2017 third quarter highlights - ithaca energy · delivery of lower risk growth through the...

MANAGEMENT DISCUSSION & ANALYSIS QUARTER ENDED 30 SEPTEMBER 2017

1

2017 THIRD QUARTER HIGHLIGHTS

Solid cashflow generation in the first nine months of the year

Average production for nine months to 30 September 2017 (“YTD 2017”) of 12,525 boepd (YTD 2016: 9,585 boepd)

Unit operating expenditure(1)

reduced to $20/boe, down from $23/boe annual average rate in 2016

YTD 2017 Cashflow from operations(1)

of $99 million (YTD 2016: $117 million), equating to $29/boe

Earnings of $28 million (YTD 2016: $64 million loss)

Commodity price hedging protection extended in both oil and gas – 9,200 boepd hedged at an average floor price of $46/boe for the 15 months to 31 December 2018

Net debt of $598 million at 30 September 2017

Rising production trend driven by increasing Stella volumes

Production increased from 9,337 boepd in the first quarter of 2017 to 14,339 boepd in the third quarter despite volumes being reduced in the latter period by planned maintenance shutdowns

Full year 2017 production forecast to average 13,000 to 14,000 boepd taking into account year to date performance, including the delayed ramp-up of Stella production in the first half of the year

GSA development activities progressing to plan

Greater Stella Area (“GSA”) production hub now fully established following completion of the switch from tanker loading to oil pipeline exports in September 2017 – reducing fixed operating costs and enhancing operational uptime

FPF-1 formally selected as the host facility for the Vorlich field development – submission of the Field Development Plan to the UK Oil & Gas Authority scheduled for 2018

Harrier field development programme progressing to plan – development drilling programme successfully completed in September 2017, with start-up of production scheduled for 2018

Ithaca is a wholly owned subsidiary of the Delek Group

Takeover by Delek Group Limited (“Delek”) completed in June 2017, followed by delisting of the Company’s shares from the Toronto Stock Exchange (“TSX”) and the AIM market of the London Stock Exchange.

A request has been made to the regulatory authorities for Canadian securities for the Company to cease being a reporting issuer in Canada following delisting of the shares on the TSX

(1) Unit costs and cashflows from operations are stated net of Stella related revenues and expenditures from investment in associate


2

SUMMARY STATEMENT OF INCOME

3-Months Ended 30 Sep. 9-Months Ended 30 Sep.

2017 2016 2017 2016

Average Production kboe/d 14.3 10.0 12.5 9.6

Average Realised Oil Price(1) $/bbl 51 44 51 42

Revenue(2) M$ 60.9 39.0 157.0 107.7

Hedging Cash Gain (Loss) M$ (0.7) 18.1 15.1 76.1

Revenue(2) (After Hedging) M$ 60.2 57.1 172.1 183.8

Opex(3) M$ (28.9) (19.1) (69.7) (61.1)

Other M$ (0.5) - (1.1) -

G&A - underlying M$ (0.9) (0.8) (2.5) (3.8)

G&A – Delek transaction costs M$ 1.0 - (5.0) -

Foreign Exchange(4) M$ 1.9 (2.1) 4.9 (2.3)

Cashflow from Operations M$ 32.8 35.1 98.7 116.8

DD&A M$ (32.1) (21.7) (74.8) (59.1)

Non-Cash Hedging (Loss) M$ (4.1) (10.9) (9.3) (96.1)

Gain on disposal of assets M$ 1.3 - 1.3 -

Finance Costs M$ (12.0) (9.1) (24.8) (27.5)

Other Non-Cash Costs M$ (3.7) (0.2) (12.0) (1.3)

Taxation M$ 21.3 (63.8) 48.3 3.0

Earnings M$ 3.8 (70.7) 27.6 (64.4)

Cashflow Per Share $/Sh. 0.08 0.09 0.23 0.28

Earnings Per Share $/Sh. 0.01 (0.17) 0.07 (0.16)

(1) Average realised price before hedging (2) Revenue net of stock movements (3) Figures shown net of Stella related returns and costs from investment in associate (4) Foreign exchange net of related realised hedging gains & losses

SUMMARY BALANCE SHEET

M$ 30 Sep. 2017 31 Dec. 2016

Cash & Equivalents 20 27

Other Current Assets 178 198

PP&E 1,223 1,112

Deferred Tax Asset 432 384

Other Non-Current Assets 210 210

Total Assets 2,063 1,931

Current Liabilities (256) (245)

Borrowings (600) (619)

Asset Retirement Obligations (210) (207)

Other Non-Current Liabilities (224) (116)

Total Liabilities (1,290) (1,187)

Net Assets 774 744

Share Capital 635 619

Other Reserves - 25

Surplus 139 100

Shareholders’ Equity 774 744


3

CORPORATE STRATEGY

Ithaca Energy Inc. (“Ithaca” or the “Company”) is a North Sea oil and gas operator focused on the

delivery of lower risk growth through the appraisal and development of UK undeveloped discoveries and the exploitation of its existing UK producing asset portfolio. Execution of Ithaca’s strategy is focused on the following core activities:

Maximising cashflow and production from the existing asset base

Delivery of lower risk, long term development led growth through the appraisal of undeveloped discoveries

Continuing to grow and diversify the cashflow base by securing new producing, development and appraisal assets through targeted acquisitions and licence round participation

Maintaining capital discipline, financial strength and a clean balance sheet, supported by lower cost debt leverage

Ithaca is a wholly owned subsidiary of the Tel Aviv stock exchange listed Delek Group Limited (TASE:DLEKG / US ADR:DGRLY), Israel’s leading integrated energy company.

CORPORATE ACTIVITIES

Application made to cease being a Canadian Reporting Issuer

CANADIAN REPORTING ISSUER STATUS Following completion of the takeover by Delek Group in June 2017 and the subsequent delisting of the Company’s shares from the Toronto Stock Exchange (and admission to trading on the AIM market of the London Stock Exchange), Ithaca has applied to the securities regulatory authorities in each of Alberta, British Columbia, Saskatchewan, Manitoba, Ontario, New Brunswick, Nova Scotia, Prince Edward Island and Newfoundland and Labrador (the “Canadian Authorities”) for a decision deeming it to have ceased to be a reporting issuer in such jurisdictions. If the requested decision is granted by the Canadian Authorities, the Company will cease being a reporting issuer in any jurisdiction in Canada and, as a result, will no longer be required to file financial statements and other continuous disclosure documents with Canadian securities regulatory authorities. The Company will continue to make required disclosures to the holders of its 8.125% senior unsecured notes due July 2019 (the “Notes”) pursuant to the terms of the trust indenture governing the Notes.

PRODUCTION & OPERATIONS

Material increase in production driven by start-up of the Stella field in February 2017

PRODUCTION & OPERATIONS Over the course of 2017 quarter on quarter production has been steadily rising as a result of the ramp-up in production from the Stella field since start-up in the first quarter of the year. YTD 2017 production has averaged 12,525 boepd, a 31% increase on the same period in the previous year (YTD 2016: 9,585 boepd), reflecting a step up in volumes from 9,337 boepd in the first quarter of 2017 to 14,339 boepd in the third quarter of the year. While volumes have been on an increasing trend over the course of the year, average production in the third quarter of this year was moderated by an approximately three week shutdown of the Stella field to enable the final FPF-1 oil export pipeline tie-in works to be completed and the switchover from oil tanker loading to pipeline exports to take place. Production was also reduced at the end of the quarter as a consequence of planned maintenance shutdowns commencing on the Floating Production, Storage and Offloading facilities (“FPSOs”) serving the Cook and Pierce fields, both of which were completed in October 2017. Following completion of the maintenance shutdown of the host facility serving the Cook field, it has been identified that certain modifications are required to the control systems on the Cook field to operate the well at unrestricted rates. As such, volumes from the field are expected to be moderately constrained for approximately six months while the necessary equipment is procured and installed. Taking into account the associated deferral of some Cook production and year to date production from the overall asset portfolio, full year 2017 average production is expected to be in the range of 13,000 to 14,000 boepd.


