June 30, 2014
Cost of sales decreased in Q2 2014 to $88.0 million (Q2 2013: $108.3 million) primarily due to movement in oil and gas inventory partially offset by increases in operating costs and depletion and depreciation and amortization ("DD&A").

Operating costs increased in the quarter to $51.9 million (Q2 2013: $43.2 million) mainly due to higher Causeway Area production levels resulting in additional tariff related costs, and higher cost share contributions for the use of third party infrastructure (the Sullom Voe terminal that processes oil from the Company's Northern North Sea assets and the Anasuria FPSO that serves the Cook field). This drove an increase in unit operating costs to $48/boe in the quarter (Q2 2013: $39/boe). Unit operating costs for the full year are expected to fall as a result of the ongoing production enhancement activities on a number of the Company's fields and the consolidation of the Summit Assets from July 31, 2014.

DD&A expense for the quarter increased to $51.3 million (Q2 2013: $46.2 million). This was primarily due to higher production volumes in Q2 2014 from the Causeway Area fields, together with a full quarter of DD&A on the Dons field (only as of April 19, 2013). This resulted in the unit DD&A rate for the quarter increasing to $48/boe (Q2 2013: $42/boe).

As the below "Changes in Accounting Policies" section outlines, the adoption of IFRS and accounting for acquisitions as business combinations has led to increased DD&A rates, representing the majority of the rate increase. It should be noted that this increase in DD&A and hence Cost of Sales is substantially offset by a credit in the Deferred Tax charged through the Income Statement.

An oil and gas inventory movement of $15.6 million was credited to cost of sales in Q2 2014 (Q2 2013 charge of $18.1 million). Movements in oil inventory arise due to differences between barrels produced and sold with production being recorded as a credit to movement in oil inventory through cost of sales until oil has been sold. In Q2 2014 more barrels of oil were produced (1,018 kbbls) than sold (894 kbbls), mainly as a result of the timing of Cook field liftings. 

             
Movement in Operating Oil & Gas Inventory   Oil kbbls   Gas kboe   Total kboe
Opening inventory   94   3   97
Production   1,018   58   1,076
Liftings / sales   894   51   945
Transfers/other*   11   -   11
Closing volumes   229   10   239
* Due to long term inventory transfers and terminal quality adjustments etc.
             
             

Six Months Ended June 30, 2014
Cost of sales increased in H1 2014 to $174.0 million (H1 2013: $154.8 million) due to increases in operating costs and DD&A, partially offset by the movement in oil and gas inventory.

Operating costs increased in the period to $93.2 million (H1 2013: $66.4 million) primarily due to the inclusion of costs for the Dons and Causeway Area fields acquired from Valiant (full H1 2014 compared to only as of April 19, 2013). Planned shutdowns in the period on Beatrice and Jacky and some weather related production downtime, particularly in relation to the Cook field during the first quarter of the year, also contributed to the increase.

DD&A for the period increased to $83.8 million (H1 2013: $65.7 million). This was primarily due to higher production volumes in H1 2014 with the addition of the Dons and Causeway fields, offset by no DD&A on the Beatrice and Jacky fields with these assets now fully written down.

An oil and gas inventory movement of $3.7 million was credited to cost of sales in H1 2014 (H1 2013: charge of $21.7 million). In H1 2014 more barrels of oil were produced (1,806 kbbls) than sold (1,786 kbbls), again mainly as a result of the timing of Cook and Dons field liftings.

CONTINGENT LIABILITY
The costs from the Sullom Voe Terminal ("SVT"), which receives oil from the Dons and Causeway areas, are billed monthly on forecast allocations and a reconciliation invoice is received in the second quarter of the following year based on actual allocations. The monthly SVT billings for 2013 have all been expensed and paid.

In June and July 2014, Ithaca received inconsistent notifications regarding the reconciliation charge in respect of 2013.  As a result, Ithaca has not been able to verify the underlying input data and calculations. The matter is being investigated with the SVT operator and additional, relevant information is being requested. Accordingly, management has not yet been able to determine the final amount that will be payable. It is possible that the reconciliation charge could be up to $12 million ($5 million post tax), which has not been recorded because of the uncertainty over the matter. The final amount of the 2013 reconciliation invoice is expected to be recognised in the Q3 2014 interim financial statements.

Agreements are in place to simplify the method of allocation of SVT costs after 2014 and to base the allocation predominately on oil throughputs, making forecasting more straightforward and reducing the potential significant cost allocation distortions inherent in the current allocation process.

                 
ADMINISTRATION & EXPLORATION & EVALUATION EXPENSES
                 
    3-Months Ended June 30th   6-Months Ended June 30th
$'000   2014   2013   2014   2013
General & Administration   3,507   3,623   6,778   5,415
Share Based Payments   339   366   766   663
Total Administration Expenses   3,846   3,989   7,544   5,478
Non-recurring Valiant Acquisition Costs   -   9,554   -   10,235
Exploration & Evaluation   446   132   2,454   443
Impairment   -   -   2,895   -
Total   4,292   13,675   12,893   16,756
                 
                 

Three Months Ended June 30, 2014
Total administrative expenses remained relatively steady in the quarter at $3.8 million (Q2 2013: $4.0 million). Around $1.7 million of the G&A cost relates to the costs of the Norwegian office, however, approximately half is recovered as a cash tax refund from the Norwegian government - the credit is recorded under Taxation. Share based payment expenses remained relatively flat as a result of no new options being granted during the quarter (no grant in Q2 2013). Exploration and evaluation expenses of $0.4 million were recorded in the quarter (Q2 2013: $0.1 million) primarily associated with costs relating to Norwegian licences deemed non-commercial.

Six Months Ended June 30, 2014
Total administrative expenses increased in the period to $7.5 million (H1 2013: $5.5 million) primarily due to an increase in general and administrative expenses as a result of the associated costs of an enlarged Ithaca group post the Valiant acquisition.

The impairment charge above represents further costs of a capital nature recognised in the first quarter of 2014 on Beatrice and Jacky, both of which were fully written down at December 31, 2013 in anticipation of their handback to Talisman.

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS

Three Months Ended June 30, 2014
A foreign exchange gain of $2.2 million was recorded in Q2 2014 (Q2 2013: $2.6 million loss). The majority of the Company's revenue is US dollar driven while expenditures are incurred in British pounds, US dollars and Euros. General volatility in the USD:GBP exchange rate is the primary driver behind the foreign exchange gains and losses, particularly on the revaluation of non USD bank accounts and working capital balances (USD:GBP at April 1, 2014: 1.66. USD:GBP at June 30, 2014: 1.70 with fluctuations between 1.65 and 1.71 during the quarter).

The Company recorded an overall $11.2 million loss on financial instruments for the quarter ended June 30, 2014 (Q2 2013: $17.5 million gain).  A $3.8 million cash loss was realised in respect of instruments which expired during the quarter - comprising a $3.7 million realised loss on commodity hedges and a $0.2 million realised loss on interest rate instruments.

Also contributing to the loss was the revaluation of instruments at June 30, 2014 which relates to instruments still held at the quarter end. This $7.4 million non-cash revaluation primarily related to a $9.7 million downward revaluation of oil hedges, due to a decrease in value of oil swaps and put options based on the increase in the Brent oil forward curve from the previous quarter end and the implied volatility at the end of the reporting period, offset by a $2.8 million upwards revaluation of gas hedging instruments. The Company does not apply hedge accounting, which can therefore lead to volatility in the results due to the impact of revaluing the financial instruments at each reporting period end. The Brent spot price closed at $111 at June 30, 2014, an increase from $106 at March 31, 2014, resulting in a mark-to-market loss on commodity hedges that have been entered into to ensure realised prices of over $100/bbl are obtained.

Six Months Ended June 30, 2014
A foreign exchange gain of $1.8 million was recorded in H1 2014 (H1 2013: $2.1 million loss). As highlighted above, general volatility in the USD:GBP exchange rate was the main driver behind the foreign exchange gain in H1 2014 (USD:GBP at January 1, 2014: 1.65. USD:GBP at June 30, 2014: 1.70 with fluctuations between 1.62 and 1.71 during the period).

The Company recorded a $7.2 million loss on financial instruments for the six months ended June 30, 2014 (H1 2012: $10.3 million gain). A $2.5 million cash loss was realised in respect of instruments which expired during the quarter - comprising a $6.3 million realised loss on commodity hedges and a $0.2 million realised loss on interest rate instruments, partially offset by a $4.0 million realised gain on foreign exchange instruments.

Also contributing to the loss was the revaluation of instruments at June 30, 2014 which relates to instruments still held at the period end. This $4.7 million non-cash revaluation primarily related to a $4.2 million revaluation loss on foreign exchange instruments and a $3.3 million downward revaluation of oil hedges, partially offset by a $3.4 million upwards revaluation of gas hedging instruments and a $0.2 million revaluation gain on interest rate swaps.

BUSINESS COMBINATIONS

NEGATIVE GOODWILL
If the cost of an acquisition is more than the fair value of net assets acquired, the difference is recognised on the balance sheet as goodwill. Conversely, if the cost of an acquisition is less than the fair value of the assets acquired, the difference is recognised as negative goodwill in the statement of income. As a result of business combination accounting $54.4 million of negative goodwill was recognised in Q2 2013 in relation to the Valiant Acquisition (Q2 2014: Nil). A further $0.9 million of negative goodwill in relation to the Cook acquisition from Noble was recognised in Q1 2013, being a total of $55.3 million of negative goodwill recognised in H1 2013 (H1 2014: Nil).

