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ANNUAL
REPORT
2011
NYSE: IOC

An Energy Development Company With Significant
Exploration Potential
About InterOil Corporation
InterOil Corporation is developing a vertically integrated energy business whose primary focus is Papua New Guinea
and the surrounding region. InterOil’s assets consist of petroleum licenses covering about 3.9 million acres, an oil
refinery, and retail and commercial distribution facilities, all located in Papua New Guinea. In addition, InterOil is a
shareholder in a joint venture established to construct an LNG plant in Papua New Guinea. InterOil’s common shares
trade on the NYSE in US dollars.
www.interoil.com

Letter From The Chairman
6
Upstream
8
Midstream - Refining and Liquefaction
13
Table of Contents
Downstream
18
The Environment and Community Relations
21
Management Discussion and Analysis
24
Operational Highlights
29
Management’s Report
59
Independent Auditor’s Report
60
Consolidated Financial Statements
62
Glossary of Terms
111
Corporate Directory
114

Directors and Executive Officers
Front / Left to Right
Ford Nicholson, Board Member Gaylen Byker, Board Member
William J. Jasper lll, President and Chief Operating Officer Collin Visaggio, Chief Financial Officer
Roger Lewis, Board Member
Back / Left to Right
Christian Vinson, Executive Vice President of Corporate Development and Government Affairs
Phil E. Mulacek, Chairman, Director and Chief Executive Officer Roger Grundy, Board Member
Mark Laurie, General Counsel and Corporate Secretary Wayne Andrews, Vice President Capital Markets
For more information, please see Page 114.

Global Operational Office Locations
The Woodlands, Texas USA
Singapore
Port Moresby, Papua New Guinea
Cairns, Australia

Letter From The Chairman
To Our Shareholders
Following up on several years of drilling success, 2011 was a year of progress in engineering and design as well as
investment in critical LNG development infrastructure and exploration activities. These investments have positioned us to
continue to create value for shareholders in 2012. As our LNG project costs have become more clearly defined, our
prospective LNG equity partners have a better view on the economics of the project. When the partnering process is
completed, we will move toward satisfying our 2009 Project Agreement with the Papua New Guinea (PNG) Government. As
the rewards come into focus, we clearly see significant opportunity on the horizon.
Our net profit for the year ended December 31, 2011 was $17.7 million. Our Corporate, Midstream Refining and Downstream
operating segments delivered excellent results, generating a profit of $82.3 million for the year - which helped to fund
investment in our developmental segments of Upstream and Midstream Liquefaction. Our year-end total assets exceeded $1
billion for the first time, and our balance sheet retains considerable financial flexibility with a debt-to-capital ratio of 12%.
During the year we have made progress on the engineering and design of our proposed LNG project in PNG. Our
accomplishments for the year include preliminary Front End Engineering and Design (FEED) on the gathering system, which
connects the production wells to the Condensate Stripping Plant (CSP). We have completed FEED on the CSP, received bids,
and are prepared to award the contract to the winning bidder. We have completed FEED on the Pipeline and received bids
on steel, coating and installation. We are advanced on the FEED for the marine facility and portions of the facility are out for
tender. The only FEED remaining is a test of the soil where the liquefaction plants are proposed to be built, and this is now
under way.
Last year was also an active time for InterOil’s exploration team as we continued to conduct exploration operations and
acquisition of seismic data in our licenses PPL236, PPL237, PPL238 and PRL15. Airborne gravity data and seismic data
acquisition are the primary tools utilized to expand basic exploration coverage, add leads to our portfolio, and create drillable
prospects. The primary near-term directive of the exploration group is to create a mature prospect inventory for a continuous
multi-well exploration program.
In 2011 we completed, or had in progress, 300.4 kilometers (187 miles) of seismic data acquisition. This seismic data
improves the definition of known leads and prospects and identifies new near-field potential. The final processed gravity data
acquired in late 2011 is now becoming available and initial assessment suggests a definition for closure of the Triceratops
6

field. We spudded the Triceratops-2 well early in 2012 which represented the re-commencement of our exploration drilling
program and we will soon be mobilizing our development drilling rig to the Elk and Antelope field area to commence further
appraisal and development work.
In early 2012, the Triceratops-2 well has successfully drilled a very promising section of limestone reservoir and could be in a
position to add material value to our shareholders in 2012. This will be the third consecutive structure drilled and developed
by the company, proving our capacity to organically build a strong hydrocarbon resource base in PNG.
In 2011, we determined that LNG market conditions were favorable to seek a “proven LNG operator.” With the help of our
advisors, we are on schedule to find that LNG partner in order to satisfy the remaining requirements of our 2009 LNG Project
Agreement commitment with the PNG Government. We are pleased with the level of interest among companies that fit the
profile required by the agreement and anticipate a positive conclusion to the selection process in the near future.
Our objectives remain to derive value for our shareholders, to support safe and efficient operations for our employees, and to
be a good partner to those with whom we do business.
Our annual update would not be complete without discussing our efforts to improve the lives of the people in the communities
in which we conduct our business. InterOil has been active in promoting women’s health and education programs in the
Purari community, providing fresh water supply to a local village, and assisting a local school re-opening at Wabo. InterOil
also sponsored the training of directors of a local company representing four Motu villages, and has sponsored higher
education for deserving individuals in the communities where we operate.
We are also proud to report that, with about 1,000 PNG citizens employed by InterOil, we have worked 10.6 million man
hours without a lost time injury. Safety has always been a priority for InterOil and this remarkable achievement is a testament
to the tireless dedication by all of our employees.
We believe that there is a vast amount of value within InterOil that will be realized as we further execute our LNG partnering
and development plans. We are very excited about the Company’s future and deeply appreciate our shareholders’ continued
support. We look forward to reporting our progress and achievements to you in the months ahead.
Sincerely,
Phil E. Mulacek
Chairman and Chief Executive Officer
7