4

GREATER STELLA AREA DEVELOPMENT ACTIVITIES

GSA “hub and spoke” strategy

Ithaca’s focus on the Greater Stella Area (“GSA”) is driven by monetisation of the Company’s existing portfolio of undeveloped discoveries located in the area. With start-up of the Stella field, the Company has established a new production hub serviced by the Ithaca-operated FPF-1 floating production facility, where initial oil and gas processing is undertaken for onward export to market. It is planned for further wells to be drilled and tied back to the FPF-1 on the wider GSA satellite portfolio over the coming years in order to maximise production and cashflow from the area.

Switch from oil tanker to pipeline exports completed

GSA OIL EXPORT PIPELINE Following an approximately three week planned shutdown of the FPF-1 to undertake the final facility and pipeline tie-in activities, the switchover from the export of oil production from the GSA by offshore tanker loading to pipeline exports was completed in September 2017. This move will significantly reduce the fixed operating costs of the GSA facilities, enhance operational uptime and enable improved reserves recovery from the fields served by the FPF-1 production hub.

Harrier field development drilling programme completed – production start-up planned for 2018

HARRIER DEVELOPMENT In line with the Company’s strategy for building out the GSA production hub, the Harrier development programme commenced in April 2017 when the ENSCO 122 heavy duty jack-up rig arrived on location for drilling of a multilateral well into the two Harrier reservoir formations. The drilling programme was completed in September 2017, with the well being suspended ready for connection to the subsea infrastructure that is scheduled for installation in summer 2018. The Harrier well is to be tied back via a 7.5 kilometre pipe to an existing slot on the Stella main drill centre manifold for onward export and processing of production on the FPF-1. The start-up of production from the field is anticipated in the second half of 2018.

Vorlich development scheduled for start-up in 2020

VORLICH DEVELOPMENT Following completion of the studies and commercial negotiations required to finalise the optimal development solution for the BP-operated Vorlich discovery (34% Ithaca working interest), the joint venture has formally selected the FPF-1 as the host facility for the field. It is scheduled for a Field Development Plan to be submitted to the UK Oil and Gas Authority in 2018 for regulatory approval, with the development scheme involving the drilling of two production wells tied back approximately 9 kilometres to the FPF-1. In addition to the value associated with Ithaca’s interest in the Vorlich field, the Company will benefit from the income received by the Stella field joint venture (54.66% Ithaca working interest) for the provision of transportation, processing and operating services by the FPF-1.

COMMODITY HEDGING

Additional hedging put in place – commodity price protection established for 9,200 boepd to December 2018

As part of the financial and risk management strategy of the business, the Company actively seeks to maintain a balanced commodity hedging position. Any hedging is executed at the discretion of the Company, with no minimum requirements stipulated in the Company’s debt finance facilities. In YTD 2017, the Company benefitted from realised commodity hedging gains in the period of $15.1 million, equating to an additional $4.60 of revenue per sales barrel of oil equivalent in the period. Based on valuations relative to the respective oil and gas forward curves as of 1 October 2017, remaining hedges were valued as a liability of $2.1 million. In the third quarter of 2017 the Company entered into additional hedging contracts for 1.7 million barrels of 2017 and 2018 oil production using swaps with a floor price of $53/bbl and 86 million therms of 2017-2019 gas production using swaps with a floor price of 46p/therm. Incorporating this hedging with the Company’s existing position at the end of the quarter, the Company has 9,200 boepd hedged at an average floor price of $46/boe for the 15 months to 31 December 2018. Full commodity price upside exposure has been retained on 20% of the volumes hedged and upside exposure to $60/boe has been retained on a further 10% of the hedged volumes.


5

OPERATING EXPENDITURE

Net unit operating costs for YTD 2017 of $20/boe – forecast to fall further for the full year

Net unit operating expenditure for YTD 2017 was $20/boe; this unit cost is net of the Company’s Stella related revenues and expenditure from its investment in associate. This represents a further reduction on the average rate of $23/boe delivered in 2016, resulting from the introduction of lower cost Stella field production into the portfolio and continued downward pressure on operating costs. Full year 2017 average net unit operating expenditure is expected to be below $20/boe, reflecting the benefit of increased volumes from the Stella field during the final quarter of the year.

CAPITAL EXPENDITURE

2017 capex estimated to be approximately $78M

Capital expenditure in 2017 is forecast to total approximately $78 million, of which approximately $67 million has been incurred in the 9 months to 30 September 2017. The majority of this expenditure relates to the GSA, primarily being Harrier development activities plus completion of the GSA oil export pipeline investment programme and Vorlich field development planning activities.

TRADING ENVIRONMENT

COMMODITY PRICES


2017 2016 2017 2016

Average Brent Price $/bbl 52 46 52 42

Although the increase in Brent has had a positive impact on revenues in YTD 2017 relative to YTD 2016, the Company’s results in YTD 2016 were more materially enhanced by higher priced oil hedges in place during that period.

FOREIGN EXCHANGE RATES


2017 2016 2017 2016

GBP : USD average 1.31 1.31 1.27 1.39

GBP : USD period end spot 1.34 1.30 1.34 1.30

Volatility in exchanges rates resulting from the UK’s decision during 2016 to exit the European Union has had a positive impact on the financial results as a consequence of the ensuing devaluation of the pound sterling versus the US dollar. Prior to the introduction of gas sales from the Stella field the majority of the Company’s revenue was derived from US dollar denominated oil sales, while approximately 80% of costs are incurred in pounds sterling. Going forward, gas sales in pounds sterling are expected to significantly reduce GBP:USD exchange rate exposure.


6

Q3 2017 RESULTS OF OPERATIONS

REVENUE

Revenue


Average Realised Price 2017 2016 2017 2016

Oil Pre-Hedging $/bbl 51 44 51 42

Oil Post-Hedging $/bbl 50 54 55 59

THREE MONTHS ENDED 30 SEPTEMBER 2017 Revenue increased to $73.7 million in Q3 2017 (Q3 2016: $44.6 million) primarily due to increased sales volumes coupled with an increase in realised price, prior to taking account of hedging. Production volumes increased by 43% in Q3 2017 compared to Q3 2016, predominantly due to the addition of Stella production combined with increased volumes from the Pierce field, partially offset by planned maintenance shutdown activities across various key assets in the portfolio during the quarter. Sales volumes were increased further (a 53% increase) due to the timing of Stella oil liftings in 2017. The realised oil price for the quarter increased from $44/bbl in Q3 2016 to $51/bbl in Q3 2017, in line with the increase in Brent for the comparative periods. After taking into account the impact of oil hedging, the average realised oil price in Q3 2017 was reduced by $1/bbl to $50/bbl. This compares to a hedging gain of $10/bbl in Q3 2016. See Foreign Exchange and Financial Instruments section below.