GAIN ON FARM-OUT
In the six months ended June 30, 2014, a gain of $2.2 million was recognised in the income statement as a result of the farm-out of the Company's cost commitments for and certain rights to the Handcross well, an exploration commitment acquired as part of the Valiant Acquisition. (Q2 2014, Q2 2013 and 1H 2013: Nil)

FINANCE COSTS

Three Months Ended June 30, 2014
Finance costs increased to $5.7 million in Q2 2014 (Q2 2013: $5.0 million). This rise primarily reflects interest and fees incurred in relation to the Company's increased debt financing facilities and the drawdowns therefrom.

Six Months Ended June 30, 2014
Finance costs increased to $12.0 million in H1 2014 (H1 2013: $7.3 million). This rise again primarily reflects increased interest and fees incurred in relation to additional drawings under the Company's RBL debt facility combined with fees and drawings under the Norwegian tax refund facility (the "Norwegian Facility") signed in Q3 2013. Total debt drawn in the period has increased from $375.9 million in Q2 2013 to $615.8 million in Q2 2014. 

TAXATION
No UK tax anticipated to be payable in the mid-term     

Three Months Ended June 30, 2014
A tax credit of $7.7 million was recognized in the quarter ended June 30, 2014 (Q2 2013: $16.8 million credit). $6.4 million  is a non-cash credit relating to UK taxation, due to a combination of the taxable loss generated and adjustments to deferred tax, primarily the UK Ring Fence Expenditure Supplement. As noted in the Cost Of Sales section the deferred tax credit is increased by the use of accounting for acquisitions as business combinations.

The remaining $1.3 million credit is due to Norwegian tax refunds, which have been generated as a result of exploration related expenditure, incurred by Ithaca's Norwegian operations during Q2 2014. Norwegian tax refunds totalling $79 million recognised on the balance sheet relate to Norwegian capital expenditure.

As a result of the above factors, profit after tax increased to $0.7 million (Q2 2013: $53.8 million).

No Corporation or Supplementary tax is expected to be paid over the medium term future relating to upstream oil and gas activities as a result of the $1,246 million of UK tax losses available to the Company. Petroleum Revenue Tax of 50% will be payable on cashflows generated by the Company's Wytch Farm field interest.

Six Months Ended June 30, 2014
A tax credit of $19.5 million was recognised in the six months ended June 30, 2014 (H1 2013: $15.7 million charge). $16.9 million of this non-cash charge relates to UK taxation and is a product of the taxable loss generated and adjustments to deferred tax charge primarily relating to the UK Ring Fence Expenditure Supplement and share based payments.

The remaining $2.6 million credit is due to Norway tax credits which have been generated as a result of exploration expenditure incurred by Ithaca's Norwegian operations.

As a result of the above factors, profit after tax increased to $17.0 million (H1 2013: $57.3 million).

CAPITAL INVESTMENTS
Capital expenditure on development and production ("D&P") assets totalled $209 million in H1 2014. This related primarily to development drilling operations on the Stella field, subsea infrastructure installation activities for the GSA hub and the on-going modification works on the FPF-1, along with drilling of the Fionn sidetrack and also the Don Southwest "TJ" well.

Capital expenditure on E&E assets in H1 2014 was $28.9 million, offset by a $4.2 million release of the acquired E&E liability, resulting in a net addition of $24.7 million. Expenditure was primarily focused on the Trell exploration well in Norway where 78% of the cost is subsequently reimbursed by the Norwegian Government.

LIQUIDITY AND CAPITAL RESOURCES
Significant investment in development projects      

             
$'000   Q2 2014   Q4 2013   Increase / (Decrease)
Cash & Cash Equivalents   50,753   63,435   (12,682)
Restricted cash   12,610   12,198   412
Trade & Other Receivables   419,858   335,877   83,981
Inventory   25,498   21,632   3,866
Other Current Assets   5,063   5,102   (39)
Trade & Other Payables   (515,477)   (472,396)   (43,081)
Net Working Capital*   (1,695)   (34,152)   32,457
             
*Working capital being total current assets less trade and other payables
             
             

The Company's liquidity requirements arise principally from capital investment and working capital demands. For the periods presented, Ithaca met its liquidity requirements primarily from ongoing cashflow generation from the producing assets and debt financing through ongoing drawings on the RBL Facility and Norwegian Facility.

As at June 30, 2014, Ithaca had a net working capital balance of $(1.7) million including a free cash balance of $50.8 million and $12.6 million restricted cash. Available cash has been, and is currently, invested in money market deposit accounts with BNP Paribas.  Management has received confirmation from the financial institution that these funds are available on demand.

Cash and cash equivalents decreased as a result of continued cash investment in the ongoing Stella field development and the Fionn sidetrack well, offset by drawings from bank facilities in the quarter.

Trade and Other Receivables have increased in the six months to June 30, 2014 predominantly due to an increase in working capital associated with the GSA development. 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. The Company assesses partners' credit worthiness before entering into joint venture agreements. The Company regularly monitors all customer receivable balances outstanding in excess of 90 days. As at June 30, 2014 substantially all of the accounts receivable is current, being defined as less than 90 days. In the past, the Company has not experienced credit loss in the collection of accounts receivable.

Trade and Other Payables have increased in the six months to June 30, 2014 predominantly due to the cash advances of $41 million under the Shell oil sales agreements combined with an increase in working capital associated with the GSA development.

At June 30, 2014, Ithaca had two UK loan facilities available, being the $610 million RBL Facility and the $100 million corporate debt facility. At the quarter end, the Company had unused UK credit facilities totalling approximately $160 million (Q4 2013: $300 million), with approximately $550 million drawn under the RBL Facility. The Company also has a Norwegian Facility of NOK 450 million (~$75 million), under which approximately $66 million was drawn as at June 30, 2014.

Following the quarter end the Company successfully completed an offering of $300 million 8.125% senior unsecured notes due July 2019 and executed an amendment to the Norwegian Facility to increase the facility size from NOK 450 million (~$75 million) to NOK 600 million (~$100 million).

During the quarter ended June 30, 2014 there was a cash inflow from operating, investing and financing activities of approximately $11.6 million (Q2 2013 outflow of $38.5 million).

Cashflow from operations
Cash generated from operating activities was $101.8 million primarily due to cash generated from Cook, Athena, Dons, Causeway, Beatrice, Jacky, Anglia, and Broom operations.

Cashflow from financing activities
Cash generated from financing activities was $172.2 million primarily due to drawdowns under the RBL debt facility in the quarter.

Cashflow from investing activities
Costs incurred in investing activities were $253.4 million. The main components of capital expenditure related to drilling of the second and third development wells, installation of the FPF-1 mooring system and continued construction and commissioning of processing plant on the FPF-1 as part of the GSA development, the drilling of the Fionn sidetrack well and drilling operations on the Don Southwest TJ well. $21 million was also advanced to FPF-1 Limited, an associate company, in relation to hull modification costs.

The Company remains fully funded, with more than sufficient financial resources to cover its anticipated future commitments from its existing cash balance, debt facilities, forecast cashflow from operations and senior notes issued post quarter end. No unusual trends or fluctuations are expected outside the ordinary course of business.

             
COMMITMENTS            
             
$'000   1 Year   2-5 Years   5+ Years
Office Leases   935   2,478   -
Other Operating Leases   11,543   12,078   -
Exploration Licence Fees   696   -   -
Engineering   49,008   2,699   -
Rig Commitments   46,979   -   -
Total   109,161   17,255   -
             
             

The engineering financial commitments relate to the Company's share of committed capital expenditure on the GSA development, as well as ongoing capital expenditure on existing producing fields. Rig commitments reflect rig hire costs committed in relation to the anticipated Stella wells as well as committed rig hire costs relating to the Don Southwest well and upcoming Athena workover. As stated above, these commitments are expected to be funded through the Company's existing cash balance, forecast cashflow from operations and its available debt facility.

FINANCIAL INSTRUMENTS

All financial instruments are initially measured in the balance sheet at fair value.  Subsequent measurement of the financial instruments is based on their classification.  The Company has classified each financial instrument into one of these categories:

     
Financial Instrument Category Ithaca Classification Subsequent Measurement
Held-for-trading Cash, cash equivalents, restricted cash, derivatives, commodity hedges, long-term liability Fair Value with changes recognised in net income
Held-to-maturity - Amortised cost using effective interest rate method.

Transaction costs (directly attributable to acquisition or issue of financial asset/liability) are adjusted to fair value initially recognised. These costs are also expensed using the effective interest rate method and recorded within interest expense.

Loans and Receivables Accounts receivable
Other financial liabilities Accounts payable, operating bank loans, accrued liabilities
     
     

The classification of all financial instruments is the same at inception and at June 30, 2014.

The table below presents the total gain / (loss) on financial instruments that has been disclosed through the statement of comprehensive income. 