Upstream
Exploration and Production

As at December 31, 2011, we had interests in three PPLs and one PRL in Papua New Guinea covering 3,996,453 gross
acres, all of which were operated by us. PPLs 236, 237 and 238 and PRL 15 are located onshore in the Eastern Papuan
Basin, northwest of Port Moresby.
On November 30, 2010, we were granted PRL 15, covering a total of nine graticular blocks including and surrounding the Elk
and Antelope fields and extracted from PPLs 237 and 238. This PRL unifies the Elk and Antelope fields into a single license
and separates the fields from our exploration acreage. The PRL has a separate minimum work program and expenditure
commitment for the next five years.
The following table summarizes our interests and on acreage currently held by InterOil as at December 31, 2011:
License Numbers Basin Location Operator
InterOil Registered
License Interest
Blocks Covered Acreage Gross Acreage Net
PPL 236 Papuan Onshore InterOil 100.00% 53 1,112,464 1,112,464
PPL 237 Papuan Onshore InterOil 100.00% 34 715,648 715,648
PPL 238 Papuan Onshore InterOil 100.00% 94 1,978,565 1,978,565
PRL 15 2 Papuan Onshore InterOil 100.00% 9 189,776 189,032
Total 3,996,453 3,991,709
1 See Petroleum License Details – Net Working Interest on PPL 236, PPL 237 and PPL 238
1 An application to transfer 2.5% interest in PRL15 to Pac LNG pursuant to an agreement entered into in 2009 was submitted to the PNG Department of
Petroleum and Energy; and was approved in December 2011.
Costs Incurred in Relation to Exploration and Development Activities
The following table outlines costs incurred by InterOil during the year ended
December 31, 2011 for acquisitions and capital expenditure associated with
exploration and development activities.
Nature of Cost
Acquisition costs
(Proved and Unproved):
Exploration costs $18.4
Amount
(US $ Million)
Development costs $107.6
Additionally the following table summarizes the results of exploration and
development activities on a gross and net basis (with net costs reflecting the cost to
Total $126.0
us, not including the portion of costs met by IPI holders, PNGDV and/or Pac LNG), as further broken down by well type,
during the year ended December 31, 2011.
Wells Development Exploration Total
Gross
(US $ Million)
Net
(US $ Million)
Gross
(US $ Million)
Net
(US $ Million)
Gross
(US $ Million)
-
Net
(US $ Million)
Gas $116.5 $107.6 $21.2 $18.4 $137.7 $126.0
Oil - - - - - -
Service - - - - - -
Dry - - - - - -
Total $116.5 $107.6 $21.2 $18.4 $137.7 $126.0
During the year ended December 31, 2011, we have commenced the construction of certain infrastructure such as roads,
wharves, warehouses and camps to support the proposed appraisal and development drilling in the Elk and Antelope gas
fields. In addition, we also undertook exploration activities in our three exploration licenses, PPL 236, PPL 237 and PPL 238.
These exploration activities involved a regional airborne geophysical survey, various seismic surveys across a number of
prospects and preparation for drilling of our next appraisal well, Triceratops 2, which was spudded in mid-January 2012. No
wells were drilled during the year ended December 31, 2011. The preparation of the Triceratops 2 well site was completed at
the end of 2011 and the Triceratops 2 well was spudded on January 15, 2012. The Triceratops 2 well is an appraisal well to
test the presence of hydrocarbons and determine whether a potential reefal carbonate reservoir exists in the Triceratops field.
Operated License Commitments, Terms, Expiry and Re-Application
In March 2009, PPLs 236, 237 and 238 were extended for 5 years, with an initial term of 2 years and a subsequent 3 year
term. The PPL license renewals require that we expend the amounts set out below and drill a total of 6 wells within those
license areas during the renewed license term. The first 2 year term of the license anniversaries occurred in March 2011. On
May 17, 2011, the State approved our request to extend all three licenses for the second two year term (years 3 and 4).
In January 2011, we applied for a variation of license conditions on PPL 238 to defer the commitment to drill a well from first
9

two year term to the second term which ends in March 2013. The State also approved this request on May 17, 2011.
We have met all other commitments under our licenses as of December 31, 2011.
Following are our applicable expenditure commitments for each PPL and PRL based on the approved renewals in March
2009 and the PRL granted in November 2010:
License License Issued for Second Term On Second Operator
InterOil Registered
License Interest
Blocks Covered
Acreage Gross
PPL 236 March 27, 2009 5 years $5.0 $10.0 $15.0 March 27, 2014
PPL 237 March 27, 2009 5 years $14.0 $34.0 $48.0 March 27, 2014
PPL 238 March 6, 2009 5 years $2.0 $30.0 $32.0 March 6, 2014
PRL15 November 30, 2010 15 years $53.0 $20.0 $73.0 November 30, 2025
1 Commitment total is for the first 5 years only
Totals $74.0 $94.0 $168.0
Petroleum License Deals
Net Working Interests in Licenses
Our licenses are located onshore in the eastern Papuan Basin,
northwest of Port Moresby and are largely owned by us,
subject to investor elections to earn a working interest in
certain discoveries pursuant to the terms of our various indirect
participation interest agreements. All properties are currently
operated by us. The State has the right under relevant PNG
legislation to acquire a 22.5% interest (which includes 2% on
behalf of landowners) in any PDL, by contributing its share of
exploration and development costs. Pac LNG holds a 2.5%
working interest in gas and condensate in the Elk and Antelope
Participant Working Interests * With State Participation
InterOil 75.6114% 58.5988%
IPI holders 15.1386% 11.7324%
PNGDV 6.75% 5.2312%
Pac LNG 2.50% 1.9375%
State
Entitlement
Landowners
Entitlement
0.00% 20.50%
fields (which fields are located on PRL 15) under an agreement entered into in 2009. The table below sets forth the working
interest position in the Elk and Antelope fields, currently under PRL 15, in the event that the State, Pac LNG and indirect
participation interest holders all exercise their rights to acquire their allocated interests in the Elk and Antelope discoveries.
Petroleum Prospecting License 236
0.00% 2.00%
Total 100.00% 100.00%
1 These interests assume all existing potential partners as at December
31, 2011 elect to participate.
We have a 100% working interest in PPL 236, subject to potential participation
and elections made by holders of indirect participation interests and the State.
The license consists of 53 graticular blocks covering an area of 4,502 square
kilometres or 1,112,464 acres.
PPL 236
The following are the work commitments for PPL 236 for the subsequent 2 year
term, ending in March 2013:
•
•
•
A minimum expenditure of $ 9.85 million;
Drill an exploration well at a location acceptable to the State; and
Complete a thorough petroleum system and basin study in PPL 236 to
determine the likely controls on the distribution and reservoir quality of
the onshore Late Oligocene to Late Miocene shallow marine reefal and
shelfal carbonate depositional systems, likely controls on the source rock
quality and maturity and tectonostratigraphic influences on the timing of
the generation and expulsion of hydrocarbons, their migration, charge
and preservation.
Petroleum Prospecting License 237
We have a 100% working interest in PPL 237, subject to potential participation and elections made
by holders of indirect participation interests and the State. The license consists of 34 graticular blocks
10

