SOURCE: Ithaca Energy Inc

May 13, 2014 02:00 ET

Ithaca Energy Inc. First Quarter 2014 Financial Results

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

CALGARY, AB--(Marketwired - May 13, 2014) - Ithaca Energy Inc. (TSX: IAE) (LSE: IAE) ("Ithaca" or the "Company") announces its financial results for the three months ended March 31 2014.

Financial Results

  • Cashflow from operations of $43.7 million (Q1 2013: $34.8 million), resulting in cashflow per share of $0.13 (Q1 2013: $0.13)
  • Profit after tax increased by approximately 370% in Q1 2014 to $16.4 million (Q1 2013: $3.5 million), equating to earnings per share of $0.05 (Q1 2013: $0.01)
  • Q1-2014 average realised oil price of $108/bbl (Q1 2013: $106/bbl)
  • Net drawn debt of $478.2 million at 31 March 2014 (December 31, 2013: $348.5 million), excluding the Company's Norwegian tax rebate facility. Additionally, $45 million was advanced under the $70 million Shell oil sales agreement
  • UK tax allowances pool of $1,174 million at 31 March 2014. Norwegian tax receivable of $77.8 million
  • Approximately 3.0 million barrels of oil production hedged over the next 2 years at a weighted average price of around $100/bbl (approximately 70% swaps / 30% puts)
  • Secured floor price of £0.58/therm (~$10/MMbtu) for approximately 200 million therms (20 billion cubic feet) of gas sales over gas years 2015 and 2016

Production & Operations
Average production in Q1-2014 was 9,222 barrels of oil equivalent per day ("boepd"), 95% oil, in line with forecast performance given shutdowns on the Cook and Beatrice fields during the quarter. Average production in April 2014 was approximately 11,200 boepd stepping up to more than 14,000 boepd to date in May.

The increasing production trend is being driven by execution of the 2014 production enhancement programme, which is progressing well. The Fionn sidetrack has recently been completed and production from the field has recommenced. The host platform works required to enable the start-up of electrical submersible pumps ("ESPs") on the Causeway and Fionn fields are substantially complete. Drilling of the planned infill well on the Don Southwest field commenced in late April 2014, with the well expected to be brought online in the third quarter of the year.

Total 2014 production guidance remains unchanged in the range of 11,000 to 13,000 boepd, approximately 95% oil. The anticipated schedule of 2014 production enhancement projects means that volumes are forecast to be weighted towards the second half of the year.

The Company was awarded the "Don NE" licence (40%, non-operated) that lies adjacent to its existing Dons field position by the Department of Energy and Climate Change during the quarter. Submission of a "Phase I" Field Development Plan is planned for later this year to enable an early production well to be drilled on the licence from the existing Don Southwest facilities potentially as early as the end of 2014.

Greater Stella Area Development Update
As previously announced on 9 May 2014, Petrofac is forecasting that the FPF-1 floating production facility will 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. Ithaca is working with Petrofac to expedite the remaining construction and commissioning works on the FPF-1.

Graham Forbes, Chief Financial Officer, commented:
"Earnings of $16 million represent satisfactory financial results for the first quarter, with the Company on-track to deliver the anticipated step-up in operating cashflows over the coming months as the various 2014 production enhancement projects are completed."

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 March 31, 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 FIRST QUARTER 2014
Strong quarterly results taking into account anticipated production levels 

  • Q1 2014 cashflow from operations increased approximately 26% to $43.7 million (Q1 2013: $34.8 million) - cashflow per share $0.13 (Q1 2013: $0.13)
  • Q1 2014 profit after tax increased approximately 370% to $16.4 million (Q1 2013: $3.5 million) - earnings per share $0.05 (Q1 2013: $0.01)
  • Q1 2014 average realised oil price of $108/bbl (Q1 2013: $106/bbl)
  • Net drawn debt of $478.2 million at March 31, 2014 (December 31, 2013: $348.5 million), excluding the Norwegian tax rebate facility. Additionally, $45 million was advanced under the $70 million Shell oil sales agreement
  • UK tax allowances pool of $1,174 million at March 31, 2014. Norwegian tax receivable of $77.8 million
  • Approximately 3.0 million barrels of oil production hedged over the next 2 years at a weighted average price of around $100/bbl (approximately 70% swaps / 30% puts)
  • Secured floor price of £0.58/therm (~$10/MMbtu) for approximately 200 million therms (20 billion cubic feet) of gas sales over gas years 2015 and 2016

Operations on-track to achieve 2014 production guidance of 11-13kboe/d 

  • Average production in Q1-2014 was 9,222 barrels of oil equivalent per day ("boepd"), 95% oil, in line with forecast performance given shutdowns on the Cook and Beatrice fields during the quarter.
  • The core activities on the 2014 production enhancement programme are progressing well. The Fionn sidetrack has recently been completed and production from the field has recommenced. The host platform works required to enable the start-up of electrical submersible pumps ("ESPs") on the Causeway and Fionn fields are substantially complete. Drilling of the planned infill well on the Don Southwest field commenced in late April.
  • Total 2014 production guidance remains unchanged in the range of 11,000 to 13,000 boepd, approximately 95% oil. The anticipated schedule of 2014 production enhancement activities means that volumes are forecast to be weighted towards the second half of the year.

Continued progress on the GSA development 

  • Continued progress has been made on the Greater Stella Area ("GSA") development since the start of 2014. Strong flow test results were achieved on the second Stella development well and drilling is on-going on the third well, with the clean-up flow test results for the well expected around late June 2014. The first of the 2014 subsea infrastructure installation campaigns was also completed in April, involving tie-in of the first two development wells at the Stella Main Drill Centre.
  • Progress has also been made on the "FPF-1" floating production facility modification works being completed by Petrofac Facilities Management Limited ("Petrofac"), however the overall topsides construction programme has advanced more slowly than planned. As previously announced, Petrofac is forecasting the vessel to 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 Stella field in mid-2015.

Don NE licence award - securing Dons Area upside 

  • The Company was awarded the "Don NE" licence (40%, non-operated) that lies adjacent to its existing Dons field position by the Department of Energy and Climate Change ("DECC"). Submission of a "Phase I" Field Development Plan ("FDP") is planned for later this year to enable an early production well to be drilled on the licence from the existing Don Southwest facilities.
  • Restructuring of the former Valiant Norwegian portfolio has largely been completed with the Company exiting the Barents Sea via a licence swap with Tullow Norge AS. Following execution of a farm-in agreement with TOTAL E&P Norge AS, an oil discovery close to existing infrastructure being was made on the "Trell" prospect in the Norwegian North Sea.
 