                       
    Three months ended June 30th   Six months ended June 30th  
$'000   2014     2013   2014     2013  
Revaluation Forex Forward Contracts   -     584   (4.171 )   (1,471 )
Revaluation of Interest Rate Swaps   (111 )   -   (234 )   -  
Revaluation of Other Long Term Liability   (393 )   96   (370 )   153  
Revaluation of Commodity Hedges   (6,877 )   6,623   72     (2,444 )
Total Revaluation (Loss) / Gain   (7,381 )   7,303   (4,703 )   (3,762 )
Realised Gain on Forex Contracts   -     837   4,028     544  
Realised Gain/(Loss) on Commodity Hedges   (3,667 )   9,374   (6,341 )   13,560  
Realised Loss on Interest Rate swaps   (155 )   -   (225 )      
Total Realised (Loss) / Gain   (3,822 )   10,211   (2,538 )   14,104  
Total Gain/(Loss) on Financial Instruments   (11,203 )   17,514   (7,241 )   10,342  
                       
                       

The following table summarises the commodity hedges in place at the end of the quarter. 

             
Derivative   Term   Volume bbl   Average Price $/bbl
Oil Swaps   July 2014 - June 2016   2,358,586   102
Put Options   July 2014 - June 2016   920,647   101
             
Derivative   Term   Volume Therms   Average Price p/therm
Gas Swaps   July 2014 - December 2014   809,600   67
Gas Puts   October 2015 - June 2017   187,300,000   63
             
             

Post quarter end, further oil swaps and oil puts were entered into for approximately 0.4 million barrels of production for the period to Q1 2016 at a weighted average price of $107/bbl, 70% puts / 30% swaps ($105/bbl net of put premiums).

As at August 11, 2014 the Company had the following hedging in place:

Oil Hedging

  • 3.6 million barrels of oil production over the next 2 years hedged at $102/bbl, 70% swaps / 30% puts ($100/bbl net of put premiums). This hedging underpins approximately $370 million of revenue while retaining oil price upside on a third of the hedged volume.

Gas Hedging

  • Approximately 190 million therms (20 Bcf) of gas sales hedged at a floor price of £0.58/therm (~$10/MMBTU) out until gas year 2016. This hedging underpins approximately $190 million of revenue (net of all hedging costs) while retaining upside to rising gas prices beyond £0.63/therm on almost 100% of the hedged volume.

The Company also enters into interest rate swaps as a measure of hedging its exposure to interest rate risks on the loan facilities. The below summaries the interest rate financial instruments in place at the end of the period.

   
Derivative Interest rate swap
Term Dec 15
Value $200 million
Rate 0.44%
   
   
 
 
QUARTERLY RESULTS SUMMARY
 
        Restated1  
$'000 30 Jun 2014 31 Mar 2014 31 Dec 2013 30 Sep 2013 30 Jun 2013 31 Mar 2013 31 Dec 2012 30 Sep 2012
Revenue 99,931 96,600 111,696 114,112 128,360 59,769 52,566 41,579
Profit After Tax 659 16,365 44,242 43,145 53,828 3,472 45,347 4,894
                 
Earnings per share "EPS" - Basic2 0.00 0.05 0.14 0.14 0.18 0.01 0.17 0.02
EPS - Diluted2 0.00 0.05 0.13 0.13 0.17 0.01 0.17 0.02
Common shares outstanding (000) 328,399 326,195 323,634 317,366 317,366 259,953 259,920 259,346

1 Q2-13 and Q3-13 restated to account for adjustment to Valiant acquisition accounting

2 Based on weighted average number of shares

The most significant factors to have affected the Company's results during the above quarters, other than transactions such as the Valiant acquisition, are fluctuations in underlying commodity prices and movement in production volumes. The Company has utilized forward sales contracts and foreign exchange contracts to take advantage of higher commodity prices while reducing the exposure to price volatility. These contracts can cause volatility in profit after tax as a result of unrealized gains and losses due to movements in the oil price and USD: GBP exchange rate.

OUTSTANDING SHARE INFORMATION
The Company's common shares are traded on the Toronto Stock Exchange ("TSX") in Canada under the symbol "IAE" and on the Alternative Investment Market ("AIM") in the United Kingdom under the symbol "IAE". As at June 30, 2014 Ithaca had 328,398,620 common shares outstanding along with 16,993,567 options outstanding to employees and directors to acquire common shares. Due to the exercise and listing of option shares following the end of Q2-2014, as at August 11, 2014, Ithaca had 329,518,620 common shares outstanding along with 15,968,567 options outstanding to employees and directors to acquire common shares.

 
  June 30, 2014
Common Shares Outstanding 328,398,620
Share Price(1) $2.49 / Share
Total Market Capitalisation $817,712,564
(1) Represents the TSX close price (CAD$2.75) on June 30, 2014. US$:CAD$ 0.9039 on June 30, 2014

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 Holdings"),
  • Ithaca Energy (UK) Limited ("Ithaca UK"),
  • Ithaca Minerals North Sea Limited ("Ithaca Minerals")
  • Ithaca Energy Holdings (UK) Limited ("Ithaca Holdings UK")
  • Ithaca Petroleum Limited (formerly Valiant Petroleum plc)
  • Ithaca Causeway Limited (formerly Valiant Causeway Limited)
  • Ithaca Exploration Limited (formerly Valiant Exploration Limited)
  • Ithaca Alpha (NI) Limited (formerly Valiant Alpha (NI) Limited
  • Ithaca Gamma Limited (formerly Valiant Gamma Limited)
  • Ithaca Epsilon Limited (formerly Valiant Epsilon Limited)
  • Ithaca Delta Limited (formerly Valiant Delta Limited)
  • Ithaca North Sea Limited (formerly Valiant North Sea Limited)
  • Ithaca Petroleum Holdings AS (formerly Valiant Petroleum Holdings AS)
  • Ithaca Petroleum Norge AS (formerly Valiant Petroleum Norge AS)
  • Ithaca Technology AS (formerly Valiant Technology AS)
  • Ithaca AS (formerly Querqus AS)
  • Ithaca Petroleum EHF (formerly Valiant Petroleum EHF)

The consolidated financial statements include, from April 19, 2013 only (being the acquisition date), the consolidated financial statements of the Valiant group of companies.

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.

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.

Capitalized costs relating to the exploration and development of oil and gas reserves, along with estimated future capital expenditures required in order to develop proved and probable reserves are depreciated on a unit-of-production basis, by asset, using estimated proved and probable reserves as adjusted for production.

A review is carried out each reporting date for any indication that the carrying value of the Company's D&P assets may be impaired. For D&P assets where there are such indications, an impairment test is carried out on the Cash Generating Unit ("CGU").  Each CGU is identified in accordance with IAS 36.  The 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 to sell and value in use, where the value in use is determined from estimated future net cash flows.  Any additional depreciation resulting from the impairment testing is charged to the Statement of Income.

Goodwill is tested annually for impairment and also when circumstances indicate that the carrying value may be at risk of being impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU to which the goodwill relates. Where the recoverable amount of the CGU is less than its carrying amount, an impairment loss is recognized in the Statement of Income. Impairment losses relating to goodwill cannot be reversed in future periods.

Recognition of decommissioning liabilities associated with oil and gas wells are determined using estimated costs discounted based on the estimated life of the asset. In periods following recognition, the liability and associated asset are adjusted for any changes in the estimated amount or timing of the settlement of the obligations. The liability is accreted up to the actual expected cash outlay to perform the abandonment and reclamation. The carrying amounts of the associated assets are depleted using the unit of production method, in accordance with the depreciation policy for development and production assets. Actual costs to retire tangible assets are deducted from the liability as incurred.

All financial instruments are initially recognized at fair value on the balance sheet. The Company's financial instruments consist of cash, restricted cash, accounts receivable, deposits, derivatives, accounts payable, accrued liabilities and the long term liability on the Beatrice acquisition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.

In order to recognize share based payment expense, the 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
Ithaca has established disclosure controls, procedures and corporate policies so that its consolidated financial results are presented accurately, fairly and on a timely basis. The Chief Executive Officer and Chief Financial Officer have designed, or have caused such internal controls over financial reporting to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of the Company's financial statements in accordance with IFRS with no material weaknesses identified.

Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements and even those options determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

As of June 30, 2014, there were no changes in Ithaca's internal control over financial reporting that occurred during the period ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

CHANGES IN ACCOUNTING POLICIES
On January 1, 2011, the Company adopted IFRS using a transition date of January 1, 2010. The financial statements for the period ended June 30, 2014, including required comparative information, have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board ("IASB").

The Company elected to present all acquisitions since the IFRS transition date as business combinations in accordance with IFRS 3®.  

One impact of accounting for acquisitions as business combinations is the recognition of asset values, upon which the DD&A rate is calculated as pre-tax fair values and the recognition of a deferred tax liability on estimated future cash flows. With current tax rates at 62% this increases the DD&A charge for such assets. An offsetting reduction is recognised in the deferred tax charged through the consolidated statement of income.

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 of IFRICs that are effective for the first time for this interim period that would be expected to have a material impact on the Company.