covering an area of 3,238 square kilometers or 715,648 acres. On November 30, 2010, a total of four graticular blocks were
excised from PPL 237 and incorporated into PRL 15.
The following are the work commitments for PPL 237 for the two year term ending in March 2013:
•
•
•
Minimum expenditure of $10.0 million;
Acquire, process and interpret new seismic data focused on selecting a drilling location; and
Complete a thorough petroleum system and basin study to determine the likely controls on the distribution and
reservoir quality of the onshore Late Oligocene to Late Miocene shallow marine reefal and shelfal
carbonate depositional systems, likely controls on the source rock
quality and maturity and tectonostratigraphic influences on the timing of the generation and expulsion of hydrocarbons,
their migration, charge and preservation.
Petroleum Prospecting License 238
We have a 100% working interest in PPL 238,
subject to potential participation and elections
made by holders of indirect participation
interests and the State. The license consists of
94 graticular blocks covering an area of 7,922
square kilometers or 1,978,565 acres. On
November 30, 2010, a total of five graticular
blocks, including the blocks in which the Elk-1
and Elk-4A gas /condensate discovery wells
were drilled, were excised from PPL 238 and
incorporated into PRL 15.
PPL 237
PPL 238
Following are the work commitments for PPL
238 for the two year term ending in March
2013:
• Minimum expenditure of $ 10.0 million
• Acquire, process and interpret new seismic data focused on selecting a
drilling location;
PPL 15
• Complete thorough petroleum system and basin study to determine the
likely controls on the distribution and reservoir quality of the onshore Late
Oligocene to Late Miocene shallow marine reefal and shelfal carbonate depositional
systems, likely controls on the source rock quality and maturity and tectonostratigraphic
influences on the timing of the generation and expulsion of hydrocarbons, their migration,
charge and preservation; and
• Drill a well at a location acceptable to the State.
Petroleum Retention License 15
Petroleum retention licenses may be granted to licensees of PPLs in which petroleum fields or parts of petroleum fields have
been discovered to permit time for the licensee to develop the means for commercialization of the gas discoveries. In August
2009, we applied for a PRL over the declared location and on November 30, 2010, PRL 15 was granted by the State and
was excised from of PPL 237 and PPL 238.
At the end of 2011, we still held a 97.50% registered interest in PRL 15. However, this is subject to elections to be made by
the State’s nominee to acquire a 22.5% interest on behalf of the State and landowners, to elections by holders of certain
indirect participation interests, as set out in the table on the preceding page.
The initial period of a petroleum retention license is for five years and further extensions of two, five year terms may be granted
at the discretion of the State.
The total commitment over the first five year term amounts to $73.0 million. Following are the work commitments for PRL15
for the first two years of this term, ending in November 2012.
•
•
Drill 2 wells in the Elk and Antelope fields;
Acquire, process and interpret 100 kilometers of two dimensional seismic acquisition and complete geoscience
studies;
11

•
•
•
Conduct social mapping and social and economic impact studies;
Conduct commercial and marketing studies; and
Conduct surface and subsurface engineering studies
•
•
•
Static and dynamic reservoir modeling
Base case depletion plan
Surface facilities
Petroleum Development License (“PDL”)
In order to progress the proposed development and commercialization of the Elk and Antelope fields, we are required to apply
for and obtain a PDL from the State. Assuming that a PDL is issued, it will replace PRL 15 and include the Elk and Antelope
gas fields and additional acreage required for facilities and pipelines. We have commenced preparation of an application for a
PDL.
The application for a PDL is made to the Department of Petroleum and Energy and must be accompanied by detailed
proposals for the construction, establishment and operation of all facilities and services for and incidental to the recovery,
processing, storage and transportation of gas from the PDL area. In addition, certain agreements and approvals from the
State will need to be in place prior to the grant of the PDL including a gas agreement defining the fiscal regime applicable to
the development and providing for the State’s equity participation in the fields amongst other things. Environmental approvals
will be necessary and we will also be obliged to submit comprehensive social mapping and landowner identifications studies
of those customary landowners within the PDL area. Ministerial recognition of landowner groups is customarily based on such
reports.
Upon application, the State will undertake a comprehensive review of the development proposals and any other incidental
agreement or approval required before granting the PDL application. Following its review, the State shall take steps to
conduct a ‘forum’ as set out under the Oil and Gas Act. The forum requires that the State co-ordinate a meeting for all
affected stakeholders including the provincial, local level governments and customary landowners with a view towards
establishing a regime for the distribution of royalties and other benefits that will arise from the commercialization of the fields.
Once all formalities are completed and the State is satisfied, the Minister for Petroleum may grant the PDL. Should the PDL
be issued, the acreage would be held subject to; (i) periodic review provided for in PNG’s Oil & Gas Act, and (ii) to the license
holders continuing to meet commitments associated with the license grant.
Participation Agreements
In May 2003, we entered into an indirect participation agreement with PNGDV which was amended in May 2006. Under this
amended agreement, PNGDV has a 6.75% interest in eight exploration wells. We have drilled six of these exploration wells to
date. PNGDV also has the right to participate in the next 16 wells that follow the first eight mentioned above up to an interest
of 5.75% at a cost of $112,500 for each 1% per well (with higher amounts to be paid if the depth exceeds 3,500 meters and
the cost exceeds $8,500,000).
In February 2005, we entered into an agreement with IPI holders pursuant to which the IPI holders paid us an aggregate
of $125.0 million and we agreed to drill eight exploration wells in Papua New Guinea on PPLs 236, 237 and 238. We have
drilled four of the eight wells to date. Following various buybacks and conversions, IPI holders currently hold interests totaling
15.1386% of each of these existing and future wells, including those in the Elk and Antelope fields.
In addition, PNGEI has the right to participate up to a 4.25% interest in 16 wells commencing from exploration wells
numbered 9 to 24. As at the end of December 31, 2011, we have drilled 6 exploration wells since inception of our exploration
program within PPL 236, 237 and 238. In order to participate, PNGEI would be required to contribute for each exploration
well; $112,500 per 1% plus actual costs over $1.0 million charged pro rata for each 1%.
Pac LNG holds a 2.5% direct working interest in gas and condensate in the Elk and Antelope fields under an agreement
entered into in 2009.
If a PDL is granted, investors in our participation interest programs set out above have the right to become registered direct
working interest owners by having their interest registered on the PDL. In order to maintain their right to earn revenues from
the field, the investors are required to continue to fund their share of ongoing appraisal drilling and all subsequent work which
may be required to bring the field into production.
12

Midstream
Refining and Liquefaction

Refining
Produces refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea for the domestic market
and for export.
Our refinery is located across the harbor from Port Moresby, the capital city of Papua New Guinea. Our refinery is currently the
sole refiner of hydrocarbons located in Papua New Guinea.
Jet fuel, diesel and gasoline are the primary products that we produce for the domestic market. The refining process also
results in the production of two Naphtha grades and low sulfur waxy residue. To the extent that we do not convert the
Naphtha to gasoline, we export it to the local and Asian markets in two grades, light Naphtha and mixed Naphtha, which are
predominately used as petrochemical feedstock. LSWR can be and is being sold as fuel for power generation domestically,
local bunker fuel sales with the majority exported for use in other complex refineries as cracker feedstock or supply to other
end users, including power generators.
Facilities and Major Subcontractors
Our refinery includes a jetty with two berths for loading and discharging vessels and a road
tanker loading system (gantry). Our larger berth has deep water access of 56 feet (17 metres)
and has been designed to accommodate crude and product tankers with capacity up to
130,000 dwt. Our smaller berth can accommodate ships with a capacity of up to 22,000 dwt.
Our tank farm has the ability to store approximately 750,000 barrels of crude feedstock and
approximately 1.1 million barrels of refined products. We have a reverse osmosis desalination
unit that produces all of the water used by our refinery, camp and office facilities, power
generation facilities that meet all of our electricity needs, and other site infrastructure and
support facilities, including a laboratory, a waste water treatment plant, staff accommodation
and a fire station.
Our refinery’s on-site laboratory is accredited by National Association of Testing Authorities, Australia. The lab is staffed and
operated by an internationally recognized independent inspection and testing company. All crude imports and finished
products are tested and certified on-site to contractual specifications, while independent certification of quantities loaded and
discharged at the refinery are also provided by the laboratory.
14