SUMMARY STATEMENT OF INCOME
 
        Q1 2014   Q1 2013   %
Average Brent Oil Price   $/bbl   108   113   -4%
Average Realised Oil Price(1)   $/bbl   108   106   2%
Revenue   M$   99.6   59.8   67%
Cost of Sales - excluding DD&A   M$   (53.5)   (27.0)   98%
G&A etc   M$   (3.7)   (1.9)   95%
Realised Derivatives Gain / (Loss)   M$   1.3   3.9   -67%
Cashflow From Operations   M$   43.7   34.8   26%
DD&A   M$   (32.5)   (19.5)   67%
Unrealised Derivatives Gain/(Loss)   M$   2.7   (11.1)   -124%
Other Non-Cash Costs   M$   (9.3)   (1.9)   389%
Profit Before Tax   M$   4.6   2.3   100%
Deferred Tax Credit / (Charge)   M$   11.8   1.2   883%
Profit After Tax   M$   16.4   3.5   369%
Earnings Per Share   $/Sh.   0.05   0.01   400%
Cashflow Per Share   $/Sh.   0.13   0.13   -
(1) Average realized price before hedging

 

 
SUMMARY BALANCE SHEET
 
M$   Q1 2014   Q4 2013
Cash & Equivalents   39   63
Other Current Assets   387   375
PP&E   1,573   1,481
Other Non-Current Assets   59   59
Total Assets   2,058   1,979
Current Liabilities   (412)   (485)
Bank Debt   (569)   (432)
Asset Retirement Obligations   (175)   (172)
Deferred Tax Liabilities   (15)   (10)
Other Non-Current Liabilities   (9)   (26)
Total Liabilities   (1,180)   (1,125)
         
Net Assets   878   854
Share Capital   547   536
Other Reserves   16   19
Surplus / (Deficit)   315   299
Shareholders' Equity   868   854
 

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.

PRODUCTION & OPERATIONS UPDATE

Operations remain on-track to achieve 2014 production guidance of 11-13kboe/d

PRODUCTION
Average production in Q1-2014 was 9,222 barrels of oil equivalent per day ("boepd"), 95% oil. This represents a 50% increase on the same quarter in 2013 (Q1-2013: 6,148 boepd ), driven by the additional assets resulting from the Valiant Petroleum plc ("Valiant") acquisition (transaction completed on April 19, 2013).

Production during the quarter was in line with forecast performance given the previously announced unplanned Cook field shutdown in January / February and a planned shutdown of the Beatrice Area facilities to complete certain inspection and maintenance works.

Total 2014 production guidance remains unchanged in the range of 11,000 to 13,000 boepd, approximately 95% oil. The anticipated schedule of 2014 production enhancement activities means that volumes are forecast to be weighted towards the second half of the year.

The core activities in the 2014 production enhancement programme are progressing well.

  • The Fionn sidetrack has recently been completed and production from the field recommenced in early May. The initial performance of the well is in line with expectations.
  • The Taqa-operated host platform works required to enable the start-up of electrical submersible pumps ("ESPs") on the Causeway and Fionn fields are substantially complete. The modifications also being undertaken to enable start-up of water injection on the Causeway field are advancing and scheduled to be finished around mid-year.
  • Drilling of the planned infill well on the Don Southwest field commenced in late April and initial production from the well is forecast for the third quarter.
  • The Athena co-venturers have awarded a contract to Diamond Offshore Drilling (UK) Limited for use of the Ocean Princess semi-submersible rig for the planned "P4" workover to replace the ESP package in the well. The rig is anticipated on location in the third quarter of the year, once it has completed its scheduled work programmes for prior clients.

GREATER STELLA AREA DEVELOPMENT UPDATE
Continued progress has been made on execution of the three core GSA development work programmes since the start of 2014.

FPF-1 construction activities progressing - main pre-assembled unit heavy lifts completed

FPF-1 MODIFICATION WORKS
The key focus of the remaining FPF-1 modification works being completed by Petrofac is on the construction and commissioning of the processing plant that is being installed on the vessel, along with the refurbishment and fit out of the existing accommodation module. 

Construction activities on the main deck of the FPF-1 have been advancing and are currently centred on fit-out of the main pre-assembled units that were lifted on to the vessel in the first quarter of the year along with preparation for the installation of additional equipment packages. A number of key pieces of equipment have recently been installed on the main deck, including the three gas turbine generators. In addition, installation of the four additional buoyancy blisters being added to the columns of the FPF-1 is at an advanced stage of completion.

As previously highlighted, completion of the FPF-1 modifications programme is the key development activity dictating the overall schedule for first hydrocarbons from the GSA hub. While progress has been made on the modifications programme over recent months, the topsides construction programme has advanced more slowly than planned. As a consequence, Petrofac is forecasting for the vessel to 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.

Ithaca is working with Petrofac to expedite the remaining construction and commissioning works on the FPF-1.

Drilling operations on-going on the third Stella development well 

DRILLING PROGRAMME
The second Stella development well, "A2", was completed in January 2014. The reservoir quality encountered by the well was in line with previous appraisal wells drilled on the field and the horizontal reservoir section of the well intersected a net reservoir interval of 2,514 feet (81% net pay). The well flowed at a maximum rate of 10,442 boepd (70% oil) on a 44/64-inch choke, with the full production potential of the well limited by the capacity of the well test equipment on the drilling rig. When combined with the corresponding results for the "A1" development well, this substantially de-risks the initial production forecast for the field.

In March 2014 the Ensco 100 jack-up drilling rig was moved from the Main Drill Centre location, from where the first two Stella development wells were drilled, to the Northern Drill Centre from where the third and fourth wells will be drilled. Drilling operations on the third well, "B1", commenced in March 2014 and are scheduled to be completed around late June.

Initial 2014 subsea campaign completed in April - well tie-ins at the Main Drill Centre  

SUBSEA INFRASTRUCTURE WORKS
The key outstanding workscopes to be completed during 2014 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 Point Loading ("SPL") oil export facilities and the dynamic flexible risers and umbilicals that will connect the riser bases to the FPF-1.

The 2014 programme is to be completed over several offshore campaigns, culminating in the hook-up of the FPF-1 and risers upon the arrival of the vessel on location. The first campaign was completed in April 2014, with the first two development wells tied in to the Main Drill Centre. The next scheduled activity is installation of the FPF-1 mooring piles in June 2014.

CORPORATE ACTIVITIES

Don NE licence award - Phase I FDP submission planned for 2014

DON NE LICENCE AWARD
Ithaca (40% working interest) and EnQuest (60%, Operator) were awarded a licence by the DECC in March 2014 covering the majority of the former Don NE field acreage that lies adjacent to the producing Don Southwest field in which both companies have corresponding working interest levels.

The Don NE field was previously operated by BP and ceased production in 2005. BP and its co-venturers are currently in the process of decommissioning the wells in the northern part of the Don NE licence and as such, DECC has at this time awarded a new licence over the southern area of the field.

Submission of a Phase I FDP is planned for later in 2014 to enable a production well to be drilled on the southern part of the field from the existing Don Southwest facilities, potentially as early as this year. The envisaged drilling location is in an area of the field where a previous appraisal well was drilled and tested in 1982. Depending on the production performance of the well, the drilling of further production and water injections wells in this part of the field would represent a potential Phase II development plan.