    ADDITIONAL INFORMATION
Non-IFRS Measures   'Cashflow from operations' referred to in this MD&A is not prescribed by IFRS. This non-IFRS financial measure does not have any standardized meaning and therefore is unlikely to be comparable to similar measures presented by other companies. The Company uses this measure 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.
Off Balance Sheet Arrangements   The Company has certain lease agreements and rig commitments which were entered into in the normal course of operations, all of which are disclosed under the heading "Commitments", above. Leases are treated as either operating leases or finance leases based on the extent to which risks and rewards incidental to ownership lie with the lessor or the lessee under IAS 17. No asset or liability value has been assigned to any leases on the balance sheet as at June 30, 2014.
Related Party Transactions   A director of the Company is a partner of Burstall Winger Zammit LLP who acts as counsel for the Company. The amount of fees paid to Burstall Winger Zammit LLP in Q2 2014 was $0.1 million (Q2 2013: $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 June 30, 2014 the Company had a loan receivable from FPF-1 Ltd, an associate of the Company, for $52.3 million (December 31, 2013: 31.6 million) 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, utilizing a conversion ratio at 6 mcf: 1 bbl may be misleading as an indication of value.
Well Test Results   Certain well test results disclosed in this MD&A represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery there from.
         
         
    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 dated March 28, 2014, (the "AIF") filed on SEDAR at http://www.sedar.com/.
         
    RISK   MITIGATIONS
Commodity Price Volatility   The Company's performance is significantly impacted by prevailing oil and natural gas prices, which are primarily driven by supply and demand as well as economic and political factors.   In order to mitigate the risk of fluctuations in oil and gas prices, the Company routinely executes commodity price derivatives, predominantly in relation to oil production, as a means of establishing a floor in realised prices.
Foreign Exchange Risk   The Company is exposed to financial risks including financial market volatility and fluctuation in various foreign exchange rates.   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 GB Sterling to settle Sterling costs which will be repaid from surplus Sterling generated revenues derived from Stella gas sales.
Interest Rate Risk   The Company is exposed to fluctuation in interest rates, particularly in relation to the debt facilities entered into.   In order to mitigate the fluctuations in interest rates, the Company routinely reviews cost exposures as a result of varying rates and assesses the need to lock in interest rates.
Debt Facility Risk   The Company is exposed to borrowing risks relating to drawdown of its debt facilities (the "Facilities"). The ability to drawdown the Facilities is based on the Company meeting certain covenants including coverage ratio tests, liquidity tests and development funding tests, which are determined by a detailed economic model of the Company. There can be no assurance that the Company will satisfy such tests in the future in order to have access to the full amount of the Facilities.    The Company believes that there are no circumstances at present that result in its failure to meet the financial tests and it can therefore draw down upon its Facilities.
   
The Facilities include covenants which restrict, among other things, the Company's ability to incur additional debt or dispose of assets. The Company routinely produces detailed cashflow forecasts to monitor its compliance with the financial tests and liquidity requirements of the Facilities.
   
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's defaults on the Facilities.  
Financing Risk   To the extent cashflow from operations and the Facilities' resources are ever deemed not adequate to fund Ithaca's cash requirements, external financing may be required. Lack of timely access to such additional financing, or access on unfavourable terms, could limit Ithaca's ability to make the necessary capital investments to maintain or expand its current business and to make necessary principal payments under the Facilities may be impaired.   The Company has established a fully funded business plan and routinely monitors its detailed cashflow forecasts and liquidity requirements to maintain its funding requirements.
   
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. The Company believes that there are no circumstances at present that would lead to selected divestment, delays to existing programs or a default relating to the Facilities.
Third Party Credit Risk   The Company is and may in the future be exposed to third party credit risk through its contractual arrangements with its current and future joint venture partners, marketers of its petroleum production and other parties.   The Company believes this risk is mitigated by the financial position of the parties.  The joint venture partners in those assets operated by the Company are largely well financed international companies. Where appropriate, a cash call process has been implemented with partners to cover high levels of anticipated capital expenditure thereby reducing any third party credit risk.
   
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. All of the Company's oil production is sold, depending on the field, to either BP Oil International Limited or Shell Trading International Ltd. Gas production is sold through contracts with RWE NPower PLC, Hess Energy Gas Power (UK) Ltd, Shell UK Ltd. and Esso Exploration & Production UK Ltd. Each of these parties has historically demonstrated their ability to pay amounts owing to Ithaca. The Company has not experienced any material credit loss in the collection of accounts receivable to date.
Property Risk   The Company's properties will be generally held in the form of licenses, 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 licenses, 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.   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 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.   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.
   
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.   The Company uses the services of Sproule International Limited ("Sproule") to independently assess the Company's reserves on an annual basis.
Competition Risk   In all areas of the Company's business, there is competition with entities that may have greater technical and financial resources.     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   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.   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 were to occur in respect of a property in which the Company has an interest, the Company's reputation could be severely harmed   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
This MD&A and any documents incorporated by reference herein contain certain forward-looking statements and forward-looking information which are based on the Company's internal expectations, estimates, projections, assumptions and beliefs as at the date of such statements or information, including, among other things, assumptions with respect to production, future capital expenditures, future acquisitions and cash flow.  The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect.  The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe", "could", "scheduled", "targeted", "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;
  • 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;
  • The continued availability of the Facilities;
  • The Company's acquisition strategy, the criteria to be considered in connection therewith and the benefits to be derived therefrom;
  • The realization of anticipated benefits from acquisitions and dispositions, including the acquisition of the Summit Assets;
  • 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 optimize 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; and
  • Timing and cost of the development of the Company's reserves.

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 is obtained within expected timeframes;
  • The Company's development plan for the Stella and Harrier discoveries will be implemented as planned;
  • The Company's ability to keep operating during periods of harsh weather;
  • Reserves volumes assigned to Ithaca's properties;
  • Ability to recover reserves volumes assigned to Ithaca's properties;
  • Revenues do not decrease below anticipated levels and operating costs do not increase significantly above anticipated levels;
  • Future oil, NGLs and natural gas production levels from Ithaca's properties and the prices obtained from the sales of such production;
  • The level of future capital expenditure required to exploit and develop reserves;
  • Ithaca's ability to obtain financing on acceptable terms, in particular, the 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;
  • 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 realisation of anticipated benefits of acquisitions, including the Summit acquisition;
  • 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 licenses;
  • Competition for, among other things, capital, drilling equipment, acquisitions of reserves, undeveloped lands and skilled personnel;
  • Changes in general economic, market and business conditions in Canada, North America, the United Kingdom, Europe and worldwide;
  • Actions by governmental or regulatory authorities including changes in income tax laws or changes in tax laws, royalty rates and incentive programs relating to the oil and gas industry including any increase in UK or Norwegian taxes;
  • Adverse regulatory rulings, orders and decisions; and
  • Risks associated with the nature of the common shares.
     
     
 Additional Reader Advisories   The information in this MD&A is provided as of August 11, 2014. The Q2 2014 results have been compared to the results of the comparative period in 2013. This MD&A should be read in conjunction with the Company's unaudited consolidated financial statements as at June 30, 2014 and 2013 and with the Company's audited consolidated financial statements as at December 31, 2013 together with the accompanying notes and Annual Information Form ("AIF") for the year ended December 31, 2013. Copies of these documents are available without charge from Ithaca or electronically on the internet on Ithaca's SEDAR profile at http://www.sedar.com/.
 
Estimates of the proved plus probable reserves associated with the acquisition of the Summit Assets as disclosed in this MD&A have been prepared by Ithaca's non-independent qualified reserves evaluator as of June 2014. The reserves estimates contained in this MD&A are estimates only and the actual results may be greater than or less than the estimates provided herein. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.
 
 
Consolidated Statement of Income
For the three and six months ended 30 June 2014 and 2013
(unaudited)
        Restated*   Restated*
        Three months ended 30 June   Six months ended 30 June
    Note   2014
US$'000
  2013
US$'000
  2014
US$'000
  2013
US$'000
                     
Revenue   5   99,931   128,360   199,571   188,129
Cost of sales   6   (87,980)   (108,303)   (173,989)   (154,761)
Gross Profit       11,951   20,057   25,582   33,368
                     
Exploration and evaluation expenses   12   (446)   (132)   (2,454)   (443)
Impairment of Assets       -   -   (2,895)   -
 Administrative expenses   7   (3,846)   (3,989)   (7,544)   (6,078)
 Non-recurring Valiant acquisition costs   7   -   (9,554)   -   (10,235)
Total administrative expenses       (3,846)   (13,543)   (7,544)   (16,313)
Operating Profit       7,659   6,382   12,689   16,612
                     
Foreign exchange       2,203   (2,637)   1,830   (2,074)
(Loss)/Gain on financial instruments   27   (11,203)   17,514   (7,241)   10,342
Gain on asset disposal       -   -   2,190   -
Negative goodwill       -   54,419   -   55,333
Profit/(Loss) Before Interest and Tax       (1,341)   75,677   9,468   80,212
                     
Finance costs   8   (5,747)   (5,001)   (12,021)   (7,277)
Interest income       17   21   42   42
Profit/(Loss) Before Tax       (7,071)   70,697   (2,511)   72,976
                     
Taxation   25   7,730   16,836   19,536   (15,674)
Profit/(Loss) After Tax       659   53,828   17,025   57,302
                     
Earnings per share                    
Basic   24   0.00   0.18   0.05   0.20
Diluted   24   0.00   0.17   0.05   0.20
                     

* Refer to Note 2, Basis of Preparation for further details on the nature of the restatement.

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 21 are an integral part of the financial statements.