Crude Supply
In December 2001, we entered into an agreement with BP Singapore for the supply of crude
feedstock to our refinery. Supply under the agreement commenced when our refinery began
operations in June 2004 and continued for 5 years until June 2009. Since this time the
agreement has been renewed annually. BP Singapore is one of the largest marketers and
shippers of crude oil in the Asia Pacific region. This contract provides us with a reliable
mechanism to access and ship the majority of the regional crudes suitable for our refinery. We
will continue to review this arrangement and other options for sources of feedstock supply
for our refinery and have been successful in securing other crude supply agreements for
specific regional crudes.
Sales
Papua New Guinea is our principal market for the products our refinery produces, other than
Naphtha and LSWR. Under our 30 year agreement with the State, the State has agreed to
ensure that all domestic distributors purchase their refined petroleum product needs from our
refinery, (and from any other refinery which may be constructed in Papua New Guinea), at IPP.
In general, the IPP is the price that would be paid in Papua New Guinea for a refined product
that is being imported. In late 2007, the IPP was modified, most significantly by changing the
Singapore benchmark price from the ”Singapore Posted Prices” which was no longer being
updated, to ”Mean of Platts Singapore” (”MOPS”) which is the current benchmark price for
refined products in the region in which we operate. The Project Agreement governing our
relationship with the State is yet to be formally amended to reflect the revised formula which has
been in use for the last four years. (See “Material Contracts – Refinery Project Agreement”).
The major export product from our refinery is the two grades of Naphtha. On January 1, 2010 a 12 month term agreement
with Dalian Fujia Dahua Petrochemicals (“Dalian”), which operates a petrochemical plant in China, was entered into providing
for export sales of Naphtha. This contract has been renewed subsequently and the current term agreement with Dalian runs
for an 18 month period from January 1, 2011 until June 30, 2012.
Our refinery is fully certified to manufacture and market Jet A-1 fuel to international specifications and markets this product to
both domestic Papua New Guinea and overseas airlines.
We were a net consumer of LPG until the conversion of the main process furnaces and commissioning of the Hyundai
generators which burn LSWR in 2006. With the installation of the LSWR firing generators, heaters and boilers, plus improved
facilities for recovering LPG from the reformer off-gas and increased percentages of sweet crudes containing LPG, we are
now a net producer of LPG.
Competition
Due to their favorable properties, light sweet crudes from the Southeast Asian and Northwest Australian region are highly
sought after by refiners for use as feedstock. Therefore, there is significant competition to secure cargoes of these crude
types. Due to the limited supply of light sweet crudes and the strong competition, we are not always able to secure our first
choice crudes for our refinery and are required to obtain alternate crudes that are available.
We own the only refinery in Papua New Guinea. While not restricted under any agreement we have with the State, we do not
envision any new entrants into the refining business within Papua New Guinea under the current market conditions. However,
domestic distributors have not sourced all of their requirements from the refinery since 2009. Excess diesel, gasoline,
Naphtha and LSWR that are exported are sold subject to prevailing commodity market conditions. Our geographical
position and limited storage capacity inhibits our ability to compete with the regional refining center in Singapore for sales of
large cargo sizes. However, these same factors may also provide competitive advantages if we expand our exports of refined
products to the small and fragmented South Pacific markets.
15

Customers
Domestically in Papua New Guinea we sell Jet A-1 fuel, diesel, gasoline and small parcels of LSWR to domestic distributors.
Our main domestic customer is our downstream distribution business segment, however we also distribute fuel products to
Niugini Oil Company, Islands Petroleum and Exxon Mobil.
Trading and Risk Management
Our revenues are derived from the sale of refined petroleum products. Prices for refined products and crude feedstock are
volatile and sometimes experience large fluctuations over short periods of time as a result of relatively small changes in
supplies, weather conditions, economic conditions and government actions. Due to the nature of our business, there is
always a time difference between the purchase of a crude feedstock and its arrival at the refinery and the supply of finished
products to customers.
Our refinery faces mainly two types of market risks:
• Flat price (or timing) risk, which results from the time lag between crude purchases and product sales. Generally, we
are required to purchase crude feedstock approximately one to two months in advance of processing, whereas the
domestic supply or export of finished products takes place after the crude feedstock is discharged and processed.
This timing difference can lead to differences between the cost of our crude feedstock and the revenue from the
proceeds of the sale of products, due to the fluctuation in prices during the time period.
• Crack spread (or margin) risk. Month to month changes of crack spreads, even when pricing of crude purchases and
that of product sales fall into the same month, can affect the profitability of our refinery.
However, we can use various derivative instruments to assist us to reduce or hedge away the risks of changes in the relative
prices of our crude feedstock and refined products. These derivatives, which can be used to manage our price risk, can
effectively enable us to manage the refinery margin. At the same time, this means that if the difference between our sales price
of the refined products and our acquisition price of crude feedstock expands or increases, then the benefits are limited to
the margin range we have established.
The derivative instruments which we generally use are over-the-counter swaps. Swap transactions are executed between
the counterparties in the derivatives swaps market. It is commonplace among major refiners and trading companies in Asia
Pacific to use derivative swaps as a tool to hedge their price exposures and margins. Due to the wide usage of such
derivative tools in the Asia Pacific region, the swaps market generally provides sufficient liquidity for our hedging and risk
management activities. The derivative swap instrument covers commodities or products such as jet, kerosene, diesel,
Naphtha, and also crudes such as Dated Brent and Dubai. By using these tools, we actively engage in hedging activities to
manage margins.
During 2011, we participated in a number of hedges to reduce our risks. To manage the flat price risks, we transferred crude
purchases to the months of product sales by utilizing Dated Brent time spread; we also directly sold product swaps for the
months of product sales, such as selling MOPS naphtha swaps. To manage the crack spread risk, we sold crack spread
swaps, such as MOPS naphtha vs. Dated Brent swaps and MOPS Gasoil 0.5% vs. Dated Brent swaps.
Liquefaction
We are developing, together with our partners, an LNG Project for the construction of liquefaction facilities now being
designed to be built on the coast in the Gulf Province of PNG. The Gulf LNG Project is a staged project which we currently
plan to build in 3 stages.
Stage 1 - Start up production: Has an expected start up in 2015 of between 3 to 5 mtpa of LNG with a condensate
stripping unit of 400 to 900 mmscf/d (subject to PNG approvals).
Stage 2 – Expected Production: The LNG Project intends to target a total of 8 mtpa LNG production to follow, with a
condensate stripping facility capacity of 1,350 mmscf/d capacity.
Stage 3 – Potential Expansion Production: The potential final ramp up will be to 11 mtpa with condensate stripping
facilities reaching 1,800 mmscf/d.
16