While the realised oil prices for each of the fields in the Company’s portfolio do not strictly follow the Brent price pattern, with some fields sold at a discount or premium to Brent and under contracts with differing timescales for pricing, the average realised price for all the fields trades broadly in line with Brent.

NINE MONTHS ENDED 30 SEPTEMBER 2017 Revenue increased by $46.6 million in YTD 2017 to $148.9 million (YTD 2016: $102.3 million). This 46% increase was driven by a 27% increase in sales volumes coupled with an increase of $9/bbl (or 21%) in the pre-hedging realised oil price associated with the upswing of Brent during the period. As noted above, production volumes increased in YTD 2017 primarily due to the ramp up of the Stella field, coupled with increased production from the Pierce field, partially offset by planned maintenance shutdown activities. The increase in sales volumes was less than this primarily due to the timing of liftings on the Pierce, Cook and Wytch Farm fields.

In terms of average realised oil prices, there was an increase to $51/bbl in YTD 2017 from $42/bbl in YTD 2016. The average Brent price for the nine months ended 30 September 2017 was $52/bbl compared to $42/bbl for YTD 2016. Post hedging the average realised oil price YTD 2017 increased by $4/bbl to $55/bbl. This compares to an oil hedging gain of $17/bbl in YTD 2016.


7

COST OF SALES

Operating Expenditure


$’000 2017 2016 2017 2016

Operating Expenditure 34,356 19,112 80,219 61,145

DD&A 32,070 21,705 74,733 59,088

Movement in Oil & Gas Inventory 12,739 5,586 (8,139) (5,404)

Other 494 - 1,090 -

Total 79,659 46,403 147,903 114,829

THREE MONTHS ENDED 30 SEPTEMBER 2017 Cost of sales increased in Q3 2017 by approximately 72% to $79.6 million (Q3 2016: $46.4 million). This was primarily attributable to production driven increases in operating costs, depletion, depreciation and amortisation (“DD&A”), coupled with a decrease in the quantity of oil and gas inventory. OPERATING EXPENDITURE Reported operating costs increased in the quarter to $34.4 million (Q3 2016: $19.1 million) driven mainly by the addition of Stella operating costs in 2017. These operating costs include tariff payments made to a 49% owned associated company of Ithaca, FPF-1 Limited. The net unit operating cost of the business is calculated by netting off the payments which are received by Ithaca through its 49% ownership in the associated company. In Q3 2017 the net unit operating cost averaged $22 per boe ($21/boe in Q3 2016). This cost is forecast to reduce in Q4 2017 as average production in Q3 2017 was reduced as a result of planned maintenance shutdown activities on various fields. DD&A The unit DD&A rate for the quarter remained steady at $24/boe (Q3 2016: $24/boe), resulting in a total DD&A expense for the period of $32.1 million (Q3 2016: $21.7 million). This increase in expense was due primarily to the inclusion of production from the Stella field.

DD&A

MOVEMENT IN INVENTORY An oil and gas inventory movement of $12.7 million was charged to cost of sales in Q3 2017 (Q3 2016: charge of $5.6 million). This charge arose primarily as a result of decreased stock volumes due to the lifting schedule on Cook in the quarter, partially offset by an increase in value due to the rise in Brent in the period. NINE MONTHS ENDED 30 SEPTEMBER 2017 Cost of sales increased in YTD 2017 to $147.9 million (YTD 2016: $114.8 million) with increases in operating costs and DD&A being offset by the movement in oil and gas inventory. OPERATING EXPENDITURE Operating costs increased in the period to $80.2 million (YTD 2016: $61.1 million) primarily as a result of increased production, partially offset by a reduction in net unit cost from $23/boe to $20/boe year on year due to lower cost Stella field production contribution. DD&A DD&A for the period increased to $74.7 million (YTD 2016: $59.1 million). As noted above, this increase was primarily due to the ramp up of production on the Stella field. MOVEMENT IN INVENTORY An oil and gas inventory movement of $8.1 million was credited to cost of sales in YTD 2017 (YTD 2016: credit of $5.4 million). In YTD 2017 more barrels of oil were produced (2,635 kbbls) than sold (2,499 kbbls), mainly due to the timing of Cook and Pierce field liftings, resulting in an underlift position and associated build-up in inventory, generating a credit to the income statement.

Movement in Operating Oil & Gas Inventory

Oil

kbbls

Gas/NGL

kboe

Total

kboe

Opening inventory 384 (3) 381

Production 2,635 784 3,419

Liftings/sales (2,499) (784) (3,283)

Transfers/other 37 0 37

Closing volumes 557 (3) 554


8

ADMINISTRATION EXPENSES AND EXPLORATION & EVALUATION EXPENSES

Administration expense levels maintained through on-going monitoring


$’000 2017 2016 2017 2016

General & Administration (“G&A”) 937 841 2,772 3,801

Share Based Payments (“SBP”) - 170 294 501

Non-recurring Delek transaction costs (1,045) - 5,022 -

Total Administration Expenses 107 1,011 7,794 4,305

Exploration & Evaluation (“E&E”) write off 194 20 995 839

THREE MONTHS ENDED 30 SEPTEMBER 2017 ADMINISTRATION EXPENSES Total underlying administrative expenses remained stable at $0.9 million in Q3 2017 (Q3 2016: $1.0 million). Underlying G&A costs are tightly managed, with the business continuing to benefit from the savings secured in the current commodity price environment. There is a credit against non-recurring Delek costs in the quarter, reflecting an amended classification of certain of the costs previously disclosed. E&E EXPENSES A minor write off of E&E assets was made at the period end relating to non-commercial prospects. NINE MONTHS ENDED 30 SEPTEMBER 2017 Total underlying administrative expenses decreased in the period to $3.1 million (YTD 2016: $4.3 million) primarily due to the cost saving drive initiated as a result of the lower oil price environment. Additional non-recurring G&A costs of $5.0 million were incurred specifically relating to the Delek takeover transaction.

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS

GBP:US$ month end exchange rate

3-Months Ended 30 September


$’000 2017 2016 2017 2016

Gain on Foreign Exchange 1,870 2,130 4,916 3,036

Total Gain on Foreign Exchange 1,870 2,130 4,916 3,036

Revaluation Forex Forward Contracts - 2,955 (17) (2,322)

Revaluation of Interest Rate Swaps - 102 - 144

Revaluation of Commodity Hedges (4,061) (14,001) (9,243) (93,919)

Total Revaluation (Loss) (4,061) (10,944) (9,260) (96,097)

Realised (Loss) on Forex Contracts - (4,076) (5,027)

Realised (Loss) / Gain on Commodity Hedges (714) 18,104 15,104 76,091

Realised (Loss) on Interest Rate swaps - (78) (235)

Total Realised Gain (714) 13,950 15,104 70,829

Total Foreign Exchange & Financial Instruments (2,905) 5,136 10,760 (22,232)

THREE MONTHS ENDED 30 SEPTEMBER 2017 FOREIGN EXCHANGE While the majority of the Company’s revenue is US dollar denominated, expenditures are predominantly incurred in pounds sterling (some US dollar and Euro denominated costs are also incurred). Consequently, general volatility in the GBP:USD exchange rate is the primary factor underlying foreign exchange gains and losses. In Q3 2017, a foreign exchange gain of $1.9 million was recorded (Q3 2016: $2.1 million gain). This was primarily driven by timing differences on the settlement of pounds sterling invoices.