Consolidated Statement of Financial Position        
(unaudited)            
    Note   30 June
2014
US$'000
  31 December 2013
US$'000
ASSETS            
             
Current assets            
Cash and cash equivalents       50,753   63,435
Restricted cash   9   12,610   12,198
Accounts receivable   10   397,115   314,727
Deposits, prepaid expenses and other       22,743   21,150
Inventory   11   25,498   21,632
Derivative financial instruments   28   5,063   5,102
        513,782   438,244
Non current assets            
Long-term receivable   31   52,328   31,655
Long-term inventory   11   8,126   8,126
Investment in associate       18,337   18,337
Exploration and evaluation assets   12   79,843   57,628
Property, plant & equipment   13   1,545,683   1,423,712
Goodwill       985   985
        1,705,302   1,540,443
             
Total assets       2,219,084   1,978,687
             
LIABILITIES AND EQUITY            
             
Current liabilities            
Trade and other payables   17   515,477   472,396
Exploration obligations   18   8,638   12,859
        524,115   485,255
Non current liabilities            
Borrowings   16   605,911   432,243
Decommissioning liabilities   19   176,609   172,047
Other long term liabilities   20   -   6,037
Deferred tax liability       8,466   9,909
Contingent consideration   21   4,000   4,000
Derivative financial instruments   28   18,467   15,550
        813,452   639,786
             
Net Assets       881,517   853,646
             
Equity attributable to owners of the parent        
Share capital   22   548,109   535,716
Share based payment reserve   23   17,707   19,254
Retained earnings       315,701   298,676
Shareholders' Equity       881,517   853,646
             
The financial statements were approved by the Board of Directors on 11 August 2014 and signed on its behalf by:
             
"Jay Zammit"            
Director            
             
"Les Thomas"            
Director            

The accompanying notes on pages 6 to 21 are an integral part of the financial statements.

Consolidated Statement of Changes in Equity            
(unaudited)                
    Share Capital   Share based
payment
reserve
  Retained Earnings   Total
    US$'000   US$'000   US$'000   US$'000
Balance, 1 Jan 2013   431,318   20,340   153,990   605,648
Shares issued   93,005   -   -   93,005
Share based payment   -   1,963   -   1,963
Options exercised   585   (257)   -   328
Net income for the period   -   -   57,302   57,302
Balance, 30 June 2013   524,908   22,046   211,292   758,246
                 
Balance, 1 Jan 2014   535,716   19,254   298,676   853,646
Share based payment   -   3,280   -   3,280
Options exercised   12,393   (4,827)   -   7,566
Net income for the period   -   -   17,025   17,025
Balance, 30 June 2014   548,109   17,707   315,701   881,517
                 

The accompanying notes on pages 6 to 21 are an integral part of the financial statements.

Consolidated Statement of Cash Flow                
For the three and six months ended 30 June 2014 and 2013                
(unaudited)   Restated*    Restated*   
    Three months ended 30 June    Six months ended 30 June   
    2014 US$'000   2013 US$'000   2014 US$'000   2013 US$'000
CASH PROVIDED BY (USED IN):                
Operating activities                
  Profit Before Tax   (7,071)   70,697   (2,511)   72,976
  Adjustments for:                
  Depletion, depreciation and amortisation   51,307   46,221   83,771   65,719
  Exploration and evaluation expenses   446   132   2,454   444
  Impairment   -   -   2,895   -
  Share based payment   337   366   766   661
  Loan fee amortisation   923   592   1,849   1,184
  Revaluation of financial instruments   7,381   (7,303)   4,703   3,762
  Movement in goodwill   -   (54,419)   -   (55,333)
  Gain on disposal   -   -   (2,190)   -
  Accretion   1,305   1,088   2,610   1,590
  Bank interest & charges   3,504   3,296   7,483   4,455
  Valiant acquisition fees   -   4,351   -   5,032
Cashflow from operations   58,132   65,022   101,830   100,492
  Changes in inventory, receivables and payables relating to operating activities   (13,255)   19,963   22,148   20,842
Net cash from operating activities   44,877   84,985   123,978   121,334
                 
Investing activities                
  Acquisition of Valiant   -   (200,636)   -   (200,636)
  Cash acquired on acquisition of Valiant   -   11,611   -   11,611
  Valiant acquisition fees   -   (4,351)   -   (5,032)
  Acquisition of Cook   -   -   -   (33,370)
  Capital expenditure   (106,020)   (66,050)   (234,725)   (91,434)
  Investment in associate   -   -   -   -
  Loan to associate   (20,763)   -   (20,854)   -
  Proceeds on disposal   -   -   2,190   -
  Changes in receivables and payables relating to investing activities   58,435   (56,880)   (59,971)   (44,441)
Net cash used in investing activities   (68,348)   (316,306)   (313,360)   (363,302)
                 
Financing activities                
  Proceeds from issuance of shares   517   299   7,567   328
  (Increase) / decrease in restricted cash   -   (3,226)   -   (3,226)
  Derivatives   -   (1,680)   (1,315)   (9,627)
  Loan repayment   -   (115,000)   -   (115,000)
  Loan draw down   35,914   320,918   171,865   375,918
  Bank interest & charges   (3,024)   (4,396)   (5,941)   (5,506)
Net cash from/used in financing activities   33,407   196,915   172,176   242,887
                 
Currency translation differences relating to cash   1,671   (4,137)   4,524   (5,202)
                 
Increase / (decrease) in cash and cash equiv.   11,607   38,543   (12,682)   (4,283)
                 
Cash and cash equivalents, beginning of period   39,146   65,634   63,435   31,374
                 
Cash and cash equivalents, end of period   50,753   27,091   50,753   27,091

* Refer to Note 2, Basis of Preparation for further details on the nature of the restatement.

The accompanying notes on pages 6 to 21 are an integral part of the financial statements.

1. NATURE OF OPERATIONS

Ithaca Energy Inc. (the "Corporation" or "Ithaca"), incorporated and domiciled in Alberta, Canada on 27 April 2004, is a publicly traded company involved in the exploration, development and production of oil and gas in the North Sea. The Corporation's registered office is 1600, 333 - 7th Avenue S.W., Calgary, Alberta, Canada, T2P 2Z1. The Corporation's shares trade on the Toronto Stock Exchange in Canada and the London Stock Exchange's Alternative Investment Market in the United Kingdom under the symbol "IAE".

2. BASIS OF PREPARATION

These interim consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) applicable to the preparation of interim financial statements, including IAS 34 Interim Financial Reporting. These interim consolidated financial statements do not include all the necessary annual disclosures in accordance with IFRS.

The policies applied in these condensed interim consolidated financial statements are based on IFRS issued and outstanding as of 11 August 2014, 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 2014 could result in restatement of these interim consolidated financial statements.

The financial statements for the period ended 30 June 2013 have been restated to reflect adjustments to the provisional fair values attributed to the business combination accounting for the acquisition of Valiant Petroleum PLC in 2Q 2013. Subsequent revisions disclosed within the 3Q 2013 and 31 December 2013 year end accounts are now reflected through 2Q 2013 ie the time of acquisition. Restatements have been reflected through negative goodwill, cost of sales and taxation.

The condensed interim consolidated financial statements should be read in conjunction with the Corporation's annual financial statements for the year ended 31 December 2013.

3. SIGNIFICANT ACCOUNTING POLICIES, JUDGEMENTS AND ESTIMATION UNCERTAINTY

Basis of measurement

The consolidated financial statements have been prepared under the historical cost convention, except for the revaluation of certain financial assets and financial liabilities (under IFRS) to fair value, including derivative instruments.

Basis of consolidation

The consolidated financial statements of the Corporation include the accounts of Ithaca Energy Inc. and all wholly-owned subsidiaries as listed per note 31. Ithaca has seventeen wholly-owned subsidiaries, thirteen of which were acquired on 19 April 2013 as part of the acquisition of Valiant Petroleum PLC ("Valiant"). The consolidated financial statements include the Valiant group of companies from 19 April 2013 only (being the acquisition date). All inter-company transactions and balances have been eliminated on consolidation.

A subsidiary is an entity which the Corporation controls by having the power to govern the financial and operating policies. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether Ithaca controls another entity. A subsidiary is fully consolidated from the date on which control is obtained by Ithaca and is de-consolidated from the date that control ceases.

Business Combinations

Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair value of the assets acquired, equity instruments issued and liabilities incurred or assumed at the date of completion of the acquisition. Acquisition costs incurred are expensed and included in administrative expenses. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the cost of acquisition over the fair value of the Corporation's share of the identifiable net assets acquired is recorded as goodwill. If the cost of the acquisition is less than the Corporation's share of the net assets required, the difference is recognised directly in the statement of income 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 22 (c). The expense is recorded in the statement of income or capitalised for all options granted in the year, with the gross increase recorded in the share based payment reserve. Compensation costs are based on the estimated fair values at the time of the grant and the expense or capitalised amount is recognised over the vesting period of the options. Upon the exercise of the stock options, consideration paid together with the amount previously recognised in share based payment reserve is recorded as an increase in share capital. In the event that vested options expire unexercised, previously recognised compensation expense associated with such stock options is not reversed. In the event that unvested options are forfeited or expired, previously recognised compensation expense associated with the unvested portion of such stock options is reversed.