We can provide no assurances that we will obtain the financing and approvals necessary to proceed with the LNG Project in
this manner, or that we will have sufficient gas resources to support the potential expansion stage.
Other than the core liquefaction facilities, the infrastructure being contemplated includes wells, gas gathering pipelines,
condensate stripping facilities, condensate storage, a condensate pipeline and export handling facilities, a dry gas pipeline
from the Elk and Antelope fields and LNG storage and marine export terminal.
Initial engineering design was undertaken in relation to the LNG Project and the regulatory and taxation regime with the State
was established with the execution on December 23, 2009 of the LNG Project Agreement. This agreement also provides for
the participation by the State in the LNG Project, allowing it to take up to a 20.5% ownership stake. Affected landowners are
able to take an additional 2% stake.
During 2010, we and Pac LNG, decided to pursue the development of the LNG Project by exploring the use of a
modular plant, able to be expanded incrementally from an initial position of 2 mtpa, and to explore locating this plant in the
Gulf Province rather than near our existing refinery outside of Port Moresby. Advantages perceived with this approach include
the potential acceleration of first production and reduced operational risks.
In line with this revised approach, certain initial conditional agreements have been entered into with EWC for development of
the LNG Project. Under the terms of these agreements, the LNG Project is intended to be developed in two initial phases,
with a 2 mtpa liquefaction module to be followed immediately by a 1 mtpa module expansion plant. In return for fully
funding the construction of the liquefaction facilities, EWC is to be entitled to a fee of 14.5% of the proceeds from LNG
revenue derived from these facilities less agreed deductions, and subject to adjustments based on timing and execution for a
15 year period. The agreements remain conditional and the parties may still elect not to proceed with the LNG Project on the
terms specified or at all.
We are also exploring employment of a floating liquefaction vessel, to be constructed by FLEX LNG and Samsung Heavy
Industries. The vessel would integrate with and augment the land-based modules proposed by EWC. FEED work, including
work specific for the LNG Project has been carried out and commercial negotiations are being undertaken.
Infrastructure required for the LNG Project includes a jetty and breakwater for the LNG loading facility with expansion
potential, and approximately 70 miles (115 kilometers) of pipeline from the Elk and Antelope fields to the coast. The wells and
processed natural gas pipeline from the CS Project 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.
Completion of the required LNG Project by us and our joint venture partners and related construction will take a number of
years to complete. No assurances can be given that we will be able to construct the proposed LNG facilities or as to the
timing of such construction.
At present, the LNG Project is being pursued by us in joint venture with Pac LNG. Our interests in the project are held through
an incorporated joint venture entity, PNG LNG which in turn wholly owns those entities formed in Papua New Guinea to
pursue the LNG Project. We have equal voting rights in the entity but hold approximately 85% of the economic interest in it by
means of the Class B shares we hold and under our shareholders agreement (see “Material Contracts – LNG Project
Shareholders Agreement dated July 30, 2007”). It is intended that our interest will be reduced and Pac LNG’s and possibly
other third party interest’s will increase as the LNG Project proceeds, and as Pac LNG and possibly others make certain
equalizing payments, whether in response to cash calls or as a result of sales of a strategic interest in the LNG Project.
We are currently seeking an internationally recognized LNG operating and equity partner for the co-development of the LNG
Project, which may include their acquisition of an interest in the Elk and Antelope fields.
17

Downstream
Wholesale and Retail Distribution

We have the largest wholesale and retail petroleum product distribution base in Papua New Guinea, after acquiring the fuel
distribution assets of British Petroleum and Royal Dutch Shell several years ago. This business includes bulk storage,
transportation distribution, aviation, wholesale and retail facilities for refined petroleum products. Our downstream business
supplies petroleum products nationally in Papua New Guinea through a portfolio of retail service stations and commercial
customers.
Sales
The ICCC regulates the maximum prices and margins that may be charged by the wholesale and retail hydrocarbon
distribution industry in Papua New Guinea. Margins were last reviewed by the ICCC in 2010 and will be further reviewed in
2014. We and our competitors may charge less than the maximum margin set by the ICCC in order to maintain
competitiveness.
Supply of Products
Our retail and wholesale distribution business distributes diesel, jet fuel, avgas, gasoline,
kerosene and fuel oil as well as branded commercial and industrial lubricants, such as engine
and hydraulic oils. In general, all of the refined products sold pursuant to our wholesale and
retail distribution business are purchased from our refinery. We import the commercial and
industrial lubricants, avgas and fuel oil, which constitute a small percentage of our sales.
We deliver refined products from our refinery to two tanker vessels we charter, which are
operated by a separate corporate division. We do not own these vessels but rather lease them
on a full time charter basis. We schedule all of our own movements and deliveries on our
chartered vessels. Our inland depots are supplied by road tankers which are owned and operated by third party independent
transport contractors.
Our terminal and depot network distributes refined petroleum products to retail service stations, aviation facilities and
commercial customers. We supply retail service stations and commercial customers with petroleum products using trucks or,
in the case of some commercial customers, coastal ships. We do not own any of these shipping or trucking distribution
assets. We pass transportation costs through to our customers.
Retail Distribution
We provide petroleum products to retail service stations, both operating under the InterOil
brand name and under independent brands. The service stations are either owned by us,
head leased to us with a sublease to company-approved operators, or independently owned
and operated. We supply products to each of these service stations pursuant to distribution
supply agreements. Under the cover of an equipment loan agreement, we also provide fuel
pumps and related infrastructure to the operators of many of these retail service stations that
are not owned or leased by us.
Wholesale Distribution
We supply petroleum products as a wholesaler to commercial clients and operate aviation refueling facilities throughout
Papua New Guinea. We own and operate six large terminals and six depots that we use to supply product throughout Papua
New Guinea. We enter into commercial supply agreements with mining, agricultural, fishing, logging and similar commercial
clients to supply their petroleum product needs. Pursuant to many of these agreements, we supply and maintain company
owned above-ground storage tanks and pumps that are used by these customers. More than two-thirds of the volume of
petroleum products that we sold during 2011 was supplied to commercial customers. Although the volume of sales to
commercial customers is far larger than through our retail distribution network, these product sales are at a lower margin due
to the volume rebates offered to our larger customers as a direct result of competition in this sector. Aviation customers
represented a significant proportion of our total business by volume.
Competition
Our main competitor in the wholesale and retail distribution business in Papua New Guinea is ExxonMobil. We also compete
with smaller local distributors of petroleum products. With the decision of our competitors early in 2010 to partly import
directly from overseas refineries and the consequent cessation of the joint industry shipping arrangements, it is difficult to
accurately gauge our market share. Our competitors source small quantities from our refinery from both the refinery gantry
19