Given the ability of the co-venturers to produce wells on the Don NE field via the existing Don Southwest field infrastructure, this represents crystallisation of a valuable upside that has stemmed from the acquisition of the Valiant assets. Moreover, any development activity is expected to benefit from application of the Small Field Allowance, which shelters field revenues of up to approximately $240 million (100%) from payment of the 32% Supplementary Tax charge.

28th UK OFFSHORE LICENSING ROUND
Several licence applications were made as part of the 28th UK Offshore Licensing Round in April 2014. It is anticipated that the DECC will announce the results of the Round in late 2014.

PORTFOLIO MANAGEMENT & DRILLING
Restructuring of former Valiant Norwegian portfolio largely completed

The following previously reported licence management and drilling activities were completed in Q1-2014.

  • Restructuring of the former Valiant Norwegian portfolio was largely completed in January 2014 with the Company exiting the Barents Sea by swapping its position in the "Langlitinden" well for a licence interest in the Norwegian North Sea with Tullow Norge AS, on which a well is scheduled to be drilled on the "Lupus" prospect in mid-2014. As part of the portfolio restructuring, the Norvarg licence in the Barents Sea is also to be relinquished. Despite the considerable extent of the discovery and presence of mobile gas in the Kobe formation, the reservoir properties and lack of infrastructure in the area means that Norvarg is considered non-commercial at this time.
  • Ithaca and Dyas UK Limited ("Dyas") entered into an agreement with North Sea Energy Limited ("NSE") to remove NSE from the Jacky joint venture in March 2014. As a result, Ithaca increased its interest in the Jacky field from 47.5% to 52.5% and is putting in place a cost sharing agreement with Dyas to share all costs 50/50 (excluding decommissioning and related costs).
  • As previously noted, it is anticipated that 2014 will be the last year of production from the Beatrice and Jacky fields. Under the terms of the Beatrice facilities lease agreement executed with Talisman in 2008, Ithaca is able to re-transfer the facilities to Talisman for decommissioning. Preparation for the re-transfer is underway.

DRILLING ACTIVITY

  • Handcross (UK): Following completion of the successful Handcross exploration well farm-out programme in 2013, which resulted in Ithaca achieving a full carry for its share of the well cost, the commitment well transferred as part of the Valiant acquisition was drilled on the prospect in early 2014. No hydrocarbons were encountered by the well in the target formation. 
  • Trell (Norway): A farm-in executed with TOTAL E&P Norge AS resulted in an oil discovery close to existing infrastructure being made on the "Trell" prospect in February 2014. The joint venture is currently working on updating the subsurface model to incorporate the well data and assess the potential recoverable volumes and development options for the discovery.

Q1 2014 RESULTS OF OPERATIONS

REVENUE

Revenue up 67% on Q1-2013

Revenue increased by $39.8 million from Q1 2013 to $99.6 million (Q1 2013: $59.8 million). This was primarily driven by an increase in oil sales volumes coupled with a small realised oil price increase.

Oil sales volumes increased primarily due to the inclusion of sales from the Dons and Causeway fields following the acquisition of Valiant, partially offset by lower volumes from the Beatrice and Jacky fields.

The decrease in gas sales in Q1 2014 compared to Q1 2013 was due to a combination of lower sales volumes, primarily driven by the shut-in of Topaz for the quarter, and a slightly lower realised price per boe.

There was a small increase in average realized oil prices from $106.32/bbl in Q1 2013 to $108.23/bbl in Q1 2014. The average Brent price for the quarter ended 31 March 2014 was $108.211/bbl compared to $112.569 for Q1 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. This increase in realized oil price was partially offset by a realized hedging loss of $3.04/bbl in the quarter.

       
Average Realised Price   Q1 2014 Q1 2013
Oil Pre-Hedging $/bbl 108 106
Oil Post-Hedging $/bbl 105 114
Gas $/boe 45 47
       

COST OF SALES

         
    Q1 2014
$'000
  Q1 2013
$'000
Operating Expenditure   41,264   23,227
DD&A   32,465   19,498
Movement in Oil & Gas Inventory   11,861   3,576
Oil purchases   418   157
Total   86,008   46,458
         

Cost of sales increased in Q1 2014 to $86.0 million (Q1 2013: $46.5 million) due to higher production volumes resulting in increases in operating costs and depletion, depreciation and amortization ("DD&A") and movement in oil and gas inventory.

Operating costs increased in the quarter to $41.3 million (Q1 2013: $23.2 million) primarily due to the inclusion of costs for the Dons and Causeway fields acquired from Valiant.

Operating costs increased to $49.72/boe in the quarter (Q1 2013: $41.98) mainly as a result of planned shutdowns in the period on Beatrice and Jacky and weather related downtime on Athena and Cook, coupled with cyclical production on Causeway. Operating costs for the full year are expected to average around $40/boe as production increases as a result of the ongoing production enhancement activities.

DD&A expense for the quarter increased to $32.5 million (Q1 2013: $19.5 million). This was primarily due to higher production volumes in Q1 2014 with the addition of the Dons and Causeway fields.  The blended rate for the quarter has increased to $39.00/boe (Q1 2013: $35.06/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 offset by a credit in the Deferred Tax charged through the Income Statement.

An oil and gas inventory movement of $11.9 million was charged to cost of sales in Q1 2014 (Q1 2013 charge of $3.6 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 Q1 2014 more barrels of oil were sold (893k bbls) than produced (789k bbls), mainly as a result of the timing of Cook and Dons field liftings and Athena shuttle tankers.

             
Movement in Operating Oil & Gas Inventory   Oil
kbbls
  Gas
kboe
  Total
kboe
Opening inventory   193   8   201
Production   789   41   830
Liftings / sales   (893)   (46)   (939)
Transfers/other*   5   -   5
Closing volumes   94   3   97
* Due to long term inventory transfers and terminal quality adjustments etc            
             

ADMINISTRATION & EXPLORATION & EVALUATION EXPENSES

         
$'000   Q1 2014   Q1 2013
General & Administration ("G&A")   3,270   2,476
Share Based Payments   429   295
Total Administration Expenses   3,699   2,771
Exploration & Evaluation ("E&E")   2,008   312
Impairment   2,895   -
Total   8,602   3,083
         

Total administrative expenses increased in the quarter to $3.7 million (Q1 2013: $2.8 million) primarily due to an increase in general and administrative expenses as a result of the continued growth of the Company. Around $1.6 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 increased as a result of a tranche of options being granted during the quarter (no grant in Q1 2013), as well as being dependent on cost distribution based on the timewriting profile during any period.

Exploration and evaluation expenses of $2.0 million were recorded in the quarter (Q1 2013: $0.3 million) associated with the relinquishment of licences transferred as part of the Valiant acquisition in April 2013, including $0.7 million relating to Norway.

The impairment charge above represents further costs of a capital nature recognised in the quarter 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

A foreign exchange loss of $0.4 million was recorded in Q1 2014 (Q1 2013: $0.6 million gain). 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 January 1, 2014: 1.65. USD:GBP at March 31, 2014: 1.66 with fluctuations between 1.62 and 1.68 during the quarter).