9

FINANCIAL INSTRUMENTS The Company recorded an overall loss of $4.8 million on financial instruments for the quarter ended 30 September 2017 (Q3 2016: $3.0 million gain). A $0.7 million realised loss was made in Q3 2017. This related to oil hedges maturing during the quarter. In addition to the small realised loss the Company recorded a $4.1 million negative revaluation of instruments as at 30 September 2017, due primarily to the addition of new oil swaps entered into during the quarter (with an average fixed price of $53/boe) and a rise in the forward oil price curve. NINE MONTHS ENDED 30 SEPTEMBER 2017 FOREIGN EXCHANGE A foreign exchange gain of $4.9 million was recorded in YTD 2017 (YTD 2016: $3.0 million gain) primarily due to volatility in the GBP:USD exchange rate, with fluctuations between 1.20 and 1.36 during the period and a closing rate of 1.34 on 30 September 2017. FINANCIAL INSTRUMENTS The Company recorded an overall $5.8 million gain on financial instruments for the nine month period ended 30 September 2017 (YTD 2016: $25.3 million loss). A $15.1 million gain was recorded in respect of realised commodity hedges, comprising $8.5 million on oil hedges and $6.6 million on gas hedges maturing during the period. Offsetting the realised gain was the revaluation of instruments as at 30 September 2017, which values instruments still held at quarter end. This $9.3 million negative revaluation related to a negative revaluation of oil hedges of $6.1 million and a negative revaluation of gas hedges of $3.1 million. The loss on commodity instruments was primarily due to the realisation of the amounts noted above (i.e. where they are no longer still held at the period end), coupled with movements in value of the remaining instruments based on the movement in the forward curve from the start of the year to the end of the reporting period. As of 1 October 2017 the Company’s commodity hedges were valued as a liability of $2.1 million based on valuations relative to the respective oil forward curves, comprising an oil hedging liability of $2.6m offset by a gas hedging asset of $0.5m.

FINANCE COSTS

Underlying finance costs remain stable



$’000 2017 2016 2017 2016

Bank interest and charges (4,628) (946) (7,114) (3,228)

Senior notes interest (6,094) (3,830) (14,508) (11,489)

Finance lease interest (233) (247) (710) (751)

Non-operated asset finance fees (94) (9) (150) (21)

Prepayment interest (776) (706) (2,156) (2,110)

Petrofac incentive payment interest (172) - (172) -

Loan fee amortisation (1,040) (1,040) (3,121) (3,119)

Accretion (2,098) (2,316) (6,251) (6,883)

Total Finance Costs (15,135) (9,094) (34,182) (27,601)

THREE MONTHS ENDED 30 SEPTEMBER 2017 Finance costs charged to the income statement increased to $15.1 million in Q3 2017 (Q3 2016: $9.1 million). This increase is primarily attributable to the cessation of capitalisation of interest relating to the Stella development now that the field is producing. All other finance costs have remained relatively stable quarter on quarter. NINE MONTHS ENDED 30 SEPTEMBER 2017 Finance costs charged to the income statement increased to $34.2 million in YTD 2017 (YTD 2016: $27.6 million). As noted above, this increase primarily reflects the cessation of interest capitalisation on the Stella development.


10

TAXATION

No UK tax anticipated to be payable within the next 5 years


$’000 2017 2016 2017 2016

UK & Norway Corporation Tax – excluding Rate Changes

21,331 10,854 48,332 64,665

Impact of Change in Tax Rates - (74,749) - (61,712)

Total Taxation 21,331 (63,895) 48,332 2,953

THREE MONTHS ENDED 30 SEPTEMBER 2017 A tax credit of $21.3 million was recognised in the quarter ended 30 September 2017 (Q3 2016: $63.9 million charge). In addition to the expected $7.0m credit, being 40% of the loss before taxation, significant components of the credit include a $10.2 million credit relating to the UK Ring Fence Expenditure Supplement, and a $0.8 million credit in respect of the additional capital allowances recognised in relation to Stella for expenditure incurred by Ithaca but paid by Petrofac. In accordance with the Stella Sale and Purchase Agreement (“SPA”), Ithaca receives the right to claim a tax benefit for these capital allowances and the tax benefit of these allowances continue to be received by Ithaca as the expenditure is incurred. In recognition of the benefit Ithaca receives from the additional capital allowances a payment is expected to be made to Petrofac 5 years after legal completion of the SPA, in accordance with its terms, of a sum calculated at the prevailing tax rate applied to the relevant capital allowances. A related deferred tax asset is recorded at 30 September 2017 of $97.2 million reflecting the expected future benefit of these additional capital allowances. NINE MONTHS ENDED 30 SEPTEMBER 2017 A tax credit of $48.3 million was recognised in the nine months ended 30 September 2017 (YTD 2016: $3.0 million credit). Significant components of the credit include a $29.1 million credit relating to the UK Ring Fence Expenditure Supplement; a $3.8 million credit relating to stock options exercised, and $2.2 million in respect of additional capital allowances recognised in relation to Stella for expenditure incurred by Ithaca but paid by Petrofac as explained above. It was announced in the UK Budget on 16 March 2016 that Petroleum Revenue Tax ("PRT") was effectively abolished from 1 January 2016 with the introduction of a 0% rate. This eliminated the Company's future PRT tax charge from 1 January 2016. The PRT rate change was enacted in March 2016 and therefore the deferred PRT provision was fully released through the YTD 2016 results giving rise to a credit of $24.2 million. Further, it was also announced in the UK Budget on 16 March 2016 that the Supplementary Corporation Tax (“SCT”) rate payable by oil and gas producers would be reduced from 20% to 10% with effect from 1 January 2016. This reduced the Company’s future SCT charge accordingly. The impact of the 10% reduction in the Supplementary Charge was to reduce the net deferred tax assets by $74.7 million, coupled with the CT impact of the PRT rate change of $11.2 million, giving an overall rate change driven CT charge for YTD 2016 of $85.9 million.

CAPITAL INVESTMENTS

2017 capital investment programme primarily focused on GSA development activities

$’000 Additions YTD 2017

Development & Production (“D&P”) 184,386

Exploration & Evaluation (“E&E”) 3,743

Other Fixed Assets 40

Total 188,169

Excluding capitalised interest costs and capitalisation of future Stella related payments to Petrofac, underlying capital expenditure in the period was approximately $67 million, which mainly related to activities on the GSA, predominantly being drilling operations on the Harrier field.


11

WORKING CAPITAL

$’000 30 Sep. 2017 31 Dec. 2016 Increase / (Decrease)

Cash & Cash Equivalents 20,163 27,199 (7,036)

Trade & Other Receivables 142,286 158,579 (16,293)

Inventory 32,064 27,729 4,335

Other Current Assets/(Liabilities) (2,052) 7,183 (9,235)

Trade & Other Payables (235,435) (236,928) 1,493

Net Working Capital* (42,974) (16,238) (26,736)

*Working capital being total current assets less trade and other payables

As at 30 September 2017 Ithaca had a net working capital credit balance of $43.0 million, including an unrestricted cash balance of $20.2 million held with BNP Paribas. Substantially all of the accounts receivable are current, being defined as less than 90 days. The Company regularly monitors all receivable balances outstanding in excess of 90 days. No credit loss has historically been experienced in the collection of accounts receivable. Working capital movements are driven by the timing of receipts and payments of balances and fluctuate in any given period. A significant proportion of Ithaca’s accounts receivable balance is with customers and co-venturers in the oil and gas industry and is subject to normal joint venture/industry credit risks. Net working capital has decreased over the period to 30 September 2017 primarily as a result of the positive cashflow from operations in the period being offset by capital expenditure and repayment of borrowings.