for the Port Moresby market and by tanker vessel for the markets outside Port Moresby. Our major competitive advantage is
the large widespread distribution network we maintain with adequate storage capacity that services most areas of PNG. We
also believe that our commitment to the distribution business in Papua New Guinea at a time when major-integrated oil and
gas companies exited the Papua New Guinea fuel distribution market provides us with a competitive advantage. However,
major-integrated oil and gas companies such as ExxonMobil have greater resources than we do and could if they decided to
do so, expand much more rapidly in this market than we can.
Major Customers
We sell approximately 15% of our refined petroleum products to a major mining project in
Papua New Guinea pursuant to a wholesale distribution contract. These volumes were
contracted with narrow margins in order to provide volumes for the Midstream Refinery
operations and as such, the loss of this customer, at least in the short term, would not
adversely affect the profitability of our retail and wholesale distribution business. We entered
into an additional supply agreement with a major mine in January 2010 for a two plus two year
period.
During 2011, we sold approximately 10% of our refined petroleum products to Pacific Energy
Aviation (PNG) Ltd for aviation refueling at Papua New Guinea’s international airport in Port Moresby.
20

The Environment and Community Relations

Environmental Protection
Our operations in Papua New Guinea are subject to an environmental law regime which includes laws concerning emissions
of substances into, and pollution and contamination of, the atmosphere, waters and land, production, use, handling, storage,
transportation and disposal of waste, hazardous substances and dangerous goods, conservation of natural resources, the
protection of threatened and endangered flora and fauna and the health and safety of people.
These environmental laws require that our sites be operated, maintained, abandoned and reclaimed to standards set out
in the relevant legislation. The significant Papua New Guinea laws applicable to our operations include the Environment Act
2000; the Oil and Gas Act 1998; the Dumping of Wastes at Sea Act (Ch. 369); the Conservation Areas Act (Ch.362); and the
International Trade (Flora and Fauna) Act (Ch.391).
The Environment Act 2000 is the single most significant legislation affecting our operations. This regulates the environmental
impact of development activities in order to promote sustainable development of the environment and the economic, social
and physical well-being of people and imposes a duty to take all reasonable and practicable measures to prevent or minimize
environmental harm. A breach of this Act can result in significant fines or penalties. Under the Compensation (Prohibition of
Foreign Legal Proceedings) Act 1995, no legal proceedings for compensation claims arising from petroleum projects in Papua
New Guinea may be taken up or pursued in any foreign court.
Compliance with Papua New Guinea’s environmental legislation can require significant expenditures. The environmental
legislation regime is complex and subject to different interpretations. Although no assurances can be made, we believe that,
absent the occurrence of an extraordinary event, continued compliance with existing Papua New Guinea laws regulating the
release of materials into the environment or otherwise relating to the protection of the environment will not have a material
effect upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations, as
has been the case during 2011. Future legislative action and regulatory initiatives could result in changes to operating permits,
additional remedial actions or increased capital expenditures and operating costs that cannot be assessed with certainty at
this time.
We have outstanding loans with OPIC, an agency of the United States Government supporting the development of our
refinery. OPIC is required by statute to conduct an environmental assessment of every project proposed for financing and to
decline support for projects that, in OPIC’s judgment, would have an unreasonable or major adverse impact on the
environment, or on the health or safety of workers in the host country. For most industrial sectors, OPIC expects projects to
meet the more stringent of the World Bank or host-country environmental, health and safety standards. OPIC systematically
monitors compliance with environmental representations and non-compliance may constitute a default under loan
agreements.
More stringent laws and regulations relating to climate change and greenhouse gases may be adopted in the future and could
cause us to incur material expenses in complying with them. Regulatory initiatives could adversely affect the marketability of
the refined products we produce and any oil and natural gas we may produce in the future. The impact of such future
programs cannot be predicted.
22

Environmental and Social Policies
We have developed and implemented an environmental policy which acknowledges that the principles of sustainable
development are integral to responsible resource management and will strive to minimize impacts on the physical
environment. Other environmental initiatives embrace the introduction of “Environmental Risk Analysis” for major projects in
which hazards to the environment are identified, mitigating controls implemented and a “Hazard Register” developed to
monitor any residual risks. We are also developing project specific “Environmental Management, Monitoring & Reporting
Plans”, in compliance with the PNG environmental legislation and in order to monitor our ongoing compliance and
performance, we have established corporate level controls in which all “near miss and real incidents” are reported, and
investigated.
We have not adopted any specific social policies that are fundamental to our operations. However, we are committed to
working closely with the communities we operate in and to complying with all laws and governmental regulations applicable to
our activities, including maintaining a safe and healthy work environment and conducting our activities in full compliance with
all applicable environmental laws.
We have established a dedicated Community Relations department to oversee the management of community assistance
programs and to manage land acquisition related compensation claims and payments. Our development philosophy is based
on “bottom-up planning” thus ensuring that all planning and development takes the local community into account. In relation
to our midstream refining business, the department has developed a long-term community development assistance program
that benefits the villages in the vicinity of the refinery. In addition, we have a team of officers associated with our upstream
business who operate in the field and perform a wide variety of tasks. These include land owner identification studies, social
mapping management, local recruitment, liaising with landowners, recording compensation payments to land owners and
assisting in the provision of health and medical services in the areas in which our exploration activities are conducted.
Generally, the department works closely with government, landowners and the community in order to ensure that all our
activities have a minimum environmental impact and to at least maintain, and generally improve, the quality of life of the
people inhabiting the areas in which we work.
We are currently undertaking the work required under PNG’s Oil & Gas Act and Environment Act to support an application for
a PDL for the Elk and Antelope gas fields and other related licenses which will be required for pipelines and processing
facilities associated with our LNG Project. These studies cover social mapping, social economic impact statements, land
investigations and other related base line studies. The environmental approval process is well advanced and we have
engaged expert consultants to assist us with the preparation of a detailed environmental impact statement, a project
environmental management plan, a fisheries assessment report and other baseline environmental studies. These studies are
a pre-requisite to the grant of a PDL, allow us to advance the necessary planning to formulate our proposals as to the nature
and distribution of project benefits, and will assist the State in convening a forum of all interested stakeholders at a landowner,
local and provincial government level for the purpose of procuring a development agreement on benefit sharing.
23