The Company recorded an overall $4.0 million gain on financial instruments for the quarter ended March 31, 2014 (Q1 2013: $7.2 million loss). A $1.3 million cash gain was realised in respect of instruments which expired during the quarter - comprising a $2.7 million realised loss on commodity hedges and a $4.0 million realised gain on foreign exchange instruments.

Also contributing to the gain was the revaluation of instruments at March 31, 2014 which relates to instruments still held at the quarter end. This $2.7 million non-cash revaluation primarily related to an upward revaluation of commodity hedges, due to an increase in value of oil swaps and put options based on the movement in the Brent oil forward curve from the year end and the implied volatility at the end of the reporting period, offset by the expiry of foreign exchange hedges. 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 $106 at March 31, 2014, a reduction from $110 at December 31, 2013, resulting in a mark-to-market gain on commodity hedges which were entered into to ensure prices of over $100/bbl were obtained. 

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 $0.9 million of negative goodwill was recognised in Q1 2013 in relation to the Cook acquisition from Noble ($0 million in Q1 2014).

GAIN ON FARM-OUT
Following completion of the committed Handcross well during the quarter, an additional gain of $2.2 million has been recognised in the income statement as a result of the farm-out programme.

FINANCE COSTS

Finance costs increased to $6.3 million in Q1 2014 (Q1 2013: $2.3 million). This rise primarily reflects interest and fees incurred in relation to the Company's increased debt financing facilities and the drawdowns therefrom. Accretion costs have also increased $0.8 million compared to Q1 2013 due to higher decommissioning liabilities as at March 31, 2014 as a result of inclusion of the former Valiant decommissioning liabilities.

TAXATION

No UK tax anticipated to be payable in the mid-term  
A tax credit of $11.8 million was recognized in the quarter ended March 31, 2014 (Q1 2013: $1.2 million credit). $10.5 million is a non-cash credit relating to UK taxation and is a product of adjustments to the tax charge primarily relating to: UK Ring Fence Expenditure Supplement and share based payments. 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 Q1 2014. Norwegian tax refunds totalling $77.8 million recognised on the balance sheet relate to Norwegian capital expenditure.

As a result of the above factors, profit after tax increased to $16.4 million (Q1 2013: $3.5 million).

No tax is expected to be paid in the mid-term future relating to upstream oil and gas activities as a result of the $1,174 million of UK tax losses available to the Company.

CAPITAL INVESTMENTS

Capital additions to development and production ("D&P") assets totalled $108m in Q1 2014. These relate primarily to the execution of the GSA development, and the drilling of the Fionn sidetrack well during the quarter.

Capital expenditure on E&E assets in Q1 2014 was $23.2 million, offset by a $1.8million release of the acquired E&E liability, resulting in a net addition of $21.4 million. Expenditure was primarily focused on the Trell exploration and appraisal well in Norway as well as UK pre-development projects.

LIQUIDITY AND CAPITAL RESOURCES

Significant investment in development projects  

             
$'000   Q1 2014   Q4 2013   Increase / (Decrease)
Cash & Cash Equivalents   51,456   75,633   (24,177)
Trade & Other Receivables   355,138   335,877   19,261
Inventory   17,582   21,632   (4,050)
Other Current Assets   2,572   5,102   (2,530)
Trade & Other Payables   (397,228)   (472,396)   75,168
Net Working Capital*   29,520   (34,152)   63,672
*Working capital being total current assets less trade and other payables            
             

As at March 31, 2014, Ithaca had a net debit working capital balance of $29.5 million including a free cash balance of $39.1 million ($12.3 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. Other working capital movements are driven by the timing of receipts and payments of balances.

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 March 31, 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 returned to normal levels having been untypically high at year end. Cash advances of $45 million under the Shell oil sales agreements are included within Trade & Other payables.

At March 31, 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 $197 million (Q4 2013: $300 million), with approximately $513 million drawn under the Facility.

Additionally, the Company also has a Norwegian tax refund facility (the "Norwegian Facility") of NOK 450 million (~$75 million), under which approximately $67 million was drawn as at March 31, 2014.

During the quarter ended March 31, 2014 there was a cash outflow from operating, investing and financing activities of approximately $24 million (Q1 2013 inflow of $34.8 million).

Cashflow from operations
Cash generated from operating activities was $44 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 $139 million primarily due to the drawdown of the existing debt facilities in the quarter.

Cashflow from investing activities
Costs incurred in investing activities were $127 million with approximately $240 million cash used in investing activities as a result of the release of working capital built up at the end of Q4 2013. The main components of capital expenditure related to the GSA development and the drilling of the Fionn sidetrack well.

The Company continues to be fully funded, with more than sufficient financial resources to cover its anticipated future commitments from its existing cash balance, debt facilities and forecast cashflow from operations. 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   2,662   -
Other Operating Leases   12,319   2,250   -
Exploration Licence Fees   696   -   -
Engineering   106,224   893   -
Rig Commitments   48,664   -   -
Total   168,840   5,805   -
             

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 upcoming Don Southwest well. As stated above, these commitments are expected to be funded through the Company's existing cash balance, forecast cashflow from operations and its undrawn 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.
Loans and Receivables   Accounts receivable    
Other financial liabilities   Accounts payable, operating bank loans, accrued liabilities   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. 
The classification of all financial instruments is the same at inception and at March 31, 2014.

The table below presents the total gain / (loss) on financial instruments that has been disclosed through the statement of comprehensive income.
 
 
$'000   Q1 2014   Q1 2013
Revaluation Forex Forward Contracts   (4,171)   (2,055)
Revaluation of Other Long Term Liability   23   57
Revaluation of Commodity Hedges   6,949   (9,067)
Revaluation of Interest Rate Swaps   (123)   -
Total Revaluation Gain / (Loss)   2,678   (11,065)
Realised Gain / (Loss) on Commodity Hedges   (2,674)   4,186
Realised Gain / (Loss) on Forex Forward Contracts   4,028   (293)
Realised Loss on Interest Rate swaps   (70)   -
Total Realised Gain   1,284   3,893
Total Gain / (Loss) on Financial Instruments   3,962   (7,172)
         
 

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

Oil Hedging

  • 2.7 million barrels of oil production over the next 2 years hedged at $100/bbl (70% swaps / 30% puts).  This hedging underpins approximately $270 million of revenue while retaining oil price upside on over a third of the hedged volume.

Gas Hedging

  • Secured floor price of £0.58/therm (~$10/MMBTU) for approximately 200 million therms (20 Bcf) of gas sales over gas year's 2015 and 2016.  This hedging underpins approximately $200 million of revenue (net of all hedging costs) while retaining full upside to rising gas prices beyond £0.63/therm.  
             
