| InterOil CorporationManagementDiscussion and Analysis For the Year ended December 31, 2010March 22, 2011 |   |        |
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| FORWARD-LOOKING STATEMENTS                                                        | 2  |
|-----------------------------------------------------------------------------------|----|
| OIL AND GAS DISCLOSURES                                                           | 4  |
| INTRODUCTION                                                                      | 4  |
| BUSINESS STRATEGY                                                                 | 5  |
| OPERATIONAL HIGHLIGHTS                                                            | 5  |
| SELECTED ANNUAL FINANCIAL INFORMATION AND HIGHLIGHTS                              | 8  |
| YEAR AND QUARTER IN REVIEW                                                        | 15 |
| LIQUIDITY AND CAPITAL RESOURCES                                                   | 23 |
| INDUSTRY TRENDS AND KEY EVENTS                                                    | 31 |
| RISK FACTORS                                                                      | 33 |
| CRITICAL ACCOUNTING ESTIMATES                                                     | 34 |
| NEW ACCOUNTING STANDARDS                                                          | 35 |
| NON-GAAP MEASURES AND RECONCILIATION                                              | 37 |
| PUBLIC SECURITIES FILINGS                                                         | 39 |
| DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING | 39 |
| GLOSSARY OF TERMS                                                                 | 39 |

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|   | · | our ability to finance the development of liquefaction and condensate stripping facilities; |
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|   | · | our ability to negotiate final definitive agreements contemplated by the Heads of Agreement with Energy World Corporation, Ltd; |
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|   | · | the uncertainty on the availability, terms and deployment of capital; |
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|   | · | our ability to construct and commission our liquefaction and condensate stripping facilities together with the construction of the common facilities and pipelines, on time and within budget; |
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|   | · | the inherent uncertainty of oil and gas exploration activities; |
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|   | · | the availability of crude feedstock at economic rates; |
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|   | · | the uncertainty associated with the regulated prices at which our products may be sold; |
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|   | · | difficulties with the recruitment and retention of qualified personnel; |
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|   | · | losses from our hedging activities; |
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|   | · | fluctuations in currency exchange rates; |
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|   | · | risks of legal action against us |
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|   | · | political, legal and economic risks in Papua New Guinea; |
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|   | · | stock price volatility; |
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|   | · | landowner claims and disruption; |
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|   | · | compliance with and changes in foreign governmental laws and regulations, including environmental laws; |
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|   | · | the inability of our refinery to operate at full capacity; |
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|   | · | the impact of competition; |
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|   | · | the adverse effects from importation of competing products contrary to our legal rights; |
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|   | · | the margins for our products; |
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|   | · | inherent limitations in all control systems, and misstatements due to errors that may occur and not be detected; |
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|   | · | exposure to certain uninsured risks stemming from our operations; |
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|   | · | contractual defaults. |
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|   | · | interest rate risk; |
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|   | · | weather conditions and unforeseen operating hazards; |
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|   | · | the impact of legislation regulating emissions of greenhouse gases on current and potential markets for our products; |
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|   | · | general economic conditions, including any further economic downturn and the availability of credit; |
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|   | · | actions by our joint venture partners; |
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|   | · | the impact of our current debt on our ability to obtain further financing; and |
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|   | · | law enforcement difficulties. |
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| Segments   |   | Operations                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
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|       |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| Upstream   |   | Exploration and Production – Explores, appraises and develops crude oil and natural gas structures in Papua New Guinea.  Currently developing the Elk Antelope infrastructure which includes condensate stripping and associated facilities, and the gas gathering and associated common facilities, in connection with commercializing significant gas discoveries.                                                                                                                    |
|       |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| Midstream  |   | Refining – Produces refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea for the domestic market and for export. Liquefaction – The LNG Project.  Developing liquefaction and associated facilities in Papua New Guinea for the export of LNG.                                                                                                                                                                                                          |
|       |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| Downstream |   | Wholesale and Retail Distribution – Markets and distributes refined products domestically in Papua New Guinea on a wholesale and retail basis.                                                                                                                                                                                                                                                                                                                                               |
|       |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| Corporate  |   | Corporate – Provides support to the other business segments by engaging in business development and improvement activities and providing general and administrative services and management, undertakes financing and treasury activities, and is responsible for government and investor relations.  General and administrative and integrated costs are recovered from business segments on an equitable basis. Our corporate segment results also include consolidation adjustments. |