Management Discussion and Analysis

The following Management Discussion and Analysis (“MD&A”) should be read in conjunction with our audited annual
consolidated financial statements and accompanying notes for the year ended December 31, 2011 and our annual
information form (the “2011 Annual Information Form”) for the year ended December 31, 2011. The MD&A was
prepared by management and provides a review of our performance in the year ended December 31, 2011, and of
our financial condition and future prospects.
Our financial statements and the financial information contained in this MD&A have been prepared in accordance with
International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board applicable to
the preparation of financial statements, including IFRS 1 – ‘First-time Adoption of International Financial Reporting Standards’,
and are presented in United States dollars (“USD”) unless otherwise specified. Our transition date to IFRS was January 1,
2010. Financial information for 2010 included in this MD&A has been restated in accordance with IFRS. Financial information
for 2009 included in this MD&A has been prepared in accordance with previous GAAP.
References to “we,” “us,” “our,” “Company,” and “InterOil” refer to InterOil Corporation or InterOil Corporation and its
subsidiaries as the context requires. Information presented in this MD&A is as at December 31, 2011 and for the quarter and
year ended December 31, 2011, unless otherwise specified. A listing of specific defined terms can be found in the “Glossary
of Terms” section of this document.
Forward-Looking Statements
This MD&A contains “forward-looking statements” as defined in U.S. federal and Canadian securities laws. Such statements
are generally identifiable by the terminology used such as “may,” “plans,” “believes,” “expects,” “anticipates,” “intends,”
“estimates,” “forecasts,” “budgets,” “targets” or other similar wording suggesting future outcomes or statements regarding an
outlook. We have based these forward-looking statements on our current expectations and projections about future events.
All statements, other than statements of historical fact, included in or incorporated by reference in this MD&A are
forward-looking statements.
Forward-looking statements include, without limitation, our business strategies and plans; plans for our exploration
(including drilling plans) and other business activities and results therefrom; characteristics of our properties; entering into
definitive agreements with our joint venture partners; the construction of proposed liquefaction facilities and condensate
stripping facilities in Papua New Guinea; the development of such liquefaction and condensate stripping facilities; the timing
and cost of such development; the commercialization and monetization of any resources; whether sufficient resources will be
established; the likelihood of successful exploration for gas and gas condensate or other hydrocarbons; re-commissioning of
our CRU; cash flows from operations; sources of capital and its sufficiency; operating costs; contingent liabilities;
environmental matters; and plans and objectives for future operations; the timing, maturity and amount of future capital and
other expenditures.
Many risks and uncertainties may affect the matters addressed in these forward-looking statements, including but not limited
to:
• our ability to finance the development of liquefaction
and condensate stripping facilities;
• our ability to negotiate definitive agreements
following conditional agreements or heads of
agreement relating to the development of liquefaction
and condensate stripping facilities, or to otherwise
negotiate and secure arrangements with other entities
for such development and the associated financing
thereof;
• the uncertainty associated with the availability, terms
and deployment of capital;
• 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;
• our ability to obtain and maintain necessary permits,
concessions, licenses and approvals from relevant
PNG government authorities to develop our gas and
condensate resources and to develop liquefaction
and condensate stripping facilities within reasonable
time periods and upon reasonable terms;
• the inherent uncertainty of oil and gas exploration
activities;
• the availability of crude feedstock at economic rates;
• the uncertainty associated with the regulated prices
at which our products may be sold;
• difficulties with the recruitment and retention of
qualified personnel;
• losses from our hedging activities;
25

• fluctuations in currency exchange rates;
• political, legal and economic risks in Papua New
Guinea;
• landowner claims and disruption;
• compliance with and changes in Papua New Guinean
laws and regulations, including environmental laws;
• the inability of our refinery to operate at full capacity;
• the impact of competition;
• the adverse effects from importation of competing
products contrary to our legal rights;
• the margins for our products and adverse effects on
the value of our refinery;
• inherent limitations in all control systems, and
misstatements due to errors that may occur and not
be detected;
• exposure to certain uninsured risks stemming from our
operations;
• contractual defaults;
• interest rate risk;
• weather conditions and unforeseen operating hazards;
• general economic conditions, including any further
economic downturn, the availability of credit the European
sovereign debt credit crisis and the downgrading of United
States government debt;
• the impact of our current debt on our ability to obtain
further financing;
• risk of legal action against us and
• law enforcement difficulties.
Forward-looking statements and information are based on our current beliefs as well as assumptions made by, and
information currently available to, us concerning anticipated financial conditions and performance, business prospects,
strategies, regulatory developments, the ability to attract joint venture partners, future hydrocarbon commodity prices, the
ability to secure adequate capital funding, the ability to obtain equipment in a timely manner to carry out development
activities, the ability to market products successfully to current and new customers, the effects from increasing competition,
the ability to obtain financing on acceptable terms, and the ability to develop reserves and production through development
and exploration activities. Although we consider these assumptions to be reasonable based on information currently available
to us, they may prove to be incorrect.
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions
could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements will eventuate. In light of the
significant uncertainties inherent in our forward-looking statements, the inclusion of such information should not be regarded
as a representation by us or any other person that our objectives and plans will be achieved. Some of these and other risks
and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully
described under the heading “Risk Factors” in our 2011 Annual Information Form.
Furthermore, the forward-looking information contained in this MD&A is made as of the date hereof, unless otherwise
specified and, except as required by applicable law, we will not update publicly or to revise any of this forward-looking
information. The forward-looking information contained in this report is expressly qualified by this cautionary statement.
Oil and Gas Disclosures
We are required to comply with Canadian Securities Administrators’ National Instrument 51-101 Standards for Disclosure
of Oil and Gas Activities (“NI 51-101”), which prescribes disclosure of oil and gas reserves and resources. GLJ Petroleum
Consultants Ltd., an independent qualified reserve evaluator based in Calgary, Canada, has evaluated our resources data as
at December 31, 2011 in accordance with NI 51-101, which evaluation is summarized in our 2011 Annual Information Form
available at www.sedar.com. We do not have any production or reserves, including proved reserves, as defined under NI
51-101 or as per the guidelines set by the United States Securities and Exchange Commission (“SEC”), as at December 31,
2011.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, possible and probable reserves
that a company has demonstrated by actual production or conclusive formation tests to be economically and legally
producible under existing economic and operating conditions. We include in this MD&A information that the SEC’s guidelines
generally prohibit U.S registrants from including in filings with the SEC.
26