Derivative   Term   Volume bbl   Average Price $/bbl
Oil Swaps   April 2014 - March 2016   1,963,581   100
Put Options   April 2014 - March 2016   762,800   100
             
Derivative   Term   Volume Therms   Average Price p/therm
Gas Swaps   April 2014 - December 2014   1,210,000   67
Gas Puts   October 2015 - June 2017   187,300,000   64
             

Post quarter end, further oil swaps were entered into for approximately 0.3 million barrels of production for the period to Q1 2016 at a weighted average price of $100/bbl.

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   31 Mar 2014   31 Dec 2013   30 Sep 2013   30 Jun 2013   31 Mar 2013   31 Dec 2012   30 Sep 2012   30 Jun 2012
Revenue   96,600   111,696   114,112   128,360   59,769   52,566   41,579   35,779
Profit After Tax   16,365   44,242   43,145   53,827   3,472   45,347   4,894   30,238
                                 
Earnings per share "EPS" - Basic2   0.05   0.14   0.14   0.18   0.01   0.17   0.02   0.12
EPS - Diluted2   0.05   0.13   0.13   0.17   0.01   0.17   0.02   0.11
Common shares outstanding (000)   326,195   323,634   317,366   317,366   259,953   259,920   259,346   259,346
 
1Q2-13 and Q3-13 restated to account for adjustment to Valiant acquisition accounting
2Based 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 March 31, 2014 Ithaca had 328,148,621 common shares outstanding along with 17,243,566 options outstanding to employees and directors to acquire common shares.

In Q1 2014, the Company's Board of Directors granted 7,165,000 options at a weighted average exercise price of C$2.71. Each of the options granted may be exercised over a period of four years from the grant date. One third of the options will vest at the end of each of the first, second and third years from the effective date of grant.

Due to the exercise and listing of option shares following the end of Q1-2014, as at May 9, 2014, Ithaca had 328,398,620 common shares outstanding along with 16,993,567 options outstanding to employees and directors to acquire common shares.

     
    March 31, 2014
Common Shares Outstanding   328,148,621
Share Price(1)   $2.49 / Share
Total Market Capitalisation   $817,090,066
(1) Represents the TSX close price (CAD$2.75) on March 31, 2014. US$:CAD$0.9039 on March 31, 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 December 31, 2013, there were no changes in our internal control over financial reporting that occurred during the year ended December 31, 2013 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 year ended December 31, 2013, 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 Corporation.

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 March 31, 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 Q1 2014 was $0.1 million (Q1 2013: $0.1 million). These transactions are in the normal course of business and are conducted on normal commercial terms with consideration comparable to those charged by third parties.

As at March 31, 2014 the Company had a loan receivable from FPF-1 Ltd, an associate of the Company, for $31.6 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 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 Facilities include covenants which restrict, among other things, the Company's ability to incur additional debt or dispose of assets.

As is standard to a credit facility, the Company's and Ithaca Energy (UK) Limited's assets have been pledged as collateral and are subject to foreclosure in the event the Company or Ithaca Energy (UK) Limited's defaults on 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 Company routinely produces detailed cashflow forecasts to monitor its compliance with the financial tests and liquidity requirements of 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.

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 has established a fully funded business plan and routinely monitors its detailed cashflow forecasts and liquidity requirements to maintain its funding requirements.

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 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.
  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.

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.
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 acts at all times as a reasonable and prudent operator and has non-operated interests in assets where the designated operator is required to act in the same manner. The Company takes out market insurance to mitigate many of these operational, construction and environmental risks.
The Company uses experienced service providers for the completion of work programmes.
The Company uses the services of Sproule International Limited ("Sproule") to independently assess the Company's reserves on an annual basis.
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;
  • 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;
  • 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 May 9, 2014. The Q1 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 March 31, 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 www.sedar.com.

 
Consolidated Statement of Income
For the three months ended 31 March 2014 and 2013
(unaudited)
     
  Note 2014
US$'000
2013
US$'000
       
Revenue 5 99,640 59,769
Cost of Sales 6 (86,008) (46,458)
Gross Profit   13,632 13,311
       
Exploration and evaluation expenses 12 (2,008) (312)
Impairment of assets   (2,895) -
Administrative expenses 7 (3,699) (2,771)
Operating Profit   5,030 10,228
       
Foreign exchange   (373) 563
Gain/(loss) on financial instruments 27 3,962 (7,172)
Gain on farmout   2,190 -
Negative goodwill   - 914
Profit Before Interest and Tax   10,809 4,533
       
Finance costs 8 (6,274) (2,276)
Interest income   25 20
Profit Before Tax   4,560 2,277
       
Taxation 25 11,805 1,195
Profit After Tax   16,365 3,472
       
Earnings per share (US$ per share)      
Basic 24 0.05 0.01
Diluted 24 0.05 0.01
       

The accompanying notes are an integral part of the financial statements.

     
Consolidated Statement of Financial Position    
(unaudited)      
    31 March
2014
US$'000
31 December 2013
US$'000
ASSETS      
       
Current assets      
Cash and cash equivalents   39,146 63,435
Restricted cash   12,310 12,198
Accounts receivable 10 330,033 314,727
Deposits, prepaid expenses and other   25,104 21,150
Inventory 11 17,582 21,632
Derivative financial instruments 28 2,572 5,102
    426,747 438,244
Non-current assets      
Long-term receivable 30 31,565 31,655
Long-term inventory 11 8,126 8,126
Investment in associate 15 18,337 18,337
Exploration and evaluation assets 12 76,997 57,628
Property, plant & equipment 13 1,496,228 1,423,712
Goodwill 14 985 985
    1,632,238 1,540,443
       
Total assets   2,058,985 1,978,687
       
LIABILITIES AND EQUITY      
       
Current liabilities      
Trade and other payables 17 397,228 472,396
Exploration obligation 18 11,039 12,859
    408,267 485,255
       
Non current liabilities      
Borrowings 16 569,117 432,243
Decommissioning liabilities 19 175,295 172,047
Other long term liabilities 20 - 6,037
Deferred tax liabilities 25 14,505 9,909
Contingent consideration 21 4,000 4,000
Derivative financial instruments 28 9,047 15,550
    771,964 639,786
       
Net assets   878,754 853,646
       
Shareholders' equity      
Share capital 22 547,291 535,716
Share based payment reserve 23 16,422 19,254
Retained earnings   315,041 298,676
Total equity   878,754 853,646
       
The financial statements were approved by the Board of Directors on 9 May 2014 and signed on its behalf by:
       
"Les Thomas"      
Director      
       
"Jay Zammit"      
Director      
       

The accompanying notes 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
Share based payment - 994 - 994
Options exercised 47 (18) - 29
Net income for the period - - 3,472 3,472
Balance, 31 March 2013 431,365 21,316 157,462 610,143
         
Balance, 1 Jan 2014 535,716 19,254 298,676 853,646
Share based payment - 1,693 - 1,693
Options exercised 11,575 (4,525) - 7,050
Net income for the period - - 16,365 16,365
Balance, 31 March 2014 547,291 16,422 315,041 878,754
         

The accompanying notes are an integral part of the financial statements.