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|   | · | Developing our position as a prudent and responsible business operator; |
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|   | · | Enhancing the existing refining and distribution business; |
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|   | · | Maximizing the value of our exploration assets; |
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|   | · | Monetizing our discovered resources through condensate stripping and  liquefaction facilities and businesses; and |
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|   | · | Positioning ourselves for long term success. |
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|   | · | On February 9, 2010, we acquired a second drilling rig for approximately $4.5 million with additional costs incurred for the inspection, package and transport of the rig.  The rig was shipped from New Zealand to Papua New Guinea and is currently at our facilities in Napa Napa where upgrades were carried out to prepare the rig for in field drilling within Elk and Antelope fields. |
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|   | · | On April 15, 2010, we entered into a preliminary works joint venture and preliminary works financing agreement with Mitsui & Co. Ltd. (“Mitsui”) to commence Front-End Engineering and Design (“FEED”) work on the proposed CS Project.  On August 4, 2010, we finalized a Joint Venture Operating Agreement ("JVOA") with Mitsui for the CS Project.  The capital cost for the CS Project is currently estimated at $550.0 million, with approximately $32.0 million of this to be expended for FEED.  A Final Investment Decision ("FID") by the JVOA partners is currently targeted for before June 30, 2011.  Mitsui will be responsible for arranging or providing financing for the capital costs of the project in the event that a positive FID is made.  An option deed was also executed with Mitsui, under which Mitsui has the option toacquire interests of up to a 5% in the Elk and Antelope fields, and in our proposed LNG Project. |
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|   | · | During the third quarter of 2010, we completed drilling and logging activities on the Antelope 2 well, having drilled a further horizontal section in order to evaluate additional reservoir and test the condensate-to-gas ratio (“CGR”) in the deeper section of the reservoir.  Drill Stem Test 7 produced a stabilized CGR of approximately 24.0 to 27.7 barrels of condensate per million cubic feet of natural gas.  Subsequently, this well was plugged and suspended for planned future completion as a producer prior to start-up of the proposed condensate stripping and LNG processing facilities. |
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|   | · | During the quarter ended September 30, 2010, the Department of Petroleum and Energy in Papua New Guinea approved the divestment of our 15% non-operated interest in PPL 244. |
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|   | · | During the third quarter of 2010, we finalized the acquisition and processing of 40.8 kilometres of 2D seismic over the Bwata gas field (PPL237 with 20.8 kilometers in 2 dip lines) and the Wolverine prospect (PPL238 with 20 kilometers in 2 dip lines).  During the fourth quarter, the seismic program focused on further delineation of Bwata and Wolverine structures, apportioned into 58 km for Bwata (consisting of 3 dip lines and 1 strike line) and 45.4 kilometers for Wolverine (consisting of 3 dip lines and a strike line running north-south).  The data is being processed and interpreted. |
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|   | · | At the end of the 2010, the initial preparatory work on a seismic program for PPL 236 were well advanced with social mapping and construction of the base camp initiated.  Work on the PPL 236 seismic comprises 70 kilometers comprising 6 dip lines which transect the Whale, Tuna, Barracuda, Wahoo, Mako and Shark leads.  The seismic program is expected to be completed in March 2011 and will also fulfil our license commitment for PPL 236. |
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|   | · | On November 30, 2010, we were granted Petroleum Retention License (“PRL”) 15, covering blocks including and surrounding the Elk and Antelope fields, unifying the fields into a single license separate from our exploration acreage and specifying minimum work commitment activities over the next five years.  Specific approvals from the Oil and Gas Minister of Papua New Guinea under the PRL or a Petroleum Development License (“PDL”) will be required from the State before commencement of construction or commercial production of hydrocarbons from the license can begin.  We have initiated the work on the application and associated information required to be submitted to the State. |
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|   | · | During 2010, we bought back a total of 1.45% of interests held under the 2005 Amended and Restated Indirect Participation Interest Agreement (“IPI Agreement”).  In exchange for these interests, we issued 754,788 common shares to those investors which had an aggregate value of $50.7 million when issued.  Our current interest in our exploration licenses after this transaction is 75.6114%, assuming that all remaining IPI investors take up their working interest rights in such licenses and excluding the interests that the State is able to take up under relevant legislation. |
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|   | · | During the last quarter of 2010, we evaluated the seismic results before deciding to drill our next well.  During this time, drilling equipment underwent maintenance, and our drilling and associated equipments crew were on standby.  All costs in relation to the maintenance and standby time has been expensed, which has increased our exploration costs and office and administration and other expenses within the statement of operations. |
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|   | · | Total refinery throughput for the year ended December 31, 2010 was 24,682 barrels per operating day, compared with 21,155 barrels per operating day during 2009. |
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|   | · | Capacity utilization for 2010, based on 36,500 barrels per day operating capacity, was 53% compared with 47% in 2009. |
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|   | · | During the years ended December 31, 2010 and 2009, our refinery was shut down for 81 days and 80 days, respectively. During the quarter ended December 31, 2010 and 2009, our refinery was shut down for 40 and 24 days respectively.  The higher number of shut down days in the fourth quarter of 2010 was due to the turnaround maintenance which ran from October 1, 2010 to November 2, 2010. |
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|   | · | The catalytic reformer unit which allows the refinery to produce reformate for gasoline remained shut down throughout the year due to technical problems.  This shutdown required us to import unleaded gasoline to satisfy domestic needs. |
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|   | · | On September 28, 2010, we together with Liquid Niugini Gas Ltd., signed a heads of agreement with Energy World Corporation (“EWC”) to construct a three million tonne per annum land based LNG facility in the Gulf Province of Papua New Guinea.  Following this agreement, and subsequent to year end, on February 2, 2011, the parties signed certain conditional agreements defining certain parameters for the aforementioned development, construction, financing and the operation of the planned land-based modular LNG facilities.  These facilities are intended to be developed in phases. |
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|   | · | Further engineering and planning work was undertaken to design the LNG and condensate facilities, and appropriate supporting infrastructure, including a jetty and loading facilities together with pipelines for both gas and condensate.  The wells and processed natural gas pipeline and condensate pipeline from the condensate stripping plant to the coast in the Gulf Province will be the responsibility of the owners of the Elk and Antelope fields, including us and our upstream partners. |
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|   | · | Total Downstream sales volumes for 2010 were 626.5 million liters compared with 588.8 million liters for 2009.  Volume growth continued throughout the year, mainly due to increased construction activity in the latter half of the year associated with Exxon Mobil’s LNG project in Papua New Guinea. |
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|   | · | In January 2010, we took delivery of a second charter vessel Saturn, a 13,051 dead weight tones (“DWT”) vessel.  This vessel was initially chartered for nine months and during the year the contract was extended until April 2011.  Our first charter, the MT Ipsilantis, has also been extended for a further 2 years from March 2011.  In June 2010, this vessel was converted from diesel to low sulphur waxy residue (“LSWR”) bunkering fuel.  Our vessels now operate exclusively on LSWR. |
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|   | · | During the second quarter of 2010, we finalized the renewal agreement with Ok Tedi Mining Limited for a two year term with estimated volume in excess of 100.0 million liters per annum. |
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|   | · | During the third quarter of 2010, we finalized agreements with Ramu Nico Limited, and certain contractors for the Exxon Mobil LNG project for an estimated volume of 70.0 million liters per annum. PNG Power Ltd also signed an agreement to source an additional 26.0 million liters per annum for a new power generation site in Port Moresby. |
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|   | · | In November 2010, the Papua New Guinea Independent Consumer and Competition Commission (“ICCC”) completed its review of the pricing arrangements for petroleum products in PNG.  The purpose of the review was to consider the extent to which the existing regulation of price setting arrangements at both wholesale and retail levels should continue, or be revised for the next five year period until the end of 2014.  The report recommended an increase in margins for wholesaling and certain other activities while the retail margin is to remain the same.  It also recommended some increases in monitoring industry activity in PNG. |
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|   | · | During 2009, we reviewed and selected an Enterprise Resource Planning (“ERP”) system for implementation group-wide.  The implementation process for Microsoft Dynamics AX is ongoing and we migrated all businesses and operations, except for Downstream operations, to the new system during 2010.  We plan to migrate the downstream business to the new ERP system during the first half of 2011. |
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|   | · | On August 11, 2010, we entered into a short term secured credit facility of $25.0 million with Clarion Finanz AG (“Clarion”).  The funds were made available in two installments of $12.5 million each on August 11, 2010 and August 30, 2010.  The facility was due to mature on January 31, 2011, and carried an interest rate of 10% per annum.  This facility was fully repaid in November 2010 from the proceeds of our concurrent public offerings. |
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|   | · | On August 31, 2010, we entered into an agreement to settle and release all claims against us and our subsidiaries brought by various plaintiffs in the District Court of Montgomery County, Texas commenced in 2005 and styled Todd Peters et al v. Phil Mulacek et. al. Pursuant to the agreed settlement, on October 19, 2010 we issued 199,677 common shares to the plaintiffs, valued at $12.0 million based on a volume weighted average price calculated over the ten trading days prior to execution of the settlement agreement.  The settlement did not reflect any admission of liability by us. |
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|   | · | On November 5, 2010, we undertook concurrent public offerings of 2,800,000 common shares at an issue price of $75.00 per share for gross proceeds of $210.0 million, and $70.0 million aggregate principal amount of 2.75% convertible senior notes due 2015, raising gross proceeds of $280.0 million from the combined offerings.  The net proceeds after deducting the underwriting discounts, commissions and offering expenses were $266.0 million. |
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| Consolidated – Operating results                                            |   | Year ended December 31, |     |
|--------------------------------------------------------------------------------------------------|--------|----------------------------------------|----------|
| ($ thousands, except per share data)                                    |   | 2010                                   |     |   | 2009 |   |   | 2008 |   |
| Sales and operating revenues                                                                     |   |                                   | 802,374  |   |   |   | 688,479 |   |   |   | 915,579 |   |
| Interest revenue                                                                                 |   |                                   | 151      |   |   |   | 351 |   |   |   | 932 |   |
| Other non-allocated revenue                                                                      |   |                                   | 4,470    |   |   |   | 4,228 |   |   |   | 3,216 |   |
| Total revenue                                                                                    |   |                                   | 806,995  |   |   |   | 693,058 |   |   |   | 919,727 |   |
| Cost of sales and operating expenses                                                             |   |                                   | (701,557 | ) |   |   | (601,983 | ) |   |   | (888,623 | ) |
| Office and administration and other expenses                                                     |   |                                   | (52,650  | ) |   |   | (44,894 | ) |   |   | (46,691 | ) |
| Derivative (loss)/gain                                                                           |   |                                   | (1,065   | ) |   |   | 1,009 |   |   |   | 24,039 |   |
| Exploration costs                                                                                |   |                                   | (16,982  | ) |   |   | (209 | ) |   |   | (996 | ) |
| Exploration impairment                                                                           |   |                                   | -        |   |   |   | - |   |   |   | (108 | ) |
| Gain on sale of oil and gas properties assets                                                    |   |                                   | 2,141    |   |   |   | 7,364 |   |   |   | 11,235 |   |
| Loss on extinguishment of IPI liability                                                          |   |                                   | (30,569  | ) |   |   | (31,710 | ) |   |   | - |   |
| Litigation settlement expense                                                                    |   |                                   | (12,000  | ) |   |   | - |   |   |   | - |   |
| Foreign exchange (loss)/gain                                                                     |   |                                   | (10,777  | ) |   |   | (3,305 | ) |   |   | 3,878 |   |
| Earnings before interest, taxes, depreciation and amortization ("EBITDA" - non-GAAP measure) (1) |   |                                   | (16,464  | ) |   |   | 19,330 |   |   |   | 22,461 |   |
| Depreciation and amortization                                                                    |   |                                   | (14,275  | ) |   |   | (14,322 | ) |   |   | (14,143 | ) |
| Interest expense                                                                                 |   |                                   | (7,364   | ) |   |   | (9,993 | ) |   |   | (20,032 | ) |
| Loss before income taxes and non-controlling interest                                            |   |                                   | (38,103  | ) |   |   | (4,985 | ) |   |   | (11,714 | ) |
| Income tax (expense)/benefit                                                                     |   |                                   | (7,383   | ) |   |   | 11,076 |   |   |   | (82 | ) |
| Non-controlling interest                                                                         |   |                                   | (7       | ) |   |   | (8 | ) |   |   | (1 | ) |
| Net (loss)/profit                                                                                |   |                                   | (45,493  | ) |   |   | 6,083 |   |   |   | (11,797 | ) |
| Net (loss)/profit per share (dollars) (basic)                                                    |   |                                   | (1.03    | ) |   |   | 0.15 |   |   |   | (0.35 | ) |
| Net (loss)/profit per share (dollars) (diluted)                                                  |   |                                   | (1.03    | ) |   |   | 0.15 |   |   |   | (0.35 | ) |
| Total assets                                                                                     |   |                                   | 965,489  |   |   |   | 631,754 |   |   |   | 591,843 |   |
| Total liabilities                                                                                |   |                                   | 276,967  |   |   |   | 189,764 |   |   |   | 364,704 |   |
| Total long-term liabilities                                                                      |   |                                   | 134,449  |   |   |   | 96,225 |   |   |   | 208,224 |   |
| Gross margin (2)                                                                                 |   |                                   | 100,817  |   |   |   | 86,496 |   |   |   | 26,956 |   |
| Cash flows (used in)/provided by operating activities  (3)                                  |   |                                   | (13,561  | ) |   |   | 44,500 |   |   |   | 15,586 |   |