Cash and Cash Equivalents

For the purpose of the statement of cash flow, cash and cash equivalents include investments with an original maturity of three months or less.

Restricted cash

Cash that is held for security for bank guarantees is reported in the balance sheet and cash flow statements separately. If the expected duration of the restriction is less than twelve months then it is shown in current assets.

Financial Instruments

All financial instruments, other than those designated as effective hedging instruments, are initially recognised at fair value in the statement of financial position. The Corporation's financial instruments consist of cash, restricted cash, accounts receivable, deposits, derivatives, accounts payable, accrued liabilities, contingent consideration and the long term liability on the Beatrice acquisition. The Corporation classifies its financial instruments into one of the following categories: held-for-trading financial assets and financial liabilities; held-to-maturity investments; loans and receivables; and other financial liabilities. All financial instruments are required to be measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.

Held-for-trading financial instruments are subsequently measured at fair value with changes in fair value recognised in net earnings. All other categories of financial instruments are measured at amortised cost using the effective interest method. Cash and cash equivalents are classified as held-for-trading and are measured at fair value. Accounts receivable are classified as loans and receivables. Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classified as other financial liabilities. Although the Corporation does not intend to trade its derivative financial instruments, they are classified as held-for-trading for accounting purposes.

Transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability and original issue discounts on long-term debt have been included in the carrying value of the related financial asset or liability and are amortised to consolidated net earnings over the life of the financial instrument using the effective interest method.

Analysis of the fair values of financial instruments and further details as to how they are measured are provided in notes 27 to 29.

Inventory

Inventories of materials and product inventory supplies, other than oil and gas inventories, are stated at the lower of cost and net realisable value. Cost is determined on the first-in, first-out method. Oil and gas inventories are stated at fair value less cost to sell. 

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.

Decommissioning liabilities

The Corporation records the present value of legal obligations associated with the retirement of long term tangible assets, such as producing well sites and processing plants, in the period in which they are incurred with a corresponding increase in the carrying amount of the related long term asset. The obligation generally arises when the asset is installed or the ground/environment is disturbed at the field location. In subsequent periods, the asset is adjusted for any changes in the estimated amount or timing of the settlement of the obligations. The carrying amounts of the associated assets are depleted using the unit of production method, in accordance with the depreciation policy for development and production assets. Actual costs to retire tangible assets are deducted from the liability as incurred.

Contingent consideration

Contingent consideration is accounted for as a financial liability and measured at fair value at the date of acquisition with any subsequent remeasurements recognised either in the statement of income or in other comprehensive income in accordance with IAS 39.

Taxation

Current income tax

Current income tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amounts are those that are enacted or substantively enacted by the reporting date.

Deferred income tax

Deferred tax is recognised for all deductible temporary differences and the carry-forward of unused tax losses. Deferred tax assets and liabilities are measured using enacted or substantively enacted income tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in rates is included in earnings in the period of the enactment date. Deferred tax assets are recorded in the consolidated financial statements if realisation is considered more likely than not.

Recent accounting pronouncements

New and amended standards and interpretations need to be adopted in the first interim financial statements issued after their effective date (or date of early adoption). There are no new IFRSs or IFRICs that are effective for the first time for this interim period that would be expected to have a material impact on the Corporation.

Significant accounting judgements and estimation uncertainties

The preparation of financial statements in conformity with IFRS requires management to make estimates and assumptions regarding certain assets, liabilities, revenues and expenses. Such estimates must often be made based on unsettled transactions and other events and a precise determination of many assets and liabilities is dependent upon future events. Actual results may differ from estimated amounts. 

The amounts recorded for depletion, depreciation of property and equipment, long-term liability, stock-based compensation, contingent consideration, decommissioning liabilities, derivatives and deferred taxes are based on estimates. The depreciation charge and any impairment tests are based on estimates of proved and probable reserves, production rates, prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be material. Further information on each of these estimates is included within the notes to the financial statements.

4. SEGMENTAL REPORTING

The Company operates a single class of business being oil and gas exploration, development and production and related activities in a single geographical area presently being the North Sea.

5. REVENUE

    Three months ended 30 June   Six months ended 30 June
    2014
US$'000
  2013
US$'000
  2014
US$'000
  2013
US$'000
Oil sales   97,231   125,064   193,833   181,217
Gas sales   1,463   2,452   3,519   5,224
Condensate sales   116   135   135   272
Other income   1,121   709   2,084   1,416
Total   99,931   128,360   199,571   188,129

6. COST OF SALES 

    Restated   Restated
    Three months ended 30 June   Six months ended 30 June
    2014
US$'000
  2013
US$'000
  2014
US$'000
  2013
US$'000
Operating costs   (51,896)   (43,155)   (93,159)   (66,382)
Oil purchases   (373)   (790)   (793)   (947)
Movement in oil and gas inventory   15,596   (18,137)   3,735   (21,713)
Depletion, depreciation and amortisation   (51,307)   (46,221)   (83,772)   (65,719)
    (87,980)   (108,303)   (173,989)   (154,761)

7. ADMINISTRATIVE EXPENSES

Three months ended 30 June   Six months ended 30 June
    2014
US$'000
  2013
US$'000
  2014
US$'000
  2013
US$'000
General & administrative   (3,507)   (3,623)   (6,778)   (5,415)
Non-recurring Valiant acquisition related costs   -   (9,554)   -   (10,235)
Share based payment   (339)   (366)   (766)   (663)
    (3,846)   (13,543)   (7,544)   (16,313)
                 

8. FINANCE COSTS

    Three months ended 30 June   Six months ended 30 June
    2014
US$'000
  2013
US$'000
  2014
US$'000
  2013
US$'000
Accretion   (1,315)   (1,088)   (2,620)   (1,590)
Bank charges   (3,161)   (3,297)   (7,140)   (4,460)
Non-operated asset finance fees   (38)   (24)   (101)   (42)
Prepayment interest   (310)   -   (310)   -
Loan fee amortisation   (923)   (592)   (1,850)   (1,185)
    (5,747)   (5,001)   (12,021)   (7,277)

9. RESTRICTED CASH

    30 June
2014
US$'000
  31 Dec
2013
US$'000
Security   12,610   12,198
    12,610   12,198

The above represents cash backed letters of credit for the Corporation's share of costs arising under Sullom Voe Terminal tariff agreements at 30 June 2014.

10. ACCOUNTS RECEIVABLE

    30 June
2014
US$'000
  31 Dec
2013
US$'000
Trade debtors   260,400   194,442
Norwegian tax receivable   79,051   61,397
Accrued income   57,664   58,888
    397,115   341,727

11. INVENTORY

    30 June
2014
US$'000
  31 Dec
2013
US$'000
Crude oil inventory - current   25,283   21,417
Crude oil inventory - non current   8,126   8,126
Materials inventory   215   215
    33,624   29,758

The non-current portion of inventory relates to long term stocks at the Sullom Voe Terminal

12. EXPLORATION AND EVALUATION ASSETS

    US$'000
     
At 1 January 2013   47,390
     
Additions   60,145
Write offs/relinquishments   (31,170)
Disposals   (18,737)
At 31 December 2013   57,628
     
Additions   28,890
Release of exploration obligations   (4,221)
Write offs/relinquishments   (2,454)
At 30 June 2014   79,843
     

Following completion of geotechnical evaluation activity, certain licences were declared unsuccessful and certain prospects were declared non-commercial and therefore the related expenditure of $2.4 million was expensed in the six months to 30 June 2014.

The above also includes the release of the exploration obligation provision against expenditure incurred (see note 18).

13. PROPERY, PLANT AND EQUIPMENT 

    Development & Production
Oil and Gas Assets
US$'000
 
Other fixed
assets
US$'000
  Total
US$'000
Cost            
             
At 1 January 2013   725,020   2,425   727,445
             
Acquisitions   685,333   -   685,533
Additions   332,796   738   333,534
Disposals   -   -   -
             
At 31 December 2013   1,743,349   3,163   1,746,512
             
Additions   208,209   429   208,638
             
At 30 June 2014   1,951,558   3,592   1,995,150
             
DD&A            
             
At 1 January 2013   (109,758)   (1,899)   (111,657)
             
DD&A charge for the period   (157,879)   (400)   (158,279)
             
Impairment charge for the period   (52,864)   -   (52,864)
             
At 31 December 2013   (320,501)   (2,299)   (322,800)
             
DD&A charge for the period   (83,571)   (201)   (83,772)
             
Impairment charge for the period   (2,895)   -   (2,895)
             
At 30 June 2014   (406,967)   (2,500)   (409,467)
             
NBV at 1 January 2013   615,262   526   615,788
NBV at 1 January 2014   1,422,848   864   1,423,712
             
NBV at 30 June 2014   1,544,591   1,092   1,545,683
             

The impairment charge above represents further costs of a capital nature recognized in the period on Beatrice and Jacky, both of which were fully written down at 31 December 2013 in anticipation of their handback to Talisman.

14. GOODWILL 

    US$'000
Cost    
At 31 December 2013, 31 March 2014 & 30 June 2014   985
     

$1.0 million represents goodwill recognised on the acquisition of gas assets from GDF in December 2010. As at 30 June 2014, the recoverable amount of assets acquired from GDF was sufficiently high to support the carrying value of this goodwill.

