Ithaca Energy earns $16.36-million (U.S.) in Q1 2014
Ticker Symbol: C:IAE
Ithaca Energy earns $16.36-million (U.S.) in Q1 2014
Ithaca Energy Inc (C:IAE)
Shares Issued 328,148,621
Last Close 5/12/2014 $2.54
Tuesday May 13 2014 - News Release
Mr. Les Thomas reports
ITHACA ENERGY INC. FIRST QUARTER 2014 FINANCIAL RESULTS
Ithaca Energy Inc. has released its financial results for the three months ended March 31 2014.
Financial ResultsCashflow 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 A pounds sterling 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."
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 A pounds sterling 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.
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 ACTIVITYHandcross (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.
COST OF SALES
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.
ADMINISTRATION & EXPLORATION & EVALUATION EXPENSES
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
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
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.
Consolidated Statement of Income For the three months ended 31 March 2014 and 2013 (unaudited)