| (1) | Earnings before interest, taxes, depreciation and amortization, or EBITDA, is a non-GAAP measure and is reconciled to Canadian GAAP in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
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| (2) | Gross Margin is a non-GAAP measure and is “sales and operating revenues” less ”cost of sales and operating expenses” and is reconciled to Canadian GAAP in the section to this document entitled ”Non-GAAP Measures and Reconciliation”. |
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| (3) | Refer to “Liquidity and Capital Resources – Summary of Cash Flows” for detailed cash flow analysis. |
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|   | - | Loss on extinguishment of IPI liability of $30.6 million: During 2010 we bought back 1.45% interest in the IPI agreement for which a total of 754,788 common shares valued at $50.7 million were issued.  We have adopted the extinguishment of liability model for accounting for the buyback of 1.4% of this interest with the difference between fair value and book value of the IPI liability for this interest being expensed, amounting to an $30.6 million expense for the year.  For the remaining 0.05% interest, the investor had already waived their conversion right in 2009.  This meant that conveyance accounting was followed and the premium paid to the investor on buyback was capitalized to oil and gas properties.  The buyback was a non-cash transaction, the loss on extinguishment did not impact our netcash balance. |
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|   | - | Settlement of litigation for $12.0 million – Todd Peters et al v. Phil Mulacek et. al:  In August 2010, we entered into an agreement with the Plaintiffs to settle and release all claims against us and our subsidiaries.  Pursuant to the settlement, which was approved by the trial court in September 2010,  we issued 199,677 common shares to the Plaintiffs in October 2010, valued at $12.0 million based on a volume weighted average price calculated over the ten trading days prior to execution of the settlement agreement.  The settlement was a non-cash transaction, the expense did not impact our net cash balance. |
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|   | - | Seismic activity and standby costs expensed for $17.0 million – Seismic costs incurred on the programs over the Bwata and Wolverine structures during the year amounted to $8.7 million.  These costs have been expensed as incurred under successful efforts accounting.  In addition, during the last quarter of 2010 no drilling activity was conducted while we evaluated the seismic results and drilling equipment underwent maintenance.  Our drilling and associated equipment/service crews were on standby during this period.  All costs in relation to the maintenance and standby time have been expensed for the year. |
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|   |   | YearlyVariance($ millions) |   |   | QuarterlyVariance($ millions) |   |   |
|--------|--------|---------------------------------|--------|--------|------------------------------------|--------|--------|
|   |   |                            |   |   |                               |   |   |   |   |
|   |   | $                               | (51.6  | )      |                               | $      | (55.1  | ) | Net profit/(loss) variance for the comparative periods primarily due to: |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | 14.3   |   |                               | $      | 10.5   |   | Increase in gross margins mainly due to higher yielding crude cargos and higher export premiums for our refining segment.  Downstream margins also increased on increased domestic consumption due to construction activity on the Exxon Mobil LNG project, the increasing price environment leading to higher margins on inventories sold, and in small part due to upward revision of wholesale prices based on the pricing review completed and published by the ICCC in November 2010. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (7.8   | )      |                               | $      | (3.7   | ) | Higher office and administration and other expenses, mainly resulting from higher salaries and wages expenses due to the strengthening of the AUD against the USD and higher maintenance costs on our rig during the standby in fourth quarter. The increase is also due to higher stock compensation expense and higher consulting costs in relation to the transactions to underpin the development of our Elk Antelope fields, the CS Project and the LNG Project. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (16.8  | )      |                               | $      | (13.6  | ) | Higher exploration costs during current periods for seismic activity over the Bwata field and the Wolverine prospect which were expensed as incurred, and crew and drilling services stand by charges expensed in the fourth quarter of 2010. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | 1.1    |   |                               | $      | (18.6  | ) | Lower loss on extinguishment of IPI liability for the year in relation to the interest buyback of 1.4% interest in 2010, 1.0% of which was purchased in the fourth quarter, compared with 4.3364% interest bought back in 2009.  However, the premiums paid on buybacks in 2010 were higher than similar transactions in 2009. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (12.0  | )      |                               | $      | 0.0    |   | Litigation settlement expense on account of the agreed settlement of the Todd Peters v. Phil Mulacek et al litigation for which we issued 199,677 common shares to the Plaintiffs valued at $12.0 million. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (7.5   | )      |                               | $      | (3.4   | ) | Foreign exchange movements of PGK against the USD, and lower PGK rates being charged by financial institutions on conversion of the PGK sales revenue into USD for repayment of our crude purchase working capital facility. The rates fluctuate significantly based on the extent to which other PNG participants are looking to convert their foreign currencies.  We are unable to undertake PGK currency hedging due to the relatively small size of the PGK foreign exchange market. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | 2.6    |   |                               | $      | (1.1   | ) | Lower interest expense for the year primarily due to the mandatory conversion in June 2009 of the remaining portion of the 8% convertible debentures. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (5.2   | )      |                               | $      | (6.3   | ) | Lower gain on sale of exploration assets due to a $2.1 million gain on the sale of PPL 244 in the fourth quarter of 2010 compared to a $7.4 million gain in 2009 due to the waiver by IPI holders of a 6.210% interest of their rights to convert their interest into common shares in the IPI agreement. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (18.5  | )      |                               | $      | (16.7  | ) | Increase in income tax expense during 2010 due to the initial recognition of a $14.3 million future income tax benefit in December 2009 for Midstream Refining. |

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| Quarters ended                        |   |   |     |   |   |   |
|---------------------------------------|--------|--------|----------|--------|--------|--------|
| ($ thousands except per share         |   | 2010   |     |   | 2009   |   |
|  data)                           |   | Dec-31 |     |   | Sep-30 |   |   | Jun-30 |   |   | Mar-31 |   |   | Dec-31 |   |   | Sep-30 |   |   | Jun-30 |   |   | Mar-31 |   |
| Upstream                              |   |   | 245      |   |   |   | 714 |   |   |   | 1,349 |   |   |   | 998 |   |   |   | 1,027 |   |   |   | 1,011 |   |   |   | 660 |   |   |   | 611 |   |
| Midstream – Refining            |   |   | 158,092  |   |   |   | 173,379 |   |   |   | 194,016 |   |   |   | 152,093 |   |   |   | 173,438 |   |   |   | 141,295 |   |   |   | 114,347 |   |   |   | 145,523 |   |
| Midstream – Liquefaction        |   |   | 0        |   |   |   | 0 |   |   |   | 0 |   |   |   | 0 |   |   |   | 0 |   |   |   | 1 |   |   |   | 2 |   |   |   | 4 |   |
| Downstream                            |   |   | 143,364  |   |   |   | 133,508 |   |   |   | 119,300 |   |   |   | 109,687 |   |   |   | 118,270 |   |   |   | 107,712 |   |   |   | 85,472 |   |   |   | 78,572 |   |
| Corporate                             |   |   | 15,213   |   |   |   | 18,295 |   |   |   | 11,321 |   |   |   | 12,093 |   |   |   | 10,539 |   |   |   | 10,087 |   |   |   | 8,640 |   |   |   | 7,753 |   |
| Consolidation entries                 |   |   | (122,545 | )      |   |   | (117,437 | ) |   |   | (100,637 | ) |   |   | (96,052 | ) |   |   | (93,971 | ) |   |   | (86,509 | ) |   |   | (60,625 | ) |   |   | (70,801 | ) |
| Total revenues                        |   |   | 194,369  |   |   |   | 208,459 |   |   |   | 225,349 |   |   |   | 178,819 |   |   |   | 209,303 |   |   |   | 173,597 |   |   |   | 148,496 |   |   |   | 161,662 |   |
| Upstream                              |   |   | (41,681  | )      |   |   | (11,753 | ) |   |   | (3,498 | ) |   |   | (1,964 | ) |   |   | 574 |   |   |   | (29,097 | ) |   |   | (669 | ) |   |   | (469 | ) |
| Midstream – Refining            |   |   | 13,780   |   |   |   | 15,785 |   |   |   | 16,962 |   |   |   | 4,402 |   |   |   | 8,492 |   |   |   | 8,199 |   |   |   | 14,134 |   |   |   | 14,747 |   |
| Midstream – Liquefaction        |   |   | (1,959   | )      |   |   | (4,588 | ) |   |   | (3 | ) |   |   | (563 | ) |   |   | (1,200 | ) |   |   | (2,119 | ) |   |   | (1,379 | ) |   |   | (2,361 | ) |
| Downstream                            |   |   | 4,709    |   |   |   | 1,674 |   |   |   | 7,060 |   |   |   | 4,492 |   |   |   | 4,391 |   |   |   | 6,542 |   |   |   | 4,150 |   |   |   | 3,241 |   |
| Corporate                             |   |   | 4,566    |   |   |   | (4,510 | ) |   |   | 1,751 |   |   |   | 4,402 |   |   |   | 1,765 |   |   |   | 1,980 |   |   |   | 1,897 |   |   |   | 3,051 |   |
| Consolidation entries                 |   |   | (7,005   | )      |   |   | (5,229 | ) |   |   | (7,384 | ) |   |   | (5,910 | ) |   |   | (4,884 | ) |   |   | (4,092 | ) |   |   | (278 | ) |   |   | (7,285 | ) |
| EBITDA (1)                            |   |   | (27,590  | )      |   |   | (8,621 | ) |   |   | 14,888 |   |   |   | 4,859 |   |   |   | 9,138 |   |   |   | (18,587 | ) |   |   | 17,855 |   |   |   | 10,924 |   |
| Upstream                              |   |   | (47,845  | )      |   |   | (16,585 | ) |   |   | (7,943 | ) |   |   | (6,182 | ) |   |   | (3,626 | ) |   |   | (31,392 | ) |   |   | (2,382 | ) |   |   | (2,133 | ) |
| Midstream – Refining            |   |   | 8,531    |   |   |   | 11,998 |   |   |   | 12,056 |   |   |   | (74 | ) |   |   | 18,070 |   |   |   | 3,762 |   |   |   | 9,624 |   |   |   | 10,350 |   |
| Midstream – Liquefaction        |   |   | (2,114   | )      |   |   | (4,970 | ) |   |   | (360 | ) |   |   | (911 | ) |   |   | (1,591 | ) |   |   | (2,481 | ) |   |   | (1,765 | ) |   |   | (2,552 | ) |
| Downstream                            |   |   | 2,642    |   |   |   | (325 | ) |   |   | 3,719 |   |   |   | 671 |   |   |   | 2,371 |   |   |   | 3,440 |   |   |   | 1,742 |   |   |   | 964 |   |
| Corporate                             |   |   | 3,381    |   |   |   | (5,398 | ) |   |   | 1,796 |   |   |   | 3,544 |   |   |   | 3,036 |   |   |   | 1,602 |   |   |   | (677 | ) |   |   | 349 |   |
| Consolidation entries                 |   |   | (403     | )      |   |   | 908 |   |   |   | (1,438 | ) |   |   | (191 | ) |   |   | 1,047 |   |   |   | (237 | ) |   |   | 2,894 |   |   |   | (4,332 | ) |
| Net (loss)/profit                     |   |   | (35,808  | )      |   |   | (14,372 | ) |   |   | 7,830 |   |   |   | (3,143 | ) |   |   | 19,307 |   |   |   | (25,306 | ) |   |   | 9,436 |   |   |   | 2,646 |   |
| Net (loss)/profit per share (dollars) |   |   |     |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Per Share – Basic               |   |   | (0.78    | )      |   |   | (0.33 | ) |   |   | 0.18 |   |   |   | (0.07 | ) |   |   | 0.45 |   |   |   | (0.60 | ) |   |   | 0.25 |   |   |   | 0.07 |   |
| Per Share – Diluted             |   |   | (0.78    | )      |   |   | (0.33 | ) |   |   | 0.17 |   |   |   | (0.07 | ) |   |   | 0.43 |   |   |   | (0.60 | ) |   |   | 0.24 |   |   |   | 0.07 |   |