   
For the three months ended 31 March 2014 and 2013  
(unaudited)  
  2014
US$'000
2013
US$'000
Operating activities    
     
  Profit Before Tax 4,560 2,277
       
  Adjustments for:    
  Depletion, depreciation and amortisation 32,464 19,498
  Exploration and evaluation write off 2,008 312
  Impairment 2,895 -
  Share based payment 429 295
  Loan fee amortisation 926 592
  Revaluation of financial instruments (2,678) 11,065
  Gain on farm-out (2,190) -
  Movement in goodwill - (914)
  Accretion 1,305 502
  Bank interest & charges 3,979 1,159
     
Cashflow from operations 43,699 34,786
     
  Changes in inventory, debtors and creditors relating to operating activities 35,403 882
     
Net cash from operating activities 79,102 35,668
     
Investing activities    
     
  Acquisition of Cook - (33,370)
  Capital expenditure (128,705) (25,384)
  Loan to associate (91) -
  Proceeds on farm-out 2,190 -
  Changes in debtors and creditors relating to investing activities (118,406) 12,439
     
Net cash (used in) investing activities (245,012) (46,315)
     
Financing activities    
  Proceeds from issuance of shares 7,050 29
  Derivatives (1,315) (7,947)
  Loan draw down 135,951 55,000
  Bank charges (2,917) (1,110)
     
Net cash from financing activities 138,769 45,972
     
Currency translation differences relating to cash and cash equivalents 2,852 (1,065)
     
Increase/(decrease) in cash and cash equivalents (24,289) 34,260
     
Cash and cash equivalents, beginning of period 63,435 31,374
     
Cash and cash equivalents, end of period 39,146 65,634
     

The accompanying notes 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 9 May 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 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. 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 acquired, the difference is recognised directly in the statement of income as negative goodwill.

Goodwill

Capitalisation

Goodwill acquired through business combinations is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised as the fair value of the Corporation's share of the identifiable net assets acquired and liabilities assumed. If this consideration is lower than the fair value of the identifiable assets acquired, the difference is recognised in the statement of income.

Impairment

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

Interest in joint arrangements and associates

Under IFRS 11, joint arrangements are those that convey joint control which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. Associates are investments over which the Corporation has significant influence but not control or joint control, and generally holds between 20% and 50% of the voting rights.

Under the equity method, investments are carried at cost plus post-acquisition changes in the Corporation's share of net assets, less any impairment in value in individual investments. The consolidated income statement reflects the Corporation's share of the results and operations after tax and interest.

The Corporation's interest in joint operations (eg exploration and production arrangements) are accounted for by recognising its assets (including its share of assets held jointly), its liabilities (including its share of liabilities incurred jointly), its revenue from the sale of its share of the output arising from the joint operation, its share of revenue from the sale of output by the joint operation and its expenses (including its share of any expenses incurred jointly).

Revenue

Oil, gas and condensate revenues associated with the sale of the Corporation's crude oil and natural gas are recognised when title passes to the customer. This generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism. Revenues from the production of oil and natural gas properties in which the Corporation has an interest with joint venture partners are recognised on the basis of the Corporation's working interest in those properties (the entitlement method). Differences between the production sold and the Corporation's share of production are recognised within cost of sales at market value.

Interest income is recognised on an accruals basis and is separately recorded on the face of the statement of income.

Foreign currency translation

Items included in the financial statements are measured using the currency of the primary economic environment in which the Corporation and its subsidiaries operate (the 'functional currency'). The consolidated financial statements are presented in United States Dollars, which is the Corporation's functional and presentation currency.

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of income.

Share based payments

The Corporation has a share based payment plan as described in note 22 (c). The expense is recorded in the consolidated statement of income or capitalised for all options granted in the year, with the gross increase recorded in the share based payment reserve. Compensation costs are based on the estimated fair values at the time of the grant and the expense or capitalised amount is recognised over the vesting period of the options. Upon the exercise of the stock options, consideration paid together with the amount previously recognised in share based compensation reserve is recorded as an increase in share capital. In the event that vested options expire unexercised, previously recognised compensation expense associated with such stock options is not reversed. In the event that unvested options are forfeited or expired, previously recognised compensation expense associated with the unvested portion of such stock options is reversed.

Cash and cash equivalents

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

Restricted cash

Cash that is held for security for bank guarantees is reported in the statement of financial position and statement of cash flow 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 on 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 liability acquired as part of the Beatrice field 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 consolidated statement of income when incurred. Costs incurred after rights to explore have been obtained, such as geological and geophysical surveys, drilling and commercial appraisal costs and other directly attributable costs of exploration and evaluation including technical, administrative and share based payment expenses are capitalised as intangible exploration and evaluation ("E&E") assets.

E&E costs are not amortised prior to the conclusion of evaluation activities. At completion of evaluation activities, if technical feasibility is demonstrated and commercial reserves are discovered then, following development sanction, the carrying value of the E&E asset is reclassified as a development and production ("D&P") asset, but only after the carrying value is assessed for impairment and where appropriate its carrying value adjusted. If after completion of evaluation activities in an area, it is not possible to determine technical feasibility and commercial viability or if the legal right to explore expires or if the Corporation decides not to continue exploration and evaluation activity, then the costs of such unsuccessful exploration and evaluation are written off to the statement of income in the period the relevant events occur.

Impairment

The Corporation's oil and gas assets are analysed into CGU 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 profit or loss or in other comprehensive income in accordance with IAS 39.

Taxation

Current income tax

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

Deferred income tax

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

Deferred tax assets and liabilities are offset only when a legally enforceable right of offset exists and the deferred tax assets and liabilities arose in the same tax jurisdiction.

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 of 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, share based payment, contingent consideration, decommissioning liabilities, derivatives, and deferred taxes are based on estimates. The depreciation charge, any impairment tests and fair value estimates for the purpose of purchase price allocation (business combinations) are based on estimates of proved and probable reserves, production rates, prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be material. Further information on each of these estimates is included within the notes to the financial statements.

4. SEGMENTAL REPORTING

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

5. REVENUE

 
Three months ended 31 March
  2014
US$'000
2013
US$'000
Oil sales 96,601 56,153
Gas sales 2,056 2,771
Condensate sales 20 137
Other income 963 708
  99,640 59,769
     

6. COST OF SALES 

 
Three months ended 31 March
  2014
US$'000
2013
US$'000
Operating costs (41,264) (23,227)
Oil purchases (418) (157)
Movement in oil and gas inventory (11,861) (3,576)
Depletion, depreciation and amortisation (32,465) (19,498)
  (86,008) (46,458)
     

7. ADMINISTRATIVE EXPENSES

 
Three months ended 31 March
  2014
US$'000
2013
US$'000
General & administrative (3,270) (2,476)
Share based payments (429) (295)
  (3,699) (2,771)
     

8. FINANCE COSTS

 
Three months ended 31 March
  2014
US$'000
2013
US$'000
Accretion (note 19) (1,305) (502)
Bank charges & interest (3,979) (1,164)
Loan fee amortisation (926) (592)
Non-operated asset finance fees (64) (18)
  (6,274) (2,276)
     

9. RESTRICTED CASH  

     
  31 March 31 Dec
  2014
US$'000
2013
US$'000
Security 12,310 12,198
  12,310 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 31 March 2014.