NET DEBT & CAPITAL RESOURCES

Refinancing opportunities under review following completion of the Delek acquisition

NET DEBT Net debt at 30 September 2017 of $598 million was materially unchanged from the year-end position. With the ramping-up of production from the Stella field, the increased operating cashflows of the business are scheduled to result in resumption of the downward trend in net debt that was established in 2016. With the reserves based lending facilities and senior notes having maturities in late 2018 and mid-2019 respectively, the Company is assessing its options to refinance these maturities as part of optimising the financial position of the business with the support of the Delek Group. As such, the Company is focused on retaining adequate liquidity headroom while at the same time maintaining flexibility around any future financing activities associated with delivering upon the growth objectives of the business. It is anticipated that the bank debt facilities will be refinanced later this year.

DEBT SUMMARY (M$) 30 Sep. 2017 31 Dec. 2016

RBL Facility 303.1 324.9

Senior Notes 300.0 300.0

Delek Term Loan 15.0 -

Total Debt 618.1 624.9

UK Cash and Cash Equivalents (20.2) (27.2)

Net Drawn Debt 597.9 597.7

Note this table shows debt repayable as opposed to the reported balance sheet debt which nets off capitalised RBL and senior note costs

DEBT FACILITIES Ithaca has existing available debt facilities of over $630 million, comprising bank debt, senior notes and a parent company loan. As at 30 September 2017 the bank debt facilities total $375 million ($330 million senior RBL Facility and $45 million junior RBL), both with a maturity of September 2018. As at the same date, the debt


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availability of these facilities was over $300 million. In addition, following the takeover by Delek, the Company has in place a $30 million unsecured parent company term loan with a maturity of September 2018. When combined with the $300 million senior unsecured notes, due July 2019, the Company has drawn debt of $618 million and cash in the bank of $20.2 million. Both RBL facilities are based on conventional oil and gas industry borrowing base financing terms, neither of which have historic financial covenant tests, and are due to mature in late 2018. Similarly, neither the Company’s $300 million senior unsecured notes nor the term loan from Delek have any historic or maintenance financial covenant tests. The Company was in compliance with all its relevant financial and operating covenants during the quarter. The key covenants in the senior and junior RBL facilities, which are available on the Company’s SEDAR profile at www.sedar.com, are:

A corporate cashflow projection showing total sources of funds must exceed total forecast uses of funds for the later of the following 12 months or until forecast first oil from the Harrier field.

The ratio of the net present value of cashflows secured under the RBL for the economic life of the fields to the amount drawn under the facility must not fall below 1.15:1.

The ratio of the net present value of cashflows secured under the RBL for the life of the debt facility to the amount drawn under the facility must not fall below 1.05:1.

Working capital driven cash outflow in the quarter

YTD 2017 CASHFLOW MOVEMENTS During the nine months ended 30 September 2017 there was a cash outflow from operating, investing and financing activities of approximately $7.0 million (YTD 2016 inflow of $18.2 million); as set out in the following graph.

Cashflow from operations Cash generated from operating activities was $94.5million. Revenues from the producing portfolio of assets were bolstered by the start-up of production from the Stella field, combined with realised gains from the hedging programme in place and reduced unit operating costs. Cashflow from financing activities Cash used in financing activities was $41.0 million, being interest charges coupled with repayments of the RBL debt facility during the period, partly offset by the receipt of a term loan from Delek. Cashflow from investing activities Cash used in investing activities was $78.0 million, primarily associated with further capital expenditure on the GSA development (including capitalised interest).


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COMMITMENTS

The Company’s commitments relate primarily to capital investment activities on the GSA, along with other on-going operational commitments across the portfolio. With the Stella field now in production, the Company’s overall commitments are relatively modest and are forecast to be funded from the operating cashflows of the business.

$’000 1 Year 2-5 Years 5+ Years

Office Leases 108 - -

Licence Fees 488 - -

Engineering 15,831 - -

Rig Commitments 1,357 - -

Total 17,784 - -

FINANCIAL INSTRUMENTS

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

Financial Instrument Category

Ithaca Classification Subsequent Measurement

Held-for-trading Cash, cash equivalents, restricted cash, derivatives, commodity hedges, long-term liability

Fair Value with changes recognised in net income

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

Loans and Receivables Accounts receivable

Other financial liabilities Accounts payable, operating bank loans, accrued liabilities

The classification of all financial instruments is the same at inception and at 30 September 2017.

COMMODITIES The following table summarises the commodity hedges in place at 30 September 2017.

Derivative Term Volume bbls

Average Price $/bbl

Oil Puts October 2017 – June 2018 852,800 54

Oil Swaps October 2017 – Dec 2018 1,743,653 53

Oil Collars October 2017 – June 2018 337,503 47 -60*

* Hedged with an average floor price of $47.30/bbl and a celling price of $60.10/bbl.

Derivative Term Volume therms

Average Price p/therm

Gas Swaps October 2017 – March 2019 86,448,000 46

The Company has 9,200 boepd (70% oil) hedged at an average floor price of $46/bbl for the 15 months to 31 December 2018. This total is comprised of:

3,800 bopd of oil swap contracts at an average price of $53/bbl

700 bopd of oil collars with a floor price of $47/bbl and a ceiling price of $60/bbl

1,900 bopd of oil put options with a floor price of $54/bbl

86 million therms of gas swaps at an average price of 46p/therm


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QUARTERLY RESULTS SUMMARY

$’000 30 Sep 2017

30 Jun 2017

31 Mar 2017

31 Dec 2016

30 Sep 2016

30 Jun 2016

31 Mar 2016

31 Dec 2015

Revenue 73,680 37,943 37,239 41,346 44,585 24,511 33,250 35,340

(Loss)/Profit Before Tax

(17,578) (7,397) 4,175 (16,256) (6,798) (44,081) (16,521) (363,562)

Profit/(Loss) After Tax

3,752 13,088 10,691 10,648 (70,694) (11,466) 17,712 (177,625)

Earnings per share “EPS” – Basic1

0.01 0.03 0.03 0.26 (0.17) (0.03) 0.04 (0.35)

EPS – Diluted1 0.01 0.03 0.02 0.25 (0.17) (0.03) 0.04 (0.35)

Common shares outstanding (000)

425,339 425,339 415,886 413,099 411,784 411,784 411,384 411,384

1 Based on weighted average number of shares

The most significant factors to have affected the Company's profit before tax during the above quarters are fluctuations in underlying commodity prices and movement in production volumes. The Company has utilised commodity and foreign exchange hedging contracts to take advantage of higher commodity prices and beneficial exchange rates and reduce its exposure to volatility associated with these key factors. However, these contracts can cause volatility in profit after tax as a result of unrealised gains and losses due to movements in commodity prices and exchange rates. In addition, the significant reduction in underlying commodity prices over the period has resulted in impairment write downs in Q4 2015. The tax charge/credit can also be volatile, for example due to the timing of recognition of losses.

OUTSTANDING SHARE INFORMATION

On 5 June 2017, following completion of the notice of compulsory acquisition in relation to the Delek takeover, the Company became a wholly-owned subsidiary of Delek Group Ltd. On 7 June 2017, the Company’s common shares were subsequently delisted from the Toronto Stock Exchange (“TSX”) in Canada and the Alternative Investment Market (“AIM”) in the United Kingdom. As at 30 Sept 2017, following the exercise of share options in accordance with the terms of the Offer, the issued and outstanding common shares of the Company totalled 425,338,568. All share options not exercised and tendered to the Offer were surrendered and cancelled. Accordingly, the fully diluted common shares of the Company remained at 425,338,568 as of 30 September 2017.