| (1) | EBITDA is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------|

----

----

----

| Upstream – Operating results     |   | Year ended December 31, |    |
|-------------------------------------------------------|--------|----------------------------------------|---------|
| ($ thousands)                                    |   | 2010                                   |    |   | 2009 |   |
| Other non-allocated revenue                           |   |                                   | 3,305   |   |   |   | 3,309 |   |
| Total revenue                                         |   |                                   | 3,305   |   |   |   | 3,309 |   |
| Office and administration and other expenses          |   |                                   | (13,746 | ) |   |   | (7,111 | ) |
| Exploration costs                                     |   |                                   | (16,982 | ) |   |   | (209 | ) |
| Gain on sale of oil and gas properties                |   |                                   | 2,141   |   |   |   | 7,364 |   |
| Loss on extinguishment of IPI liability               |   |                                   | (30,569 | ) |   |   | (31,710 | ) |
| Foreign exchange loss                                 |   |                                   | (3,044  | ) |   |   | (1,304 | ) |
| EBITDA (1)                                            |   |                                   | (58,895 | ) |   |   | (29,661 | ) |
| Depreciation and amortization                         |   |                                   | (1,132  | ) |   |   | (538 | ) |
| Interest expense                                      |   |                                   | (18,528 | ) |   |   | (9,335 | ) |
| Loss before income taxes and non-controlling interest |   |                                   | (78,555 | ) |   |   | (39,534 | ) |
| Income tax expense                                    |   |                                   | -       |   |   |   | - |   |
| Net loss                                              |   |                                   | (78,555 | ) |   |   | (39,534 | ) |

| (1) | EBITDA is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------|

|   |   | YearlyVariance($ millions) |   |   | QuarterlyVariance($ millions) |   |   |
|--------|--------|---------------------------------|--------|--------|------------------------------------|--------|--------|
|   |   |                            |   |   |                               |   |   |   |   |
|   |   | $                               | (39.0  | )      |                               | $      | (44.2  | ) | Net profit/(loss) variance for the comparative periods primarily due to: |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (16.8  | )      |                               | $      | (13.6  | ) | Higher exploration costs during current period for seismic activity over the Bwata field and the Wolverine prospect, and the preparations for the seismic program over PPL 236 which commenced towards the end of the year.  These seismic costs are expensed as incurred under the successful efforts method of accounting.  In addition to seismic costs, current period expenses also included the expensing of drilling crew and associated equipment/services standby costs for the fourth quarter of 2010 when no drilling activity was undertaken pending evaluation of the results of our seismic programs completed during the year. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (6.6   | )      |                               | $      | (2.2   | ) | Increase in office and administration and other expenses mainly due to higher drilling rig maintenance expenses during the standby period in the fourth quarter of 2010, and higher consulting costs in relation to the transactions that are intended to underpin the development of our Elk Antelope condensate stripping and LNG facilities. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | 1.1    |   |                               | $      | (18.6  | ) | Lower loss on extinguishment of IPI liability for the year in relation to the interest buyback of a 1.4% interest in 2010, 1.0% of which occurred in the fourth quarter, compared with 4.3364% interest bought back in 2009.  However, the premiums paid on buybacks in 2010 were higher than similar transactions in 2009. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (5.2   | )      |                               | $      | (6.3   | ) | Lower gain on sale of exploration assets due to $2.1 million gain on sale of PPL 244 in 2010 compared to $7.4 million gain in 2009 due to the waiver of common share conversion rights by holders of a 6.210% IPI interest. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (9.2   | )      |                               | $      | (1.4   | ) | Higher interest expense due to an increase in inter-company loan balances provided to fund exploration and development activities during the year. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (1.7   | )      |                               | $      | (0.7   | ) | Increase in foreign exchange loss due to the increased Papua New Guinea denominated expenses in our operations requiring conversion of higher USD amounts into PGK.  PGK has fluctuated significantly against the USD during the year. |

----

----

| Midstream Refining – Operating results |   | Year ended December 31, |     |
|------------------------------------------------------------------|--------|----------------------------------------|----------|
| ($ thousands)                                               |   | 2010                                   |     |   | 2009 |   |
| External sales                                                   |   |                                   | 298,071  |   |   |   | 299,673 |   |
| Inter-segment revenue                                            |   |                                   | 379,344  |   |   |   | 274,736 |   |
| Interest and other revenue                                       |   |                                   | 166      |   |   |   | 194 |   |
| Total segment revenue                                            |   |                                   | 677,581  |   |   |   | 574,603 |   |
| Cost of sales and operating expenses                             |   |                                   | (605,603 | ) |   |   | (516,349 | ) |
| Office and administration and other expenses                     |   |                                   | (11,939  | ) |   |   | (9,901 | ) |
| Derivative (loss)/gain                                           |   |                                   | (1,592   | ) |   |   | 1,009 |   |
| Foreign exchange loss                                            |   |                                   | (7,518   | ) |   |   | (3,790 | ) |
| EBITDA (1)                                                       |   |                                   | 50,929   |   |   |   | 45,572 |   |
| Depreciation and amortization                                    |   |                                   | (10,355  | ) |   |   | (10,932 | ) |
| Interest expense                                                 |   |                                   | (6,585   | ) |   |   | (7,150 | ) |
| Profit before income taxes and non-controlling interest          |   |                                   | 33,989   |   |   |   | 27,490 |   |
| Income tax (expense)/benefit                                     |   |                                   | (1,478   | ) |   |   | 14,316 |   |
| Non-controlling interest                                         |   |                                   | -        |   |   |   | - |   |
| Net profit                                                       |   |                                   | 32,511   |   |   |   | 41,806 |   |
|                                                             |   |                                   |     |   |   |   |   |   |
| Gross Margin (2)                                                 |   |                                   | 71,812   |   |   |   | 58,060 |   |

|   | (1) | EBITDA is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
|--------|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------|

|   | (2) | Gross Margin is a non-GAAP measure and is external sales and inter-segment revenue less cost of sales and operating expenses and is reconciled to Canadian GAAP in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
|--------|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

----

----

|                                                                      |   | Quarter ended December 31, |   |   | Year ended December 31, |   |
|---------------------------------------------------------------------------|--------|-------------------------------------------|--------|--------|----------------------------------------|--------|
| Key Refining Metrics                                            |   | 2010                                      |   |   | 2009                                   |   |   | 2010 |   |   | 2009 |   |
| Throughput (barrels per day)(1)                                           |   |                                      | 21,550 |   |                                   |   | 20,966 |   |   |   | 24,682 |   |   |   | 21,155 |   |
| Capacity utilization (based on 36,500 barrels per day operating capacity) |   |                                      | 34     | %      |                                   |   | 44 | % |   |   | 53 | % |   |   | 47 | % |
| Cost of production per barrel(2)                                          |   | $                                         | 4.35   |   |                                   | $      | 2.92 |   |   | $ | 3.78 |   |   | $ | 3.18 |   |
| Working capital financing cost per barrel of production(2)                |   | $                                         | 0.58   |   |                                   | $      | 0.49 |   |   | $ | 0.47 |   |   | $ | 0.40 |   |
| Distillates as percentage of production                                   |   |                                      | 58.70  | %      |                                   |   | 61.00 | % |   |   | 51.00 | % |   |   | 58.63 | % |

| (1) | Throughput per day has been calculated excluding shut down days.  During 2010 and 2009, the refinery was shut down for 81 days and 80 days, respectively. |
|-----|---------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| (2) | Our cost of production per barrel and working capital financing cost per barrel have been calculated based on a notional throughput.  Our actual throughput has been adjusted to include the throughput that would have been necessary to produce the equivalent amount of finished product that we imported during the year. |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

|   |   | YearlyVariance($ millions) |   |   | QuarterlyVariance($ millions) |   |   |
|--------|--------|---------------------------------|--------|--------|------------------------------------|--------|--------|
|   |   |                            |   |   |                               |   |   |   |   |
|   |   | $                               | (9.3   | )      |                               | $      | (9.5   | ) | Net profit/(loss) variance for the comparative periods primarily due to: |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | 13.8   |   |                               | $      | 11.0   |   | Change in gross margin was due to the following contributing factors:+   Steady increase in crude prices with comparatively lower volatility.+   Improved LSWR and naphtha crack spreads and premiums over     those from 2009.-   Hedge gains realized on close out of long term hedges in early 2009,    compared with no hedge accounted contracts in the current period.-   Refinery shutdown for month of October for turnaround    maintenance program. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (2.0   | )      |                               | $      | (1.3   | ) | Increase in office and administration costs was driven by an increase in staff salary expenses, mainly due to higher stock compensation expenses and a one-off catch-up payment of airfares tax since 2007 for refinery employees.  This payment was made after rejection of  our application made to the Internal Revenue Commission in Papua New Guinea for exemption from this tax. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (3.7   | )      |                               | $      | (3.3   | ) | Increase in foreign exchange loss due to movements of PGK against the USD, and PGK rates being charged by financial institutions on conversion of the PGK sales revenue into USD for repayment of working capital facility. The exchange rates fluctuate significantly based on the extent to which other PNG participants are looking to convert their foreign currencies.  We are unable to do any currency hedging due to the relatively small size of the PGK foreign exchange market. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (2.6   | )      |                               | $      | (1.1   | ) | Movement in gains/(losses) from derivative contracts undertaken as part of our risk management strategy that were not accounted for as hedge accounted contracts. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | 0.6    |   |                               | $      | 0.5    |   | Reduction in interest expense due to capital repayments of the OPIC loan, and lower intercompany loan balances on higher profits being generated by the refinery operations. |
|   |   |                            |   |   |                               |   |   |   |   |
| Ø |   | $                               | (15.8  | )      |                               | $      | (15.4  | ) | Increase in income tax expense for the current year and quarter were driven by the initial recognition of a $14.3 million future income tax benefit in December 2009 relating to carried forward tax losses and temporary differences, compared with a $1.5 million future income tax expense during 2010 which was mainly the movement in temporary differences associated with depreciation of property, plant and equipment. |