15. INVESTMENT IN ASSOCIATES

    30 June
2014
US$'000
  31 Dec
2013
US$'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.

16. BORROWINGS

On 29 June 2012, the Corporation executed a Senior Secured Borrowing Base Facility agreement (the "Facility") for up to $430 million, being provided by BNP Paribas as Lead Arranger. The loan term is up to five years and attracts interest at LIBOR plus 3-4.5%.

The Corporation also executed a $350 million bridge loan (the "Bridge Facility") in April 2013 with BNP Paribas, the Bank of Nova Scotia and Bank of America Merrill Lynch. The Bridge Facility was available for 12 months and attracted interest of between LIBOR plus 1.0 - 2.25%.

In October 2013, the Corporation increased its existing RBL (Reserve Based Lending) Facility to $610 million with enhanced terms including reduced margin costs (LIBOR plus 2.75%-3%) and greater flexibility over future unallocated capital with a loan term until June 2017. Simultaneously, this enabled retirement of the aforementioned $350 million Bridge Facility.

The Corporation also established a new five year $100 million corporate facility in October 2013 with a term of up to 5 years which attracts interest at LIBOR plus 4.15%.

On 1 July 2013, the Corporation signed a NOK 450 million (approximately $75 million) Norwegian Exploration Financing Facility (the "Norwegian Facility") with a loan term of 1 year. Under the Norwegian tax regime, 78% of exploration, appraisal and supporting expenditure resulting from operations on the Norwegian Continental Shelf is refunded by the Government in the December of the year following the year the costs were incurred. This is a conventional tax refund facility on industry standard terms.

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.

Security provided against the facilities

Security provided against the Facility is in the form of a floating charge over all assets of the Ithaca group.

As at 30 June 2014, $551 million (31 December 2013: $410 million) was drawn down under the RBL Facility and approximately $66million (31 December 2013, $34million) was drawn under the Norwegian Facility. $10 million (31 December 2013: $12 million) of loan fees have been capitalised. 

The Corporation is in compliance with its financial and operating covenants. 

17. TRADE AND OTHER PAYABLES

    30 June
2014
US$'000
  31 Dec
2013
US$'000
Trade payables   267,160   173,052
Accruals and deferred income   248,317   299,344
    515,477   472,396

18. EXPLORATION OBLIGATIONS

    30 June
2014
US$'000
  31 Dec
2013
US$'000
Exploration obligations   8,638   12,859

The above reflects the fair value of E&E commitments assumed as part of the Valiant transaction. During the period to 30 June 2014, $4.2 million was released reflecting expenditure incurred in the period.

19. DECOMMISSIONING LIABILITIES

    30 June
2014
US$'000
  31 Dec
2013
US$'000
Balance, beginning of period   172,047   52,834
Additions   1,943   105,229
Accretion   2,619   4,509
Revision to estimates   -   9,475
Utilisation   -   -
Balance, end of period   176,609   172,047

The total future decommissioning liability was calculated by management based on its net ownership interest in all wells and facilities, estimated costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. The Corporation uses a risk free rate of 3.0 percent (31 December 2013: 3.0 percent) and an inflation rate of 2.0 percent (31 December 2013: 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 13 years.

The economic life and the timing of the obligations are dependent on Government legislation, commodity price and the future production profiles of the respective production and development facilities. Note that upon the acquisition of the Beatrice Field in November 2008, the Corporation did not assume the decommissioning liabilities.

20. OTHER LONG TERM LIABILITIES

    30 June
2014
US$'000
  31 Dec
2013
US$'000
Balance, beginning of period   6,037   3,018
Revaluation in the periodReclassed to trade payables   (370)
(6,407)
  3,019
-
Balance, end of period   -   6,037

The above balance relates to volumes of oil at the Nigg terminal which must be settled on re-transfer to Talisman, expected to take place in early 2015. This has been transferred to current liabilities in the quarter and is now included within trade and other payables (note 17).

21. CONTINGENT CONSIDERATION

    30 June
2014
US$'000
  31 Dec
2013
US$'000
Balance 31 December 2013, 31 March 2014 & 30th June 2014   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.

22. SHARE CAPITAL


Authorised share capital
  No. of common shares   Amount
US$'000
At 31 December 2013 and 30 June 2014   Unlimited   -
         
(a) Issued        
         
The issued share capital is as follows:        
Issued   Number of common shares   Amount
US$'000
Balance 1 January 2013   259,920,003   431,318
Share issueIssued for cash - options exercised   56,952,231
6,761,296
  93,005
6,574
Transfer from Share based payment reserve on options exercised   -   4,819
Balance 1 January 2014   323,633,620   535,716
Issued for cash - options exercised   4,765,000   7,566
Transfer from Share based payment reserve on options exercised (Note 23)   -   4,827
Balance 30 June 2014   328,398,620   548,109

(b) Stock options

In the quarter ended 30 June 2014, the Corporation's Board of Directors did not grant any new options.

In the quarter ended 31 March 2014, the Corporation's Board of Directors granted 7,165,000 options at a weighted average exercise price of $2.47 (C$2.71).

The Corporation's stock options and exercise prices are denominated in Canadian Dollars when granted. As at 30 June 2014, 16,993,567 stock options to purchase common shares were outstanding, having an exercise price range of $1.76 to $2.47 (C$1.80 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 2014   31 December 2013
   

No. of Options
  Wt. Avg
Exercise Price*
  No. of Options   Wt. Avg
Exercise Price*
Balance, beginning of period   14,593,567   $2.01   20,347,964   $1.63
Granted   7,165,000   $2.47   1,820,232   $2.43
Forfeited / expired   -   -   (813.333)   $2.18
Exercised   (4,765,000)   $1.74   (6,761,296)   $0.95
Options   16,993,567   $2.28   14,593,567   $2.01

* 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 2014

Options Outstanding   Options Exercisable
Range of
Exercise Price
No. of
Options
  Wt.
Avg
Life
(Years)
  Wt.
Avg
Exercise
Price*
  Range of
Exercise Price
 

No.
of
Options
  Wt.
Avg
Life
(Years)
  Wt.
Avg
Exercise
Price*
                           
$2.22-$2.47 (C$2.01-C$2.71) 12,335,232   2.7   $2.40   $2.22-$2.47 (C$2.01-C$2.71)   3,303,667   0.6   $2.23
$1.76-$2.03 (C$1.80-C$1.99) 4,658,335   2.1   $2.01   $1.76-$2.03 (C$1.80-C$1.99)   1,614,999   1.9   $1.98
  16,993,567   2.5   $2.28       4,918,666   1.0   $2.14

The following is a summary of stock options as at 31 December 2013.

Options Outstanding   Options Exercisable
Range of
Exercise Price
No. of
Options
  Wt.
Avg
Life
(Years)
  Wt.
Avg
Exercise
Price*
  Range
of
Exercise
Price
 

 No.
of
Options
  Wt.
Avg
Life
(Years)
  Wt.
Avg
Exercise
Price*
                           
 $2.22-$2.46 (C$2.25-C$2.53) 6,670,232   1.8   $2.29   $2.22-$2.46 (C$2.25-C$2.53)   4,673,333   1.0   $2.22
 $1.49-$2.03 (C$1.54-C$1.99) 7,451,667   2.1   $1.90   $1.49-$2.03 (C$1.54-C$1.99)   3,844,998   1.4   $1.77
 $0.20 (C$0.25) 471,668   0.1   $0.17   $0.20 (C$0.25)   471,668   0.1   $0.20
  14,593,567   1.9   $2.01       8,989,999   1.1   $1.95
                           

(c) Share based payments

Options granted are accounted for using the fair value method. The compensation cost during the three months and six months ended 30 June 2014 for total stock options granted was $1.6 million and $3.3 million respectively (Q2 2013: $0.9 million, Q2 YTD: $1.9 million). $0.3 million and $0.8 million were charged through the statement of income for share based payment for the three and six months ended 30 June 2014 respectively, being the Corporation's share of share based payment chargeable through the statement of income. The remainder of the Corporation's share of share based payment has been capitalised. The fair value of each stock option granted was estimated at the date of grant, using the Black-Scholes option pricing model with the following assumptions:

    For the six months ended 30 June 2014   For the year ended 31 December 2013
Risk free interest rate   1.27%   1.37%
Expected stock volatility   56%   51%
Expected life of options   3 years   2 years
Weighted Average Fair Value   $1.08   $0.82

23. SHARE BASED PAYMENT RESERVE

    30 June
2014
US$'000
  31 Dec
2013
US$'000
Balance, beginning of period   19.254   20,340
Share based payment cost   3,280   3,733
Transfer to share capital on exercise of options (Note 22)   (4,827)   (4,819)
Balance, end of period   17,707   19,254

24. EARNINGS PER SHARE

The calculation of basic earnings per share is based on the profit after tax and the weighted average number of common shares in issue during the period. The calculation of diluted earnings per share is based on the profit after tax and the weighted average number of potential common shares in issue during the period.