10. ACCOUNTS RECEIVABLE

     
  31 March 31 Dec
  2014
US$'000
2013
US$'000
Trade debtors 201,854 194,442
Norwegian tax receivable 77,798 61,397
Accrued income 50,381 58,888
  330,033 314,727
     

11. INVENTORY

     
  31 March
2014
US$'000
31 Dec
2013
US$'000
Crude oil inventory - current 17,367 21,417
Crude oil inventory - non-current 8,126 8,126
Materials inventory 215 215
  25,708 29,758
     

12. EXPLORATION AND EVALUATION ASSETS

   
  US$'000
   
At 1 January 2013 47,390
   
Additions 60,145
Release of exploration obligations (31,170)
Write offs/relinquishments (18,737)
   
At 31 December 2013 57,628
   
Additions 23,197
Release of exploration obligations (1,820)
Write offs/relinquishments (2,008)
   
At 31 March 2014 76,997
   

Following completion of geotechnical evaluation activity, certain licences were declared unsuccessful and certain prospects were declared non-commercial and therefore the related expenditures of $2.0 million were expensed in the three months to 31 March 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 685,533 - 685,533
Additions 332,796 738 333,534
       
At 31 December 2013 1,743,349 3,163 1,746,512
       
Additions 107,533 342 107,875
       
At 31 March 2014 1,850,882 3,505 1,854,387
       
DD&A and Impairment      
       
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 (32,368) (96) (32,464)
Impairment charge for the period (2,895) - (2,895)
       
At 31 March 2014 (355,764) (2,395) (358,159)
       
NBV at 1 January 2013 615,262 526 615,788
       
NBV at 1 January 2014 1,422,848 864 1,423,712
       
NBV at 31 March 2014 1,495,118 1,110 1,496,228
       

The impairment charge above represents further costs of a capital nature recognised in the quarter 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 1 January 2013, 31 December 2013 & 31 March 2014 985
   

$1.0 million represents goodwill recognised on the acquisition of gas assets from GDF in December 2010.

15. INVESTMENT IN ASSOCIATES

     
  31 March
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 Company's share of the associates' results. 

16. BORROWINGS

On 29 June 2012, the Corporation executed a Reserves Based Lending Facility agreement (the "RBL Facility") for up to $430 million, being provided by BNPP as Lead Arranger. The loan term was up to five years and attracted 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 LIBOR plus 1.0 - 2.25%.

In October 2013, the Corporation increased its existing RBL 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. 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 loan

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

As at 31 March 2014, $513 million (31 December 2013: $410 million) was drawn down under the RBL Facility and approximately $66 million (31 December 2013: 34 million) was drawn under the Norwegian Facility. $11 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

     
  31 March 31 Dec
  2014
US$'000
2013
US$'000
Trade payables 205,939 173,052
Accruals and deferred income 191,289 299,344
  397,228 472,396
     

18. EXPLORATION OBLIGATIONS

     
  31 March 31 Dec
  2014
US$'000
2013
US$'000
Exploration obligations 11,039 12,859
     

The above reflects the fair value of E&E commitments assumed as part of the Valiant transaction. During the period to 31 March 2014, $1.8 million was released reflecting expenditure incurred in the period.

19. DECOMMISSIONING LIABILITIES

     
  31 March
2014
US$'000
31 Dec
2013
US$'000
Balance, beginning of period 172,047 52,834
Additions 1,943 105,229
Accretion 1,305 4,509
Revision to estimates - 9,475
Balance, end of period 175,295 172,047
     

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

     
  31 March
2014
US$'000
31 Dec
2013
US$'000
Balance, beginning of period 6,037 3,018
Revaluation in the period (23) 3,019
Reclassed to trade payables (6,014) -
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

     
  31 March
2014
US$'000
31 Dec
2013
US$'000
Balance 31 December 2013 & 31 March 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
Number of ordinary shares Amount
US$'000
At 31 December 2013 and 31 March 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 issue 56,952,321 93,005
Issued for cash - options exercised 6,761,296 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 4,515,001 7,050
Transfer from Share based payment reserve on options exercised - 4,525
Balance 31 March 2014 328,148,621 547,291
     

(b) Stock 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 31 March 2014, 17,243,566 stock options to purchase common shares were outstanding, having an exercise price range of $1.75 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:

         
    31 March 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   (4,515,001)   $1.69   (6,761,296)   $0.95
Options   17,243,566   $2.29   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 31 March 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$2.25-C$2.71) 12,485,232 2.9 $2.40   $2.22-$2.47 (C$2.25-C$2.71) 3,456,667 0.8 $2.23
$1.75-$2.03 (C$1.80-C$1.99) 4,758,334 2.4 $2.01   $1.75-$2.03 (C$1.80-C$1.99) 1,714,998 2.1 $1.98
  17,243,566 2.8 $2.29     5,171,665 1.3 $2.26
                 

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)   3,280,003   2.0   $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)   3,113,338   1.2   $1.53
  $0.20 (C$0.25)   471,668   0.1   $0.17     $0.20 (C$0.25)   4,666,297   0.8   $0.80
    14,593,567   1.9   $2.01       11,059,638   1.3   $1.43
                 

(c) Share based payments

Options granted are accounted for using the fair value method. The cost during the three months ended 31 March 2014 for total stock options granted was $1.7 million (Q1 2013: $0.9 million). $0.4 million was charged through the statement of income for stock based compensation for the three months ended 31 March 2014 (Q1 2013: $0.3 million), being the Corporation's share of stock based compensation chargeable through the statement of income. The remainder of the Corporation's share of stock based compensation has been capitalised. The fair value of each stock option granted was estimated at the date of grant, using the Black-Scholes option pricing model with the following assumptions:

       
  For the three months ended 31 March 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 $1.12   $0.82
       

23. SHARE BASED PAYMENT RESERVE 

     
  31 March
2014
US$'000
31 Dec
2013
US$'000
Balance, beginning of period 19,254 20,340
Share based payment cost 1,693 3,733
Transfer to share capital on exercise of options (4,525) (4,819)
Balance, end of period 16,422 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 31 March
  2014 2013
Weighted av. number of common shares (basic) 326,194,787 259,944,818
Weighted av. number of common shares (diluted) 330,905,217 264,926,389
     

25. TAXATION

 
Three months ended 31 March
  2014
US$'000
2013
US$'000
Taxation 11,805 1,195
     

26. COMMITMENTS

     
  31 March
2014
US$'000
31 Dec
2013
US$'000
Operating lease commitments    
Within one year 13,255 13,262
Two to five years 4,912 8,149
     