----

----

----

| Midstream Liquefaction – Operating results |   | Year ended December 31, |   |
|----------------------------------------------------------------------|--------|----------------------------------------|--------|
| ($ thousands)                                                   |   | 2010                                   |   |   | 2009 |   |
| Interest and other revenue                                           |   |                                   | 1      |   |   |   | 8 |   |
| Total segment revenue                                                |   |                                   | 1      |   |   |   | 8 |   |
| Office and administration and other expenses                         |   |                                   | (7,023 | ) |   |   | (7,108 | ) |
| Foreign exchange (loss)/gain                                         |   |                                   | (90    | ) |   |   | 41 |   |
| EBITDA (1)                                                           |   |                                   | (7,112 | ) |   |   | (7,059 | ) |
| Depreciation and amortization                                        |   |                                   | (25    | ) |   |   | (57 | ) |
| Interest expense                                                     |   |                                   | (1,253 | ) |   |   | (1,218 | ) |
| Loss before income taxes and non-controlling interest                |   |                                   | (8,390 | ) |   |   | (8,334 | ) |
| Income tax benefit/(expense)                                         |   |                                   | 36     |   |   |   | (55 | ) |
| Net loss                                                             |   |                                   | (8,354 | ) |   |   | (8,389 | ) |

| (1) | EBITDA is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------|

----

----

|   |   | YearlyVariance($ millions) |   |   | QuarterlyVariance($ millions) |   |   |
|--------|--------|----------------------------|--------|--------|-------------------------------|--------|--------|
|   |   |                       |   |   |                          |   |   |   |   |
|   |   | $                          | 0.0    |   |                          | $      | (0.5   | ) | Net profit/(loss) variance for the comparative periods primarily due to: |
|   |   |                       |   |   |                          |   |   |   |   |
| Ø |   | $                          | 0.1    |   |                          | $      | (0.7   | ) | Reduction in office, administration and other expenses for the year due to capitalization of direct expenses relating to the LNG Project since executing the LNG Project Agreement in December 2009.  The prior period balances also included loss on the proportionate consolidation of PNG LNG subsequent to the acquisition of Merrill Lynch’s interest in that company in early 2009.  These decreased expenses were offset by higher management expenses and share compensation costs related to the LNG Project development which are not capitalized. |

| Downstream – Operating results                    |   | Year ended December 31, |     |
|---------------------------------------------------------|--------|-------------------------|----------|
| ($ thousands)                                           |   | 2010                    |     |   | 2009 |   |
| External sales                                          |   |                    | 504,304  |   |   |   | 388,806 |   |
| Inter-segment revenue                                   |   |                    | 483      |   |   |   | 185 |   |
| Interest and other revenue                              |   |                    | 1,072    |   |   |   | 1,035 |   |
| Total segment revenue                                   |   |                    | 505,859  |   |   |   | 390,026 |   |
| Cost of sales and operating expenses                    |   |                    | (470,772 | ) |   |   | (359,623 | ) |
| Office and administration and other expenses            |   |                    | (15,976  | ) |   |   | (12,911 | ) |
| Foreign exchange (loss)/gain                            |   |                    | (1,176   | ) |   |   | 832 |   |
| EBITDA (1)                                              |   |                    | 17,935   |   |   |   | 18,324 |   |
| Depreciation and amortization                           |   |                    | (2,787   | ) |   |   | (2,650 | ) |
| Interest expense                                        |   |                    | (3,739   | ) |   |   | (4,130 | ) |
| Profit before income taxes and non-controlling interest |   |                    | 11,409   |   |   |   | 11,544 |   |
| Income tax expense                                      |   |                    | (4,701   | ) |   |   | (3,027 | ) |
| Net profit                                              |   |                    | 6,708    |   |   |   | 8,517 |   |
|                                                    |   |                    |     |   |   |   |   |   |
| Gross Margin (2)                                        |   |                    | 34,015   |   |   |   | 29,368 |   |

| (1) | EBITDA is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------|

| (2) | Gross Margin is a non-GAAP measure and is “external sales” and “inter-segment revenue” less “cost of sales and operating expenses” and is reconciled to Canadian GAAP in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

----

----

|                               |   | Quarter ended December 31, |   |   | Year ended December 31, |   |
|------------------------------------|--------|----------------------------|--------|--------|-------------------------|--------|
| Key Downstream Metrics             |   | 2010                       |   |   | 2009                    |   |   | 2010 |   |   | 2009 |   |
| Sales volumes (millions of liters) |   |                       | 170.2  |   |                    |   | 159.1 |   |   |   | 626.5 |   |   |   | 588.8 |   |

|   |   | YearlyVariance($ millions) |   |   | QuarterlyVariance($ millions) |   |   |
|--------|--------|----------------------------|--------|--------|-------------------------------|--------|--------|
|   |   |                       |   |   |                          |   |   |   |   |
|   |   | $                          | (1.8   | )      |                          | $      | 0.3    |   | Net profit/(loss) variance for the comparative periods primarily due to: |
|   |   |                       |   |   |                          |   |   |   |   |
| Ø |   | $                          | 4.6    |   |                          | $      | 2.5    |   | Increase in gross margin mainly driven by a 6.4% increase in volumes compared to prior year on the back of increased sales relating to the Exxon Mobil LNG project, the increasing price environment leading to higher margins on inventories sold, and in small part, an revision of wholesale prices based on the pricing review completed and published by the ICCC in November 2010.    |
|   |   |                       |   |   |                          |   |   |   |   |
| Ø |   | $                          | (1.7   | )      |                          | $      | (0.1   | ) | Increase in income tax expense due to under-provision of deferred tax expense in the prior year. |
|   |   |                       |   |   |                          |   |   |   |   |
| Ø |   | $                          | (3.1   | )      |                          | $      | (2.1   | ) | Increase in office and administration and other expenses mainly relating to higher staff salary costs, higher recharges from Corporate, and higher lease and utility costs on relocation to new office premises in Papua New Guinea. |
|   |   |                       |   |   |                          |   |   |   |   |
| Ø |   | $                          | (2.0   | )      |                          | $      | (0.2   | ) | Foreign exchange movements during the periods due to the currency fluctuations between PGK and the USD. |

----

----

| Corporate – Operating results      |   | Year ended December 31, |    |
|---------------------------------------------------------|--------|----------------------------------------|---------|
| ($ thousands)                                      |   | 2010                                   |    |   | 2009 |   |
| Inter-segment revenue                                   |   |                                   | 32,564  |   |   |   | 21,194 |   |
| Interest revenue                                        |   |                                   | 24,335  |   |   |   | 15,825 |   |
| Other non-allocated revenue                             |   |                                   | 23      |   |   |   | - |   |
| Total revenue                                           |   |                                   | 56,922  |   |   |   | 37,019 |   |
| Office and administration and other expenses            |   |                                   | (40,291 | ) |   |   | (29,241 | ) |
| Derivative gain                                         |   |                                   | 527     |   |   |   | - |   |
| Foreign exchange gain                                   |   |                                   | 1,051   |   |   |   | 915 |   |
| Litigation settlement expense                           |   |                                   | (12,000 | ) |   |   | - |   |
| EBITDA (1)                                              |   |                                   | 6,209   |   |   |   | 8,693 |   |
| Depreciation and amortization                           |   |                                   | (106    | ) |   |   | (275 | ) |
| Interest expense                                        |   |                                   | (1,541  | ) |   |   | (3,952 | ) |
| Profit before income taxes and non-controlling interest |   |                                   | 4,562   |   |   |   | 4,466 |   |
| Income tax expense                                      |   |                                   | (1,240  | ) |   |   | (158 | ) |
| Net profit                                              |   |                                   | 3,322   |   |   |   | 4,308 |   |

| (1) | EBITDA is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------|

|   |   | YearlyVariance($ millions) |   |   | QuarterlyVariance($ millions) |   |   |
|--------|--------|----------------------------|--------|--------|-------------------------------|--------|--------|
|   |   |                       |   |   |                          |   |   |   |   |
|   |   | $                          | (1.0   | )      |                          | $      | 0.3    |   | Net profit/(loss) variance for the comparative periods primarily due to: |
|   |   |                       |   |   |                          |   |   |   |   |
| Ø |   | $                          | (12.0  | )      |                          | $      | 0.0    |   | Litigation settlement expense on account of the agreed settlement of the Todd Peters v. Phil Mulacek et al litigation for which we issued 199,677 common shares to the plaintiffs valued at $12.0 million. |
|   |   |                       |   |   |                          |   |   |   |   |
| Ø |   | $                          | 11.0   |   |                          | $      | (0.4   | ) | Reduced interest expenses (net of recharged intercompany interest revenue from other segments) due to conversion in June 2009 of the remaining portion of the 8.0% debentures issued in May 2008, and higher interest charges to other business segments on increased loan balances. |
|   |   |                       |   |   |                          |   |   |   |   |
| Ø |   | $                          | 0.3    |   |                          | $      | 1.0    |   | Decrease in net office and administration and other expenses for the year after recharges to other streams (included in inter-segment revenue). Higher office and administration and other expenses, mainly resulting from higher salaries and wages expenses due to a strengthening of the AUD against the USD compared with the prior periods. |