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CONSOLIDATION

The consolidated financial statements of the Company and the financial data contained in this management’s discussion and analysis (“MD&A”) are prepared in accordance with IFRS. The consolidated financial statements include the accounts of Ithaca and its wholly‐owned subsidiaries, listed below, and its associates FPU Services Limited (“FPU”) and FPF‐1 Limited (“FPF‐1”). Wholly owned subsidiaries:

Ithaca Energy (Holdings) Limited

Ithaca Energy (UK) Limited

Ithaca Minerals North Sea Limited

Ithaca Energy Holdings (UK) Limited

Ithaca Petroleum Limited

Ithaca Causeway Limited

Ithaca Exploration Limited

Ithaca Alpha (NI) Limited

Ithaca Gamma Limited

Ithaca Epsilon Limited

Ithaca Delta Limited

Ithaca North Sea Limited

Ithaca Petroleum Holdings AS

Ithaca Technology AS

Ithaca AS

Ithaca Petroleum EHF

Ithaca SPL Limited

Ithaca SP UK Limited

Ithaca Dorset Limited

Ithaca Pipeline Limited All inter‐company transactions and balances have been eliminated on consolidation. A significant portion of the Company’s North Sea oil and gas activities are carried out jointly with others. The consolidated financial statements reflect only the Company’s proportionate interest in such activities.


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CRITICAL ACCOUNTING ESTIMATES

Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These accounting policies are discussed below and are included to aid the reader in assessing the critical accounting policies and practices of the Company and the likelihood of materially different results being reported. Ithaca's management reviews these estimates regularly. The emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates. The following assessment of significant accounting policies and associated estimates is not meant to be exhaustive. The Company might realize different results from the application of new accounting standards promulgated, from time to time, by various rule-making bodies. Capitalised costs relating to the exploration and development of oil and gas reserves, along with estimated future capital expenditures required in order to develop proved and probable reserves are depreciated on a unit-of-production basis, by asset, using estimated proved and probable reserves as adjusted for production. A review is carried out each reporting date for any indication that the carrying value of the Company’s D&P and E&E assets may be impaired. For assets where there are such indications, an impairment test is carried out on the Cash Generating Unit (“CGU”). Each CGU is identified in accordance with IAS 36. The Company’s CGUs are those assets which generate largely independent cash flows and are normally, but not always, single developments or production areas. The impairment test involves comparing the carrying value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher of its fair value less costs of disposal and value in use, where the value in use is determined from estimated future net cash flows. Any additional depreciation resulting from the impairment testing is charged to the Statement of Income. Goodwill is tested annually for impairment and also when circumstances indicate that the carrying value may be at risk of being impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU to which the goodwill relates. Where the recoverable amount of the CGU is less than its carrying amount, an impairment loss is recognised in the Statement of Income. Impairment losses relating to goodwill cannot be reversed in future periods. Recognition of decommissioning liabilities associated with oil and gas wells are determined using estimated costs discounted based on the estimated life of the asset. In periods following recognition, the liability and associated asset are adjusted for any changes in the estimated amount or timing of the settlement of the obligations. The liability is accreted up to the actual expected cash outlay to perform the abandonment and reclamation. The carrying amounts of the associated assets are depleted using the unit of production method, in accordance with the depreciation policy for development and production assets. Actual costs to retire tangible assets are deducted from the liability as incurred. All financial instruments are initially recognised at fair value on the balance sheet. The Company’s financial instruments consist of cash, accounts receivable, deposits, derivatives, accounts payable, accrued liabilities, contingent consideration and borrowings. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. In order to recognise share based payment expense, the Company estimates the fair value of stock options granted using assumptions related to interest rates, expected life of the option, volatility of the underlying security and expected dividend yields. These assumptions may vary over time. The determination of the Company’s income and other tax liabilities / assets requires interpretation of complex laws and regulations. Tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded on the financial statements. The accrual method of accounting will require management to incorporate certain estimates of revenues, production costs and other costs as at a specific reporting date. In addition, the Company must estimate capital expenditures on capital projects that are in progress or recently completed where actual costs have not been received as of the reporting date.


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CONTROL ENVIRONMENT

The Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of the Company's disclosure controls and procedures as at 30 September 2017, and concluded that such disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its annual filings, interim filings and other reports filed or submitted under securities legislation is recorded, processed, summarised and reported within the time periods specified in the securities legislation and such information is accumulated and communicated to the Company’s management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosures. The Chief Executive Officer and Chief Financial Officer have designed, or have caused such internal controls over financial reporting to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of the Company’s financial statements for external purposes in accordance with IFRS including those policies and procedures that: (a) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the Company’s assets; (b) are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with IFRS, and that receipts and expenditures of the Company are being made only in accordance with authorisations of management and directors of the Company; and (c) are designed to provide reasonable assurance regarding prevention or timely detection of unauthorised acquisition, use or disposition of the Company’s assets that could have a material effect on the annual financial statements or interim financial statements. The Chief Executive Officer and Chief Financial Officer performed an assessment of internal control over financial reporting as at 30 September 2017, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and concluded that internal control over financial reporting is effective with no material weaknesses identified. Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements and even those options determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

As of 30 September 2017, there were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended 30 September 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

CHANGES IN ACCOUNTING POLICIES

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


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ADDITIONAL INFORMATION

Non-IFRS Measures “Cashflow from operations” and “cashflow per share” referred to in this MD&A are not prescribed by IFRS. These non-IFRS financial measures do not have any standardised meanings and therefore are unlikely to be comparable to similar measures presented by other companies. The Company uses these measures to help evaluate its performance. As an indicator of the Company’s performance, cashflow from operations should not be considered as an alternative to, or more meaningful than, net cash from operating activities as determined in accordance with IFRS. The Company considers cashflow from operations to be a key measure as it demonstrates the Company’s underlying ability to generate the cash necessary to fund operations and support activities related to its major assets. Cashflow from operations is determined by adding back changes in non-cash operating working capital to cash from operating activities. “Net working capital” referred to in this MD&A is not prescribed by IFRS. Net working capital includes total current assets less trade & other payables. Net working capital may not be comparable to other similarly titled measures of other companies, and accordingly Net working capital may not be comparable to measures used by other companies. "Net debt" referred to in this MD&A is not prescribed by IFRS. The Company uses net drawn debt as a measure to assess its financial position. Net drawn debt includes amounts outstanding under the Company’s debt facilities and senior notes, less cash and cash equivalents.

Off Balance 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. Where appropriate, finance leases are recorded on the balance sheet. As at 30 September 2017, finance lease assets of $27.3 million and related liabilities of $28.7 million are included on the balance sheet.

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 Q3 2017 was $0.0 million (Q3 2016: $0.0 million). These transactions are in the normal course of business and are conducted on normal commercial terms with consideration comparable to those charged by third parties. As at 30 September 2017 the Company had loans receivable from FPF-1 Limited and FPU Services Limited, associates of the Company, for $57.2 million and $0.0 million, respectively (30 September 2016: $60.1 million and $0.0 million, respectively) as a result of the GSA transactions.

BOE Presentation The calculation of boe is based on a conversion rate of six thousand cubic feet of natural gas ("mcf") to one barrel of crude oil ("bbl"). The term boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 mcf: 1 bbl, utilising a conversion ratio at 6 mcf: 1 bbl may be misleading as an indication of value.