     
Capital commitments 31 March
2014
US$'000
31 Dec
2013
US$'000
Capital commitments incurred jointly with other ventures (Ithaca's share) 156,478 150,091
     

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 31 March 2014:

                 
    Level 1
US$'000
  Level 2
US$'000
  Level 3
US$'000
  Total Fair Value
US$'000
Derivative financial instrument asset   -   2,572   -   2,572
Long term liability on Beatrice acquisition   -   -   (6,014)   (6,014)
Contingent consideration   -   (4,000)   -   (4,000)
Derivative financial instrument liability   -   (9,047)   -   (9,047)
                 

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

 
Three months ended 31 March
  2014
US$'000
2013
US$'000
Revaluation of forex forward contracts (4,171) (2,055)
Revaluation of other long term liability 23 57
Revaluation of commodity hedges 6,949 (9,067)
Revaluation of interest rate swaps (123) -
  2,678 (11,065)
     
Realised gain/(loss) on forex contracts 4,028 (293)
Realised gain/(loss) on commodity hedges (2,674) 4,186
Realised (loss) on interest rate swaps (70) -
  1,284 3,893
     
Total (loss) on financial instruments 3,962 (7,172)
     

The Corporation has identified that it is exposed principally to these areas of market risk.

i) Commodity Risk

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

 
Three months ended 31 March
  2014
US$'000
2013
US$'000
Revaluation of commodity hedges 6,949 (9,067)
Realised gain/(loss) on commodity hedges (2,674) 4,186
Total gain/(loss) on commodity hedges 4,275 (4,881)
     

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   Apr 14 - Mar 16   762,800   bbls   $100/bbl
Oil swaps   Apr 14 - Mar 16   1,963,581   bbls   $100/bbl
Gas swaps   Apr 14 - Jun 17   1,210,000   therms   67p/therm
Gas puts   Oct 15 - Jun 17   187,300,000   therms   64p/therm
                 

ii) Interest Risk

Calculation of interest payments for the RBL Facility agreement incorporates LIBOR whilst the Norwegian Facility incorporates NIBOR. The Corporation is therefore exposed to interest rate risk to the extent that LIBOR/NIBOR may fluctuate. The below represents interest rate financial instruments in place:

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

iii) Foreign Exchange Rate Risk

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

 
Three months ended 31 March
  2014
US$'000
2013
US$'000
Revaluation of forex forward contracts (4,171) (2,055)
Realised gain/(loss) on forex forward contracts 4,028 (293)
Total (loss) on forex forward contracts (143) (2,348)
     

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

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 fields is sold to BP Oil International Limited. Oil production from Cook, Broom, Dons, Causeway and Fionn is sold to Shell Trading International Ltd. Anglia and Topaz gas production is currently sold through two contracts to RWE NPower PLC and Hess Energy Gas Power (UK) Ltd. Cook gas is sold to Shell UK Ltd and Esso Exploration & Production UK Ltd.

The Corporation assesses partners' credit worthiness before entering into farm-in or joint venture agreements. In the past, the Corporation has not experienced credit loss in the collection of accounts receivable. As the Corporation's exploration, drilling and development activities expand with existing and new joint venture partners, the Corporation will assess and continuously update its management of associated credit risk and related procedures.

The Corporation regularly monitors all customer receivable balances outstanding in excess of 90 days. As at 31 March 2014, substantially all accounts receivables are current, being defined as less than 90 days. The Corporation has no allowance for doubtful accounts as at 31 March 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 31 March 2014, exposure is $2.6 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 31 March 2014, substantially all accounts payable are current.

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

     
  Within 1 year
US$'000
1 to 5 years
US$'000
Accounts payable and accrued liabilities 397,228 -
Other long term liabilities 6,014 -
Borrowings - 569,117
  403,242 569,117
     

28. DERIVATIVE FINANCIAL INSTRUMENTS

     
  31 March
2014
US$'000
31 December
2013
US$'000
Oil swaps (8,037) (15,349)
Oil puts (308) 597
Gas swaps 270 -
Gas puts 1,594 -
Interest rate swaps 7 -
Foreign exchange forward contract - 4,304
  (6,474) (10,448)
     

Refer to note 27 for further details of derivative financial instruments.

29. FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES

Financial instruments of the Corporation consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in these financial statements. At 31 March 2014, the classification of financial instruments and the carrying amounts reported on the balance sheet and their estimated fair values are as follows:

         
    31 March 2014
US$'000
  31 December 2013
US$'000
Classification   Carrying Amount   Fair Value   Carrying
Amount
  Fair Value
Cash and cash equivalents (Held for trading)   39,146   39,146   63,435   63,435
Restricted cash   12,310   12,310   12,198   12,198
Derivative financial instruments (Held for trading)   2,572   2,572   5,102   5,102
Accounts receivable (Loans and Receivables)   330,033   330,033   314,727   314,727
Deposits   25,104   25,104   21,150   21,150
Long-term receivable (Loans and Receivables)   31,565   31,565   31,655   31,655
                 
Borrowings (Loans and Receivables)   (569,117)   (569,117)   (432,243)   (432,243)
Contingent consideration   (4,000)   (4,000)   (4,000)   (4,000)
Derivative financial instruments (Held for trading)   (9,047)   (9,047)   (15,550)   (15,550)
Other long term liabilities   (6,014)   (6,014)   (6,037)   (6,037)
Accounts payable (Other financial liabilities)   (397,228)   (397,228)   (472,396)   (472,396)
                 

30. 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
 
 
 
 
 
2014
 
 
 
% equity interest at 31 March
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%   Nil
Ithaca Petroleum Limited   England and Wales   100%   Nil
Ithaca North Sea Limited   England and Wales   100%   Nil
Ithaca Exploration Limited   England and Wales   100%   Nil
Ithaca Causeway Limited   England and Wales   100%   Nil
Ithaca Gamma Limited   England and Wales   100%   Nil
Ithaca Alpha Limited   Northern Ireland   100%   Nil
Ithaca Epsilon Limited   England and Wales   100%   Nil
Ithaca Delta Limited   England and Wales   100%   Nil
Ithaca Petroleum Holdings AS   Norway   100%   Nil
Ithaca Petroleum Norge AS   Norway   100%   Nil
Ithaca Technology AS   Norway   100%   Nil
Ithaca AS   Norway   100%   Nil
Ithaca Petroleum EHF   Iceland   100%   Nil
             

Transactions between subsidiaries are eliminated on consolidation.

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

                     
        Sales
US$'000
  Purchases
US$'000
  Accounts receivable
US$'000
  Accounts payable
US$'000
Burstall Winger Zammit LLP   2014   -   63   -   -
    2013   -   515   -   -
                     

A director of the Corporation is a partner of Burstall Winger Zammit LLP who acts as counsel for the Corporation. 

   
Loans to related parties Amounts owed from related parties
  2014 2013
  US$'000 US$'000
FPF-1 Limited 31,565 31,655
     

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

This information is provided by RNS
The company news service from the London Stock Exchange

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