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| Consolidation adjustments – Operating results |   | Year ended December 31, |     |
|-------------------------------------------------------------------------|--------|----------------------------------------|----------|
| ($ thousands)                                                      |   | 2010                                   |     |   | 2009 |   |
| Inter-segment revenue (1)                                               |   |                                   | (412,392 | ) |   |   | (296,115 | ) |
| Interest revenue (5)                                                    |   |                                   | (24,281  | ) |   |   | (15,792 | ) |
| Total revenue                                                           |   |                                   | (436,673 | ) |   |   | (311,907 | ) |
| Cost of sales and operating expenses (1)                                |   |                                   | 374,818  |   |   |   | 273,989 |   |
| Office and administration and other expenses (2)                        |   |                                   | 36,325   |   |   |   | 21,379 |   |
| EBITDA (3)                                                              |   |                                   | (25,530  | ) |   |   | (16,539 | ) |
| Depreciation and amortization (4)                                       |   |                                   | 130      |   |   |   | 130 |   |
| Interest expense (5)                                                    |   |                                   | 24,282   |   |   |   | 15,792 |   |
| Loss before income taxes and non-controlling interest                   |   |                                   | (1,118   | ) |   |   | (617 | ) |
| Non-controlling interest                                                |   |                                   | (7       | ) |   |   | (8 | ) |
| Net loss                                                                |   |                                   | (1,125   | ) |   |   | (625 | ) |
|                                                                    |   |                                   |     |   |   |   |   |   |
| Gross Margin (6)                                                        |   |                                   | (37,574  | ) |   |   | (22,126 | ) |

| (1) | Represents the elimination upon consolidation of our refinery sales to other segments and other minor inter-company product sales. |
|-----|------------------------------------------------------------------------------------------------------------------------------------|

| (2) | Includes the elimination of inter-segment administration service fees. |
|-----|------------------------------------------------------------------------|

| (3) | EBITDA is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------|

| (4) | Represents the amortization of a portion of costs capitalized to assets on consolidation. |
|-----|-------------------------------------------------------------------------------------------|

| (5) | Includes the elimination of interest accrued between segments. |
|-----|----------------------------------------------------------------|

| (6) | Gross Margin is a non-GAAP measure and is “inter-segment revenue elimination” less “cost of sales and operating expenses” and represents elimination upon consolidation of our refinery sales to other segments.  This measure is reconciled to Canadian GAAP in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
|-----|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

|   |   | YearlyVariance($ millions) |   |   | QuarterlyVariance($ millions) |   |   |
|--------|--------|----------------------------|--------|--------|-------------------------------|--------|--------|
|   |   |                       |   |   |                          |   |   |   |   |
|   |   | $                          | (0.5   | )      |                          | $      | (1.5   | ) | Net profit/(loss) variance for the comparative periods primarily due to: |
|   |   |                       |   |   |                          |   |   |   |   |
| Ø |   | $                          | (0.5   | )      |                          | $      | (1.5   | ) | Decrease in net income due to changes in intra-group profit eliminated on consolidation between Midstream Refining and Downstream segments in the prior periods relating to the Midstream Refining segment’s profit component of inventory on hand in the Downstream segment at period ends. |

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| Organization                         |   | Facility |        |   | Balanceoutstanding December 31,2010 |   |       | Effectiveinterestrate |   | Maturity date |
|--------------------------------------|--------|----------|-------------|--------|-----------------------------------------------|--------|------------|-----------------------|--------|--------------------|
| OPIC secured loan                    |   | $        | 44,500,000  |   |                                          | $      | 44,500,000 |                  |   |               | 6.80 | % | December 2015 |
| BNP Paribas working capital facility |   | $        | 190,000,000 | (2)    |                                          | $      | 50,023,559 | (1)                   |   |               | 2.69 | % | Subsequent toyear end, this wasrenewed untilJanuary 31, 2012 |
| Westpac PGK working capital facility |   | $        | 30,280,000  |   |                                          | $      | 1,230,767  |                  |   |               | 9.50 | % | October 2011 |
| BSP PGK working capital facility     |   | $        | 18,925,000  |   |                                          | $      | 0          |                  |   |               | 9.20 | % | October 2011 |
| 2.75% convertible notes              |   | $        | 70,000,000  |   |                                          | $      | 70,000,000 |                  |   |               | 7.91 | %(4) | November 2015 |
| Mitsui unsecured loan (3)            |   | $        | 5,456,757   |   |                                          | $      | 5,456,757  |                  |   |               | 6.26 | % | See detail below |

|   | (1) | Excludes letters of credit totaling $93.7 million, which reduce the available balance of the facility to $46.3 million at December 31, 2010. |
|--------|-----|----------------------------------------------------------------------------------------------------------------------------------------------|

|   | (2) | Subsequent to the year end, the facility has been increased by $30.0 million for a total facility of $220.0 million. |
|--------|-----|----------------------------------------------------------------------------------------------------------------------|

|   | (3) | Facility is to fund our share of the CS Project costs as they are incurred pursuant to the JVOA. |
|--------|-----|--------------------------------------------------------------------------------------------------|

|   | (4) | Effective rate after bifurcating the equity and debt components of the convertible note offering. |
|--------|-----|---------------------------------------------------------------------------------------------------|

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|                              |   | Year ended December 31, |     |
|-----------------------------------|--------|-------------------------|----------|
| ($ thousands)                     |   | 2010                    |     |   | 2009 |   |   | 2008 |   |
| Net cash inflows/(outflows) from: |   |                    |     |   |   |   |   |   |   |
| Operations                        |   |                    | (13,561  | ) |   |   | 44,500 |   |   |   | 15,586 |   |
| Investing                         |   |                    | (111,158 | ) |   |   | (85,567 | ) |   |   | (47,390 | ) |
| Financing                         |   |                    | 311,846  |   |   |   | 38,546 |   |   |   | 36,913 |   |
| Net cash movement                 |   |                    | 187,127  |   |   |   | (2,521 | ) |   |   | 5,109 |   |
| Opening cash                      |   |                    | 46,450   |   |   |   | 48,971 |   |   |   | 43,862 |   |
| Closing cash                      |   |                    | 233,577  |   |   |   | 46,450 |   |   |   | 48,971 |   |

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|   |   | Yearlyvariance($ millions) |   |   |
|--------|--------|----------------------------|--------|--------|
|   |   |                       |   |   |   |
|   |   | $                          | (58.1  | )      | Variance for the comparative periods primarily due to: |
|   |   |                       |   |   |   |
| Ø |   | $                          | (15.1  | )      | Increase in cash used by operations prior to changes in operating working capital mainly due to the timing difference between the recognition and settlement of long term hedges that were settled in early 2009. |
|   |   |                       |   |   |   |
| Ø |   | $                          | (43.0  | )      | Increase in cash used by operations due primarily to a $68.3 million increase in inventories due to timing of crude and export shipments, offset by an increase in accounts payable. |

|   |   | Yearlyvariance($ millions) |   |   |
|--------|--------|----------------------------|--------|--------|
|   |   |                       |   |   |   |
|   |   | $                          | (25.6  | )      | Variance for the comparative periods primarily due to: |
|   |   |                       |   |   |   |
| Ø |   | $                          | (21.3  | )      | Higher cash outflows for the year to December 31, 2010 on exploration expenditures compared to the prior year.  The outflows related primarily to the Antelope 2 horizontal drilling, the development seismic program on the Antelope structure, seismic on the Bwata field and the Wolverine prospect, and progressing the CS Project. |
|   |   |                       |   |   |   |
| Ø |   | $                          | 8.3    |   | Higher cash calls and related inflows from IPI investors. |
|   |   |                       |   |   |   |
| Ø |   | $                          | (10.8  | )      | Higher expenditure on acquisition of plant and equipment.  2010 expenditure was mainly associated with capitalized LNG Project costs, ERP implementation, refurbishment of retail sites, tank upgrades and additional camp facilities at the refinery. |
|   |   |                       |   |   |   |
| Ø |   | $                          | 15.5   |   | Receipt in 2010 of the final installment of $13.9 million relating to the sale of 2.5% direct working interest in the Elk and Antelope fields to Pac LNG in September 2009 and $1.6 million proceeds from the sale of our interest in PPL 244. |
|   |   |                       |   |   |   |
| Ø |   | $                          | (14.9  | )      | Higher cash outflows due to movement in our secured cash restricted balances in line with the usage of the BNP working capital facility. |
|   |   |                       |   |   |   |
| Ø |   | $                          | (2.4   | )      | Increase in cash used in our Upstream development segment for working capital requirements.  This working capital relates to movements in accounts payable and accruals in our Upstream and Midstream Liquefaction operations. |