Reserves The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation. The Company's total net proved and probable reserves at 31 December 2016 were 76. These reserves were independently assessed by Sproule, a qualified reserves evaluator, as of December 31, 2016 in accordance with the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Engineers (Calgary Chapter), as amended from time to time.

Well Test Results Well test results disclosed in the MD&A represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery therefrom. Full pressure transient and well test interpretation analyses may not have been completed and as such flow test results contained in the MD&A should be considered preliminary until such analyses have been completed.


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RISKS AND UNCERTAINTIES

The business of exploring for, developing and producing oil and natural gas reserves is inherently risky. There is substantial risk that the manpower and capital employed will not result in the finding of new reserves in economic quantities. There is a risk that the sale of reserves may be delayed due to processing constraints, lack of pipeline capacity or lack of markets. The Company is dependent upon the production rates and oil price to fund the current development program. For additional detail regarding the Company’s risks and uncertainties, refer to the Company’s Annual Information Form for the year ended 31 December 2016, (the “AIF”) filed on SEDAR at www.sedar.com.

Commodity Price Volatility RISK: 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.

MITIGATIONS: To mitigate the risk of fluctuations in oil and gas prices, the Company routinely executes commodity price derivatives, as a means of establishing a floor in realised prices.

Foreign Exchange Risk RISK: The Company is exposed to financial risks including financial market volatility and fluctuation in various foreign exchange rates.

MITIGATIONS: Given the proportion of development capital expenditure and operating costs incurred in currencies other than the US Dollar, the Company routinely executes hedges to mitigate foreign exchange rate risk on committed expenditure and/or draws debt in pounds sterling to settle sterling costs which will be repaid from surplus sterling generated revenues derived from gas sales.

Interest Rate Risk RISK: The Company is exposed to fluctuation in interest rates, particularly in relation to the debt facilities entered into.

MITIGATIONS: To mitigate the fluctuations in interest rates, the Company routinely reviews the associated cost exposure and periodically executes hedges to lock in interest rates.

Debt Facility Risk RISK: The Company is exposed to borrowing risks relating to drawdown of its debt facilities (the “Facilities”). The available debt capacity and ability to drawdown on the Facilities is based on the Company meeting certain covenants including coverage ratio tests, liquidity tests and development funding tests. The available debt capacity is redetermined semi-annually, using a detailed economic model of the Company and forward looking assumptions of which future oil and gas prices, costs and production profiles are key components. Movements in any component, including movements in forecast commodity prices can therefore have a significant impact on available debt capacity and limit the Company’s ability to borrow. There can be no assurance that the Company will satisfy such tests in the future in order to have access to adequate Facilities.

The Facilities include covenants which restrict, among other things, the Company’s ability to incur additional debt or dispose of assets.

As is standard to a credit facility, the Company's and Ithaca Energy (UK) Limited’s assets have been pledged as collateral and are subject to foreclosure in the event the Company or Ithaca Energy (UK) Limited defaults on the Facilities.

The Facilities are available on the Company’s SEDAR profile at www.sedar.com. Also refer to “Capital resources – Debt Facilities” herein.

MITIGATIONS: The financial tests necessary to draw down upon the Facilities needed were met during the period.

The Company routinely produces detailed cashflow forecasts to monitor its compliance with the financial and liquidity tests of the Facilities and maintain the ability to execute proactive debt positive actions such as additional commodity hedging.

Financing Risk 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.


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MITIGATIONS: The Company has established a business plan and routinely monitors its detailed cashflow forecasts and liquidity requirements to ensure it will continue to be fully funded.

The Company believes that there are no circumstances that exist at present which require forced divestments, significant value destroying delays to existing programs or will likely lead to critical defaults relating to the Facilities.

Third Party Credit Risk 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.

MITIGATIONS: Where appropriate, a cash call process is implemented with partners to cover high levels of anticipated capital expenditure thereby reducing any third party credit risk.

The majority of the Company’s oil production is sold to Shell Trading International Ltd. Gas production is sold through contracts with Shell UK Ltd. and Esso Exploration & Production UK Ltd. Each of these parties has historically demonstrated their ability to pay amounts owing to Ithaca.

Property Risk RISK: The Company’s properties will be generally held in the form of licences, concessions, permits and regulatory consents ("Authorisations"). The Company’s activities are dependent upon the grant and maintenance of appropriate Authorisations, which may not be granted; may be made subject to limitations which, if not met, will result in the termination or withdrawal of the Authorisation; or may be otherwise withdrawn. Also, in the majority of its licences, the Company is a joint interest-holder with other third parties over which it has no control. An Authorisation may be revoked by the relevant regulatory authority if the other interest-holder is no longer deemed to be financially credible. There can be no assurance that any of the obligations required to maintain each Authorisation will be met. Although the Company believes that the Authorisations will be renewed following expiry or granted (as the case may be), there can be no assurance that such authorisations will be renewed or granted or as to the terms of such renewals or grants. The termination or expiration of the Company’s Authorisations may have a material adverse effect on the Company’s results of operations and business.

MITIGATIONS: The Company has routine ongoing communications with the UK oil and gas regulatory body and the Department of Business, Energy & Industrial Strategy (“BEIS”). Regular communication allows all parties to an Authorisation to be fully informed as to the status of any Authorisation and ensures the Company remains updated regarding fulfilment of any applicable requirements.

Operational Risk 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, with the exception of the Wytch Farm field for whjch the facilities are located onshore in the south of England, and as such, Ithaca is exposed to operational risk associated with weather delays that can result in a material delay in project execution. Third parties operate some of the assets in which the Company has interests. As a result, the Company may have limited ability to exercise influence over the operations of these assets and their associated costs. The success and timing of these activities may be outside the Company's control.

There are numerous uncertainties in estimating the Company’s reserve base due to the complexities in estimating the magnitude and timing of future production, revenue, expenses and capital.

MITIGATIONS: The Company acts at all times as a reasonable and prudent operator and has non-operated interests in assets where the designated operator is required to act in the same manner. The Company takes out market insurance to mitigate many of these operational, construction and environmental risks. The Company uses experienced service providers for the completion of work programmes.

The Company uses the services of Sproule International Limited to independently assess the Company’s reserves on an annual basis.

Development Risk RISK: The Company is executing development projects to produce reserves in offshore locations. These projects are long term, capital intensive developments. Development of these hydrocarbon reserves involves an array of complex and lengthy activities. As a consequence, these projects, among other things, are exposed to the volatility of oil and gas prices and costs. In addition, projects executed with partners and co-venturers reduce the ability of the Company to fully mitigate all risks associated with these development activities. Delays in the achievement of production start-up may adversely affect timing of cash flow and the achievement of short-term targets of production growth.


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MITIGATIONS: The Company places emphasis on ensuring it attracts and engages with high quality suppliers, subcontractors and partners to enable it to achieve successful project execution. The Company seeks to obtain optimal contractual agreements, including using turnkey and lump sum incentivised contracts where appropriate, when undertaking major project developments so as to limit its financial exposure to the risks associated with project execution.

Competition Risk RISK: In all areas of the Company’s business, there is competition with entities that may have greater technical and financial resources.

MITIGATIONS: The Company places appropriate emphasis on ensuring it attracts and retains high quality resources and sufficient financial resources to enable it to maintain its competitive position.