    Three months ended 30 June   Six months ended 30 June
    2014   2013   2014   2013
Wtd av. number of common shares (basic)   322,610,229   305,912,433   327,279,311   283,055,608
Wtd av. number of common shares (diluted)   329,445,220   309,278,839   330,171,186   287,225,134

25. TAXATION

    Three months ended 30 June   Six months ended 30 June
    2014
US$'000
  2013
US$'000
  2014
US$'000
  2013
US$'000
Taxation   7,730   16,836   19,536   (15,674)
                 

26. COMMITMENTS

Operating lease commitments   30 June
2014
US$'000
  31 Dec
2013
US$'000
         
Within one year   12,478   13,262
Two to five years   14,556   8,149
         
Capital commitments   30 June
2014
US$'000
  31 Dec
2013
US$'000
Capital commitments incurred jointly with other ventures (Ithaca's share)   99,383   111,747
         
         

27. 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 2014:

    Level 1
US$'000
  Level 2
US$'000
  Level 3
US$'000
  Total Fair Value
US$'000
Derivative financial instrument asset   -   5,063   -   5,063
Long term liability on Beatrice acquisition   -   -   (6,407)   (6,407)
Contingent consideration   -   (4,000)   -   (4,000)
Derivative financial instrument liability   -   (18,467)   -   (18,467)

The table below presents the total (loss)/gain on financial instruments that has been disclosed through the statement of comprehensive income:

    Three months ended 30 June   Six months ended 30 June
    2014
US$'000
  2013
US$'000
  2014
US$'000
  2013
US$'000
Revaluation of forex forward contracts   -   584   (4,171)   (1,471)
Revaluation of other long term liability   (393)   96   (370)   153
Revaluation of commodity hedges   (6,877)   6,623   72   (2,444)
Revaluation of interest rate swaps   (111)   -   (234)   -
    (7,381)   7,303   (4,703)   (3,762)
                 
Realised (loss)/gain on commodity hedges   (3,667)   9,374   (6,341)   13,560
Realised gain/(loss) on forex contracts   -   837   4,028   544
Realised (loss)/gain on interest rate swaps   (155)   -   (225)   -
    (3,822)   10,211   (2,538)   14,104
Total (loss)/gain on financial instruments   (11,203)   17,514   (7,241)   10,342

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 comprehensive income:

Three months ended 30 June
    2014
US$'000
  2013
US$'000
Revaluation of commodity hedges   (6,877)   6,623
Realised (loss)/gain on commodity hedges   (3,667)   9,374
Total (loss)/gain on commodity hedges   (10,544)   15,997

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:

Derivative   Term   Volume   Average price
Oil puts   July 14 - Jun 16   920,647 bbls   $101/bbl
Oil swaps   July 14 - Jun 16   2,358,586 bbls   $102/bbl
Gas swaps   July 14 - Dec 14   809,600 therms   67p/therm
Gas puts   Oct 15 - Jun 17   187,300,000 therms   63p/therm

ii) Interest Risk

Calculation of interest payments for the Senior Secured Borrowing Base Facility agreement with BNP Paribas that was signed on 29 June 2012 incorporates LIBOR. The Corporation will therefore be exposed to interest rate risk to the extent that LIBOR may fluctuate. The Corporation will evaluate its annual forward cash flow requirements on a rolling monthly basis.

Derivative   Term   Value    Rate
Interest rate swap   Aug 14-Dec 15   $200 million   0.44%

iii) Foreign Exchange Rate Risk

The table below presents the total gain on foreign exchange financial instruments that has been disclosed through the statement of comprehensive income:

Three months ended 30 June
    2014
US$'000
  2013
US$'000
Revaluation of foreign exchange forward contracts   -   584
Realised gain on foreign exchange forward contracts   -   837
Total gain/(loss) on forex forward contracts   -   1,421

The Corporation is exposed to foreign exchange risks to the extent it transacts in various currencies, while measuring and reporting its results in US Dollars. Since time passes between the recording of a receivable or payable transaction and its collection or payment, the Corporation is exposed to gains or losses on non USD amounts and on balance sheet translation of monetary accounts denominated in non USD amounts upon spot rate fluctuations from quarter to quarter. The Corporation evaluates its foreign exchange instrument requirements on a rolling monthly basis.

iv) Credit Risk

The Corporation's accounts receivable with customers in the oil and gas industry are subject to normal industry credit risks and are unsecured. All of its oil production from the Beatrice, Jacky and Athena field is sold to BP Oil International Limited. Oil production from Cook, Broom, Dons, Causeway and Fionn is sold to Shell Trading International Limited. Anglia and Topaz gas production is currently sold through three contracts to RWE NPower PLC and Hess Energy Gas Power (UK) Limited. Cook gas is sold to Shell UK Ltd and Esso Exploration & Production UK Limited.

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 2014 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 2014 (31 December 2013: $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 2014, exposure is $5.1 million (31 December 2013: $5.1 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 2014, substantially all accounts payable are current.

The following table shows the timing of cash outflows relating to trade and other payables.

    Within 1 year
US$'000
  1 to 5 years
US$'000
Accounts payable and accrued liabilities   515,477   -
Borrowings   -   605,911
    515,477   605,911

28. DERIVATIVE FINANCIAL INSTRUMENTS

    30 June
2014
US$'000
  31 December
2013
US$'000
Oil swaps   (15,523)   (15,349)
Oil puts   (2,477)   597
Gas swaps   3,106   -
Gas puts   1,594   -
Interest rate swaps   (104)   -
Foreign exchange forward contract   -   4,304
    (13,404)   (10,448)

29. FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES

Financial instruments of the Corporation consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in these financial statements. At 30 June 2014, the classification of financial instruments and the carrying amounts reported on the balance sheet and their estimated fair values are as follows:

  30 June 2014
US$'000
  31 December 2013
US$'000
Classification Carrying Amount   Fair Value   Carrying Amount   Fair Value
Cash and cash equivalents (Held for trading) 50,753   50,753   63,435   63,435
Restricted cash 12,610   12,610   12,198   12,198
Derivative financial instruments (Held for trading) 5,063   5,063   5,102   5,102
Accounts receivable (Loans and Receivables) 398,070   398,070   314,727   314,727
Deposits 22,743   22,743   21,150   21,150
Long-term receivable (Loans and Receivables) 52,328   52,328   31,655   31,655
               
Borrowings (Loans and Receivables) (605,911)   (605,911)   (432,243)   (432,243)
Contingent consideration (4,000)   (4,000)   (4,000)   (4,000)
Derivative financial instruments (Held for trading) (18,467)   (18,467)   (15,550)   (15,550)
Other long term liabilities -   -   (6,037)   (6,037)
Accounts payable (Other financial liabilities) (515,477)   (515,477)   (472,396)   (472,396)

30. CONTINGENT LIABILITY

The costs from the Sullom Voe Terminal ("SVT"), which receives oil from the Dons and Causeway areas, are billed monthly on forecast allocations and a reconciliation invoice is received in the second quarter of the following year based on actual allocations. The monthly SVT billings for 2013 have all been expensed and paid.

In June and July 2014, Ithaca received inconsistent notifications regarding the reconciliation charge in respect of 2013. As a result Ithaca has not been able to verify the underlying input data and calculations. The matter is being investigated with the SVT operator and additional, relevant information is being requested. Accordingly, management has not yet been able to determine the final amount that will be payable. It is possible that the reconciliation charge could be up to $12 million ($5 million post tax), which has not been recorded because of the uncertainty over the matter. The final amount of the 2013 reconciliation invoice is expected to be recognised in the Q3 2014 interim financial statements.

Agreements are in place to simplify the method of allocation of SVT costs after 2014 and to base the allocation predominately on oil throughputs making forecasting more straightforward and reducing the potential significant cost allocation distortions inherent in the current allocation process.

31. 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
        2014   2013
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 Ltd   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%

Transactions between subsidiaries are eliminated on consolidation.

The following table provides the total amount of transactions that have been entered into with related parties during the six month period ending 30 June 2014 and 30 June 2013, as well as balances with related parties as of 30 June 2014 and 31 December 2013:

        Sales   Purchases   Accounts receivable   Accounts payable
        US$'000   US$'000   US$'000   US$'000
Burstall Winger LLP   2014   -   84   -   -
    2013   -   515   -   -
     
     
Loans to related parties   Amounts owed from related parties
    30 June   31 Dec
    2014   2013
    US$'000   US$'000
FPF-1 Limited   52,328   31,655

32. SEASONALITY

The effect of seasonality on the Corporation's financial results for any individual quarter is not material.

33. SUBSEQUENT EVENTS

Acquisition of Summit Petroleum Limited    

In June 2014, the Boards of Ithaca and Sumitomo Corporation, announced that they had reached agreement on the terms of a recommended acquisition (the "Acquisition"). The Acquisition became effective on 1 January 2014 with Ithaca Energy Holdings (UK) Limited acquiring the entire issued and to be issued share capital of Summit. Completion anticipated in Q3-2014.

The total net acquisition price was approximately $163 million.

It is expected that the transaction will be accounted for in accordance with IFRS 3 - Business Combinations. Given the proximity of the Acquisition to the quarter end, no provisional fair values have yet been determined.

Senior Notes Offering

In July 2014, Ithaca completed its offering of $300 million 8.125% senior unsecured notes due at 2019 at par.

The Notes, the net proceeds of which will be used to partially repay (without cancelling) the Company's senior secured reserves based lending ("RBL") facility, will be senior obligations of the Company and will rank pari passu with all present and future senior unsecured indebtedness of the Company.

The Company intends to draw amounts under the RBL facility to finance the acquisition of Summit Petroleum Limited.

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