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|   |   | Yearlyvariance($ millions) |   |   |
|--------|--------|----------------------------|--------|--------|
|   |   |                       |   |   |   |
|   |   | $                          | 273.3  |   | Variance for the comparative periods primarily due to: |
|   |   |                       |   |   |   |
| Ø |   | $                          | 129.4  |   | Higher net proceeds from the issuance of 2,800,000 common shares in November 2010. |
|   |   |                       |   |   |   |
| Ø |   | $                          | 70.8   |   | Higher utilization of the BNP Paribas working capital facility consistent with the higher inventory holding balances at year end. |
|   |   |                       |   |   |   |
| Ø |   | $                          | 66.3   |   | Net proceeds after transaction costs from the issuance of $70.0 million of 2.75% convertible notes in November 2010. |
|   |   |                       |   |   |   |
| Ø |   | $                          | 11.9   |   | Funding from Mitsui relating to the CS Project. |
|   |   |                       |   |   |   |
| Ø |   | $                          | 0.9    |   | Net proceeds from the cash call made to Pac LNG for its share of costs incurred by PNG LNG and its subsidiaries during 2010. |
|   |   |                       |   |   |   |
| Ø |   | $                          | (3.6   | )      | Proceeds received from Pac LNG during the year ending December 30, 2009 relating to the acquisition of a direct 2.5% working interest in the Elk and Antelope fields. |
|   |   |                       |   |   |   |
| Ø |   | $                          | (1.4   | )      | Proceeds received from Petromin for contributions towards cash calls made with respect to development activities for the Elk and Antelope fields. |
|   |   |                       |   |   |   |
| Ø |   | $                          | (1.0   | )      | Net transaction costs relating to $25.0 million secured Clarion Finanz loan for which funds were received in August and repaid in November 2010. |

|   |   | Yearly($ millions) |   |   |
|--------|--------|--------------------|--------|--------|
|   |   |               |   |   |   |
|   |   | $                  | 113.1  |   | Expenditures in the year ended December 31, 2010 due to: |
|   |   |               |   |   |   |
| Ø |   | $                  | 61.2   |   | Drilling, testing and completion costs on the Antelope-2 well. |
|   |   |               |   |   |   |
| Ø |   | $                  | 4.5    |   | Conducting a development seismic program on the Antelope structure. |
|   |   |               |   |   |   |
| Ø |   | $                  | 8.7    |   | Conducting seismic activity in relation to the Bwata field and the Wolverine prospect. |
|   |   |               |   |   |   |
| Ø |   | $                  | 116.6  |   | Costs for early works in respect of the CS Project. |
|   |   |               |   |   |   |
| Ø |   | $                  | 2.3    |   | Site preparation costs for the Antelope-3 appraisal well. |
|   |   |               |   |   |   |
| Ø |   | $                  | 6.7    |   | Drilling crew and services stand by costs during fourth quarter of 2010. |
|   |   |               |   |   |   |
| Ø |   | $                  | 13.1   |   | Other expenditures, including purchase of a second rig and other fixed assets, and drilling consumable purchases. |

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|                                             |   | Payments Due by Period |    |
|--------------------------------------------------|--------|------------------------|---------|
|                                             |   |                   |    |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   | More |   |
| Contractual obligations                          |   |                   |    |   | Less than |   |   | 1 – 2 |   |   | 2 – 3 |   |   | 3 – 4 |   |   | 4 – 5 |   |   | than 5 |   |
| ($ thousands)                                    |   | Total                  |    |   | 1 year |   |   | years |   |   | years |   |   | years |   |   | years |   |   |  years |   |
| Secured and Unsecured loans (3)                  |   |                   | 49,957  |   |   |   | 14,457 |   |   |   | 9,000 |   |   |   | 9,000 |   |   |   | 9,000 |   |   |   | 8,500 |   |   |   | - |   |
| Convertible notes obligations                    |   |                   | 70,000  |   |   |   | - |   |   |   | - |   |   |   | - |   |   |   | - |   |   |   | 70,000 |   |   |   | - |   |
| Indirect participation interest (1)              |   |                   | 1,384   |   |   |   | 540 |   |   |   | 844 |   |   |   | - |   |   |   | - |   |   |   | - |   |   |   | - |   |
| Petroleum prospecting and retention licenses (2) |   |                   | 156,000 |   |   |   | 31,000 |   |   |   | 31,000 |   |   |   | 34,900 |   |   |   | 24,750 |   |   |   | 34,350 |   |   |   | - |   |
| Total                                            |   |                   | 277,341 |   |   |   | 45,997 |   |   |   | 40,844 |   |   |   | 43,900 |   |   |   | 33,750 |   |   |   | 112,850 |   |   |   | - |   |

| (1) | These amounts represent the estimated cost of completing our commitment to drill exploration wells under our indirect participation interest agreement entered into in July 2003 (Indirect Participation Interest - PNGDV).  See Note 21 to our financial statements for the year ended December 31, 2010. |
|-----|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| (2) | The amount pertaining to the petroleum prospecting and retention licenses represents the amount we have committed as a condition on renewal of these licenses.  We are committed to spend a further $83.0 million as a condition of renewal of our petroleum prospecting licenses up to 2014.  Of this $83.0 million commitment, as at December 31, 2010, management estimates that satisfying this license commitment would also satisfy our commitments to the IPI investors in relation to drilling the final four wells and satisfy the commitments in relation to the IPI agreement.  In addition, the terms of grant of PRL15, requires us to spend a further $73.0 million on the development of the Elk and Antelope fields by the end of 2014. |
|-----|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| (3) | This excludes the contractual interest payments on the principal amount. The effective interest rate on this loan for the year ended December 31, 2010 was 6.80%.  The annual effective interest rate will be applied to the outstanding balance for the contractual interest payment calculation. |
|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

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| - | Business Combinations: A first-time adopter may elect not to apply IFRS 3 - ‘Business Combinations’ (as revised in 2008) retrospectively to past business combinations (business combinations that occurred before the date of transition to IFRSs).  However, if a first-time adopter restates any business combination to comply with IFRS 3 (as revised in 2008), it shall restate all later business combinations and shall also apply IAS 27 (as amended in 2008) from that same date.  We have made the election not to apply IFRS 3 retrospectively to past business combinations. |
|---|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| - | Property, Plant and Equipment: An entity may elect to measure an item of property, plant and equipment at the date of transition to IFRSs at its fair value and use that fair value as its deemed cost at that date.  We have made the election not to revalue our property, plant and equipment to fair value or deemed cost.  Historical cost will be maintained as plant and equipment cost base on transition. |
|---|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| - | Foreign currency translation reserve: consistent with the our Canadian GAAP treatment, IAS 21 requires an entity: (a) to recognize some translation differences in other comprehensive income and accumulate these in a separate component of equity; and (b) on disposal of a foreign operation, to reclassify the cumulative translation difference for that foreign operation (including, if applicable, gains and losses on related hedges) from equity to profit or loss as part of the gain or loss on disposal.  An election can be made to be exempted from this requirement on transition and start with 'zero' translation differences.  We have not made the election to start with 'zero' its cumulative translation differences balance, and have elected to continue with the current translation differences inComprehensive income as these are already in compliance with IAS 21.  As we are maintaining the Foreign Currency Translation Reserve, deferred tax on the balance will also have to be recognized by crediting opening equity balances as under IFRS the translation reserve should be disclosed net of taxes.  There will be no profit and loss impact due to the deferred tax recognition. |
|---|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| - | Oil and Gas assets: Oil and Gas industry specific accounting under IFRS or Canadian GAAP is currently not as comprehensive as the guidance provided under U.S. GAAP accounting for industry specific oil and gas transactions. Para D1 of IFRS 1 provides an exemption in relation to Oil and Gas assets by allowing Companies to continue using the same policies as used under the previous GAAP and carrying forward the carrying amounts of the Oil and Gas assets under Canadian GAAP into IFRS.  We have availed this exemption and elected to maintain our Oil and Gas assets at carrying amount under Canadian GAAP, which will be the deemed cost under IFRS. |
|---|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

| - | Interests in Joint Ventures: CICA Section 3055 differs from IAS 31 as IAS 31 permits the use of either the proportionate consolidation method or the equity method to account for joint ventures.  IAS 31 recommends the use of proportionate consolidation as it better reflects the substance and economic reality, however, it does permit the use of equity method.  CICA Section 3055 only allows the use of proportionate consolidation method to account for joint ventures.  We have elected to maintain our joint venture accounting under the proportionate consolidation model for both our incorporated and unincorporated joint venture interests. |
|---|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

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| Consolidated – Operating results |   | Year ended December 31, |     |
|-------------------------------------------------------|--------|----------------------------------------|----------|
| ($ thousands)                                    |   | 2010                                   |     |   | 2009 |   |   | 2008 |   |
| Midstream – Refining                            |   |                                   | 677,415  |   |   |   | 574,409 |   |   |   | 786,114 |   |
| Downstream                                            |   |                                   | 504,787  |   |   |   | 388,991 |   |   |   | 556,868 |   |
| Corporate                                             |   |                                   | 32,564   |   |   |   | 21,194 |   |   |   | 24,567 |   |
| Consolidation Entries                                 |   |                                   | (412,392 | ) |   |   | (296,115 | ) |   |   | (451,970 | ) |
| Sales and operating revenues                          |   |                                   | 802,374  |   |   |   | 688,479 |   |   |   | 915,579 |   |
| Midstream – Refining                            |   |                                   | (605,603 | ) |   |   | (516,349 | ) |   |   | (779,832 | ) |
| Downstream                                            |   |                                   | (470,772 | ) |   |   | (359,623 | ) |   |   | (536,920 | ) |
| Corporate (1)                                         |   |                                   | -        |   |   |   | - |   |   |   | - |   |
| Consolidation Entries                                 |   |                                   | 374,818  |   |   |   | 273,989 |   |   |   | 428,129 |   |
| Cost of sales and operating expenses                  |   |                                   | (701,557 | ) |   |   | (601,983 | ) |   |   | (888,623 | ) |
| Midstream – Refining                            |   |                                   | 71,812   |   |   |   | 58,060 |   |   |   | 6,282 |   |
| Downstream                                            |   |                                   | 34,015   |   |   |   | 29,368 |   |   |   | 19,948 |   |
| Corporate (1)                                         |   |                                   | 32,564   |   |   |   | 21,194 |   |   |   | 24,567 |   |
| Consolidation Entries                                 |   |                                   | (37,574  | ) |   |   | (22,126 | ) |   |   | (23,841 | ) |
| Gross Margin                                          |   |                                   | 100,817  |   |   |   | 86,496 |   |   |   | 26,956 |   |