Weather Risk RISK: In connection with the Company’s offshore operations being conducted in the North Sea, the Company is especially vulnerable to extreme weather conditions. Delays and additional costs which result from extreme weather can result in cost overruns, delays and, ultimately, in certain operations becoming uneconomic.

MITIGATIONS: The Company takes potential delays as a result of adverse weather conditions into consideration in preparing budgets and forecasts and seeks to include an appropriate buffer in its all estimates of costs, which could be adversely affected by weather.

Reputation Risk RISK: In the event a major incident were to occur in respect of a property in which the Company has an interest, the Company's reputation could be severely harmed

MITIGATIONS: The Company's operational activities are conducted in accordance with approved policies, standards and procedures, which are then passed on to the Company's subcontractors. In addition, Ithaca regularly audits its operations to ensure compliance with established policies, standards and procedures.


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FORWARD-LOOKING INFORMATION

Forward-Looking Information Advisories

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 dispositions and cash flow. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. The use of any of the words “forecasts”, "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe", "could", “scheduled”, “targeted” and similar expressions are intended to identify forward-looking statements and forward-looking information. These statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements or information. The Company believes that the expectations reflected in those forward-looking statements and information are reasonable but no assurance can be given that these expectations, or the assumptions underlying these expectations, will prove to be correct and such forward-looking statements and information included in this MD&A and any documents incorporated by reference herein should not be unduly relied upon. Such forward-looking statements and information speak only as of the date of this MD&A and any documents incorporated by reference herein and the Company does not undertake any obligation to publicly update or revise any forward-looking statements or information, except as required by applicable laws.

In particular, this MD&A and any documents incorporated by reference herein, contains specific forward-looking statements and information pertaining to the following:

The quality of and future net revenues from the Company’s reserves;

Oil, natural gas liquids ("NGLs") and natural gas production levels;

Commodity prices, foreign currency exchange rates and interest rates;

Capital expenditure programs and other expenditures;

Future operating costs;

The sale, farming in, farming out or development of certain exploration properties using third party resources;

Supply and demand for oil, NGLs and natural gas;

The Company’s ability to raise capital and the potential sources thereof;

The continued availability of the Facilities;

The sufficiency of the Facilities, cash balances and forecast cash flow to cover anticipated future commitments;

Expected future net debt and continued deleveraging;

The anticipated effects on production and cashflow of the Stella field post start-up;

The Company’s acquisition and disposition strategy, the criteria to be considered in connection therewith and the benefits to be derived therefrom;

The realisation of anticipated benefits from acquisitions and dispositions;

The anticipated effects of the switchover from tanker loading to pipeline exports for GSA oil production;

The anticipated timing for completion of licence acquisitions;

Expected future payments associated with licence acquisitions;

Statements related to reserves and resources other than reserves;

Development plans associated with pending licence acquisitions, including field development plans and the anticipated timing thereof;

Anticipated benefits of development programmes;

Anticipated cost to develop portfolio investment opportunities;

Potential investment opportunities and the expected development costs thereof;

The Company’s ability to continually add to reserves;

Schedules and timing of certain projects and the Company’s strategy for growth;

The Company’s future operating and financial results;

The ability of the Company to optimise operations and reduce operational expenditures;

Treatment under governmental and other regulatory regimes and tax, environmental and other laws;


23

Production rates;

The ability of the Company to continue operating in the face of inclement weather;

Targeted production levels;

Timing and cost of the development of the Company’s reserves and resources other than reserves;

Estimates of production volumes and reserves in connection with acquisitions and certain projects;

Estimated decommissioning liabilities;

The timing and effects of planned maintenance shutdowns;

The expected impact on the Company's financial statements resulting from changes in tax rates;

The Company's expected tax horizon;

Expected effects of fluctuations in foreign currency exchange rates; and,

Anticipated cost exposure resulting from third party circumstances.

With respect to forward-looking statements contained in this MD&A and any documents incorporated by reference herein, the Company has made assumptions regarding, among other things:

Ithaca’s ability to obtain additional drilling rigs and other equipment in a timely manner, as required;

Access to third party hosts and associated pipelines can be negotiated and accessed within the expected timeframe;

FDP approval and operational construction and development, both by the Company and its business partners, is obtained within expected timeframes;

Ithaca’s ability to receive necessary regulatory and partner approvals in connection with acquisitions and dispositions;

The Company’s development plan for its properties will be implemented as planned;

The market for potential opportunities from time to time and the Company's ability to successfully pursue opportunities;

The Company’s ability to keep operating during periods of harsh weather;

The timing of anticipated shutdowns;

Reserves volumes assigned to Ithaca’s properties;

Ability to recover reserves volumes assigned to Ithaca’s properties;

Revenues do not decrease significantly below anticipated levels and operating costs do not increase significantly above anticipated levels;

Future oil, NGLs and natural gas production levels from Ithaca’s properties and the prices obtained from the sales of such production;

The level of future capital expenditure required to exploit and develop reserves;

Ithaca’s ability to obtain financing on acceptable terms, in particular, the Company’s ability to access the Facilities;

The continued ability of the Company to collect amounts receivable from third parties who Ithaca has provided credit to;

Ithaca’s reliance on partners and their ability to meet commitments under relevant agreements; and,

The state of the debt and equity markets in the current economic environment.

The Company’s actual results could differ materially from those anticipated in these forward-looking statements and information as a result of assumptions proving inaccurate and of both known and unknown risks, including the risk factors set forth in this MD&A and under the heading "Risk Factors" in the AIF and the documents incorporated by reference herein, and those set forth below:

Risks associated with the exploration for and development of oil and natural gas reserves in the North Sea;

Risks associated with offshore development and production including risks of inclement weather and the unavailability of transport facilities;

Operational risks and liabilities that are not covered by insurance;

Volatility in market prices for oil, NGLs and natural gas;

The ability of the Company to fund its substantial capital requirements and operations and the terms of such funding;

Risks associated with ensuring title to the Company’s properties;


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Changes in environmental, health and safety or other legislation applicable to the Company’s operations, and the Company’s ability to comply with current and future environmental, health and safety and other laws;

The accuracy of oil and gas reserve estimates and estimated production levels as they are affected by the Company’s exploration and development drilling and estimated decline rates;

The Company’s success at acquisition, exploration, exploitation and development of reserves and resources other than reserves;

Risks associated with satisfying conditions to closing acquisitions and dispositions;

Risks associated with realisation of anticipated benefits of acquisitions and dispositions;

Risks related to changes to government policy with regard to offshore drilling;

The Company’s reliance on key operational and management personnel;

The ability of the Company to obtain and maintain all of its required permits and licences;

Competition for, among other things, capital, drilling equipment, acquisitions of reserves, undeveloped lands and skilled personnel;

Changes in general economic, market and business conditions in Canada, North America, the United Kingdom, Europe and worldwide;

Actions by governmental or regulatory authorities including changes in income tax laws or changes in tax laws, royalty rates and incentive programs relating to the oil and gas industry including any increase in UK taxes;

Adverse regulatory or court rulings, orders and decisions; and,

Risks associated with the nature of the common shares.

Additional Reader Advisories

The information in this MD&A is provided as of 13 November 2017. The Q3 2017 results have been compared to the results of the comparative period in 2016. This MD&A should be read in conjunction with the Company’s unaudited consolidated financial statements as at 30 September 2017 and 2016 together with the accompanying notes and Annual Information Form (“AIF”) for the year ended 31 December 2016. These documents, and additional information regarding Ithaca, are available electronically from the Company’s website (www.ithacaenergy.com) or SEDAR profile at www.sedar.com.

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