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| Quarters ended                                                 |   | 2010   |    |   | 2009   |   |
|----------------------------------------------------------------|--------|--------|---------|--------|--------|--------|
| ($ thousands)                                                  |   | Dec-31 |    |   | Sep-30 |   |   | Jun-30 |   |   | Mar-31 |   |   | Dec-31 |   |   | Sep-30 |   |   | Jun-30 |   |   | Mar-31 |   |
| Upstream                                                       |   |   | (41,681 | )      |   |   | (11,753 | ) |   |   | (3,498 | ) |   |   | (1,964 | ) |   |   | 574 |   |   |   | (29,097 | ) |   |   | (669 | ) |   |   | (469 | ) |
| Midstream – Refining                                     |   |   | 13,780  |   |   |   | 15,785 |   |   |   | 16,962 |   |   |   | 4,402 |   |   |   | 8,492 |   |   |   | 8,199 |   |   |   | 14,134 |   |   |   | 14,747 |   |
| Midstream – Liquefaction                                 |   |   | (1,959  | )      |   |   | (4,588 | ) |   |   | (3 | ) |   |   | (563 | ) |   |   | (1,200 | ) |   |   | (2,119 | ) |   |   | (1,379 | ) |   |   | (2,361 | ) |
| Downstream                                                     |   |   | 4,709   |   |   |   | 1,674 |   |   |   | 7,060 |   |   |   | 4,492 |   |   |   | 4,391 |   |   |   | 6,542 |   |   |   | 4,150 |   |   |   | 3,241 |   |
| Corporate                                                      |   |   | 4,566   |   |   |   | (4,510 | ) |   |   | 1,751 |   |   |   | 4,402 |   |   |   | 1,765 |   |   |   | 1,980 |   |   |   | 1,897 |   |   |   | 3,051 |   |
| Consolidation Entries                                          |   |   | (7,005  | )      |   |   | (5,229 | ) |   |   | (7,384 | ) |   |   | (5,910 | ) |   |   | (4,884 | ) |   |   | (4,092 | ) |   |   | (278 | ) |   |   | (7,285 | ) |
| Earnings before interest, taxes, depreciation and amortization |   |   | (27,590 | )      |   |   | (8,621 | ) |   |   | 14,888 |   |   |   | 4,859 |   |   |   | 9,138 |   |   |   | (18,587 | ) |   |   | 17,855 |   |   |   | 10,924 |   |
| Subtract:                                                      |   |   |    |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Upstream                                                       |   |   | (5,481  | )      |   |   | (4,600 | ) |   |   | (4,367 | ) |   |   | (4,080 | ) |   |   | (4,056 | ) |   |   | (2,164 | ) |   |   | (1,563 | ) |   |   | (1,552 | ) |
| Midstream – Refining                                     |   |   | (1,509  | )      |   |   | (1,693 | ) |   |   | (1,651 | ) |   |   | (1,731 | ) |   |   | (1,973 | ) |   |   | (1,682 | ) |   |   | (1,709 | ) |   |   | (1,786 | ) |
| Midstream – Liquefaction                                 |   |   | (184    | )      |   |   | (376 | ) |   |   | (351 | ) |   |   | (342 | ) |   |   | (379 | ) |   |   | (348 | ) |   |   | (333 | ) |   |   | (158 | ) |
| Downstream                                                     |   |   | (835    | )      |   |   | (938 | ) |   |   | (1,167 | ) |   |   | (800 | ) |   |   | (930 | ) |   |   | (1,045 | ) |   |   | (1,013 | ) |   |   | (1,142 | ) |
| Corporate                                                      |   |   | (1,158  | )      |   |   | (342 | ) |   |   | (20 | ) |   |   | (20 | ) |   |   | (27 | ) |   |   | - |   |   |   | (1,600 | ) |   |   | (2,325 | ) |
| Consolidation Entries                                          |   |   | 6,571   |   |   |   | 6,107 |   |   |   | 5,916 |   |   |   | 5,687 |   |   |   | 5,905 |   |   |   | 3,823 |   |   |   | 3,141 |   |   |   | 2,923 |   |
| Interest expense                                               |   |   | (2,596  | )      |   |   | (1,842 | ) |   |   | (1,640 | ) |   |   | (1,286 | ) |   |   | (1,460 | ) |   |   | (1,416 | ) |   |   | (3,077 | ) |   |   | (4,040 | ) |
| Upstream                                                       |   |   | -       |   |   |   | - |   |   |   | - |   |   |   | - |   |   |   | - |   |   |   | - |   |   |   | - |   |   |   | - |   |
| Midstream – Refining                                     |   |   | (1,040  | )      |   |   | 101 |   |   |   | (366 | ) |   |   | (173 | ) |   |   | 14,316 |   |   |   | - |   |   |   | - |   |   |   | - |   |
| Midstream – Liquefaction                                 |   |   | 36      |   |   |   | - |   |   |   | - |   |   |   | - |   |   |   | (8 | ) |   |   | (3 | ) |   |   | (32 | ) |   |   | (12 | ) |
| Downstream                                                     |   |   | (495    | )      |   |   | (322 | ) |   |   | (1,524 | ) |   |   | (2,361 | ) |   |   | (411 | ) |   |   | (1,398 | ) |   |   | (733 | ) |   |   | (485 | ) |
| Corporate                                                      |   |   | (11     | )      |   |   | (529 | ) |   |   | 97 |   |   |   | (797 | ) |   |   | 1,340 |   |   |   | (339 | ) |   |   | (800 | ) |   |   | (359 | ) |
| Consolidation Entries                                          |   |   | (2      | )      |   |   | (2 | ) |   |   | (2 | ) |   |   | - |   |   |   | (3 | ) |   |   | (1 | ) |   |   | (2 | ) |   |   | (2 | ) |
| Income taxes and non-controlling interest                      |   |   | (1,512  | )      |   |   | (752 | ) |   |   | (1,795 | ) |   |   | (3,331 | ) |   |   | 15,234 |   |   |   | (1,741 | ) |   |   | (1,567 | ) |   |   | (858 | ) |
| Upstream                                                       |   |   | (683    | )      |   |   | (232 | ) |   |   | (78 | ) |   |   | (138 | ) |   |   | (144 | ) |   |   | (132 | ) |   |   | (150 | ) |   |   | (112 | ) |
| Midstream – Refining                                     |   |   | (2,700  | )      |   |   | (2,195 | ) |   |   | (2,888 | ) |   |   | (2,572 | ) |   |   | (2,765 | ) |   |   | (2,755 | ) |   |   | (2,801 | ) |   |   | (2,611 | ) |
| Midstream – Liquefaction                                 |   |   | (7      | )      |   |   | (6 | ) |   |   | (6 | ) |   |   | (6 | ) |   |   | (7 | ) |   |   | (10 | ) |   |   | (20 | ) |   |   | (20 | ) |
| Downstream                                                     |   |   | (737    | )      |   |   | (739 | ) |   |   | (651 | ) |   |   | (660 | ) |   |   | (679 | ) |   |   | (658 | ) |   |   | (662 | ) |   |   | (651 | ) |
| Corporate                                                      |   |   | (16     | )      |   |   | (17 | ) |   |   | (32 | ) |   |   | (41 | ) |   |   | (43 | ) |   |   | (40 | ) |   |   | (174 | ) |   |   | (18 | ) |
| Consolidation Entries                                          |   |   | 33      |   |   |   | 32 |   |   |   | 32 |   |   |   | 32 |   |   |   | 33 |   |   |   | 33 |   |   |   | 32 |   |   |   | 32 |   |
| Depreciation and amortisation                                  |   |   | (4,110  | )      |   |   | (3,157 | ) |   |   | (3,623 | ) |   |   | (3,385 | ) |   |   | (3,605 | ) |   |   | (3,562 | ) |   |   | (3,775 | ) |   |   | (3,380 | ) |
| Upstream                                                       |   |   | (47,845 | )      |   |   | (16,585 | ) |   |   | (7,943 | ) |   |   | (6,182 | ) |   |   | (3,626 | ) |   |   | (31,392 | ) |   |   | (2,382 | ) |   |   | (2,134 | ) |
| Midstream – Refining                                     |   |   | 8,531   |   |   |   | 11,998 |   |   |   | 12,056 |   |   |   | (74 | ) |   |   | 18,071 |   |   |   | 3,762 |   |   |   | 9,624 |   |   |   | 10,349 |   |
| Midstream – Liquefaction                                 |   |   | (2,114  | )      |   |   | (4,970 | ) |   |   | (360 | ) |   |   | (911 | ) |   |   | (1,593 | ) |   |   | (2,481 | ) |   |   | (1,764 | ) |   |   | (2,551 | ) |
| Downstream                                                     |   |   | 2,642   |   |   |   | (325 | ) |   |   | 3,718 |   |   |   | 671 |   |   |   | 2,371 |   |   |   | 3,440 |   |   |   | 1,742 |   |   |   | 964 |   |
| Corporate                                                      |   |   | 3,381   |   |   |   | (5,398 | ) |   |   | 1,796 |   |   |   | 3,544 |   |   |   | 3,034 |   |   |   | 1,601 |   |   |   | (677 | ) |   |   | 350 |   |
| Consolidation Entries                                          |   |   | (403    | )      |   |   | 908 |   |   |   | (1,437 | ) |   |   | (191 | ) |   |   | 1,050 |   |   |   | (236 | ) |   |   | 2,893 |   |   |   | (4,332 | ) |
| Net (loss)/profit per segment                                  |   |   | (35,808 | )      |   |   | (14,372 | ) |   |   | 7,830 |   |   |   | (3,143 | ) |   |   | 19,307 |   |   |   | (25,306 | ) |   |   | 9,436 |   |   |   | 2,646 |   |

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