All calculations converting natural gas to crude oil equivalent have been made using a ratio of six thousand cubic feet of
natural gas to one barrel of crude equivalent. Barrels of oil equivalent may be misleading, particularly if used in isolation. A
barrel of oil equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil equivalent is based
on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency
at the wellhead.
Resources
We currently have no production or reserves as defined in NI 51-101 or under the definitions established by the United States
Securities and Exchange Commission.
The Elk and Antelope gas and gas condensate fields (see “Description of Our Business”), located in Papua New Guinea and
contained within PRL 15, are reservoired in a composite trap comprising structural and stratigraphic elements consisting of
a Late Oligocene to Late Miocene limestone and carbonate. The Elk field overlies the northern end of the Antelope field and
comprises a tectonic wedge, or over thrust, of highly fractured deep water limestone and has been penetrated by the Elk-1
and Elk-2 wells. The Antelope field has been penetrated by the Antelope-1 and Antelope-2 wells and the reservoir consists of
a dominantly shallow water reef/platform complex with a dolomite cap with well developed secondary porosity and
permeability.
An evaluation of the resources of gas and condensate for the Elk and Antelope fields has been completed by GLJ Petroleum
Consultants Ltd. (“GLJ”), an independent qualified reserves evaluator, as of December 31, 2011, and was prepared in
accordance with the definitions and guidelines in the COGE Handbook and NI 51-101. All resources estimated for the Elk and
Antelope fields are classified as contingent resources – economic status undetermined as follows:
Gross Contingent Resources Estimate for Gas and Condensate*
As at December 31, 2011
Case
Low Best High
Initial Recoverable Sales Gas (tcf) 6.47 8.59 10.44
Initial Recoverable Condensate (mmbbls) 105.3 128.9 151.4
Initial Recoverable (mmboe) 1,183.6 1,560.4 1, 891.1
* These estimates represent 100% of the Elk and Antelope fields. InterOil currently has a 97.5% working interest in the Elk and Antelope fields.
Contingent Resource Estimate for Gas and Condensate – Net to InterOil*
As at December 31, 2011
Case
Low Best High
Initial Recoverable Sales Gas (tcf) 3.79 5.03 6.12
Initial Recoverable Condensate (mmbbls) 61.7 75.5 88.7
Initial Recoverable (mmboe) 693.6 914.4 1,108.1
* These estimates are based upon InterOil holding a 58.5988% working interest in the Elk and Antelope fields, which assumes that: (i) the State and landowners
elect to participate in the Elk and Antelope fields to the full extent provided under applicable PNG oil and gas legislation after a PDL has been granted in relation
to the Elk/Antelope field and (ii) all elections are made to participate in the Field by all investors pursuant to relevant indirect participation interest agreements with
InterOil, including to participate fully and directly in the PDL.
Contingent resources are those quantities of natural gas and condensate estimated, as of a given date, to be potentially
recoverable from known accumulations using established technology or technology under development, but which are not
currently considered to be commercially recoverable due to one or more contingencies. The economic status of the
resources is undetermined and there is no certainty that it will be commercially viable to produce any portion of
the resources. The following contingencies must be met before the resources can be classified as reserves:
• Sanctioning of the facilities required to process and
transport marketable natural gas to market.
• Determination of economic viability.
• Confirmation of a market for the marketable natural
gas and condensate.
27

Although a final project has not yet been sanctioned, pre-FEED studies are ongoing for the LNG Project and FEED studies
conducted for the CS Project as options for potential monetization of the gas and condensate.
The “low” estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that
the actual remaining quantities recovered will exceed the low estimate. With the probabilistic methods used, there should be
at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. The “best”
estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the
actual remaining quantities recovered will be greater or less than the best estimate. With the probabilistic methods used, there
should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
The “high” estimate is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that
the actual remaining quantities recovered will exceed the high estimate. With the probabilistic methods used, there should be
at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
The accuracy of resource estimates are in part a function of the quality and quantity of the available data and of engineering
and geological interpretation and judgment. Other factors in the classification as a resource include a requirement for more
delineation wells, detailed design estimates and near term development plans. The size of the resource estimate could be
positively impacted, potentially in a material amount, if additional delineation wells determined that the aerial extent, reservoir
quality and/or the thickness of the reservoir is larger than what is currently estimated based on the interpretation of the
seismic and well data. The size of the resource estimate could be negatively impacted, potentially in a material amount, if
additional delineation wells determined that the aerial extent, reservoir quality and/or the thickness of the reservoir are less
than what is currently estimated based on the interpretation of the seismic and well data.
Introduction
We are developing a fully integrated energy company operating in Papua New Guinea and the surrounding Southwest Pacific
region. Our operations are organized into four major segments:
Segments
Upstream
Midstream
Downstream
Corporate
Operations
Exploration and Production – Explores, appraises and develops crude oil and natural gas structures in Papua
New Guinea. Currently developing infrastructure for the Elk and Antelope fields which includes condensate
stripping and associated facilities, and the gas gathering and associated facilities, in connection with
commercializing gas discoveries. This segment also manages our construction business which services the
development projects underway in Papua New Guinea.
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.
Wholesale and Retail Distribution - Markets and distributes refined products domestically in Papua New
Guinea on a wholesale and retail basis.
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. This segment also manages our
shipping business which currently operates two vessels transporting petroleum products for our
Downstream segment and external customers, both within PNG and for export in the South Pacific region. Our
corporate segment results also include consolidation adjustments.
Business Strategy
Our strategy is to develop a vertically integrated energy company in Papua New Guinea and the surrounding region, focusing
on niche market opportunities which provide financial rewards for our shareholders, while being environmentally responsible,
providing a quality working environment and contributing positively to the communities in which we operate. A significant
current element of that strategy is to develop gas liquefaction and condensate stripping facilities in Papua New Guinea and to
establish gas and gas condensate reserves. InterOil plans to achieve this strategy by:
•
•
•
Developing our position as a prudent and responsible
business operator;
Maximizing the value of our exploration assets;
Monetizing our discovered resources;
• Enhancing our existing refining and distribution
businesses; and
• Positioning for long term success.
Further details of our business strategy can be found under the heading “Business Strategy” in our 2011 Annual
Information Form available at www.sedar.com.
28

Operational Highlights
A summary of the key operational matters and events for the year, for each of the segments is as follows:
Upstream
• The PPL 236 phase 1 exploratory seismic data acquisition program, which included 70 kilometers with six dip lines
transecting the Whale, Tuna, Barracuda, Wahoo, Mako and Shark prospects, was completed during the first quarter
of 2011. Processing and interpretation of this first phase of seismic data has been completed, and the Wahoo/Mako
leads (PPL 236) and the Tuna lead (PPL 236 and PPL 238) have been selected for follow up. Subsequently the
Kwalaha seismic data acquisition program was activated consisting of 56 kilometres and seven dip lines. Work
commenced on September 16, 2011 and was completed on December 20, 2011. The objective of the survey was to
further delineate the Wahoo and Mako prospects and identify potential drilling locations. Processing and
interpretation of the data is ongoing. A third phase of seismic data acquisition, which consists of two dip orientated
lines totaling 21 kilometres in length over the Tuna prospect, commenced on December 22, 2011. Line preparation is
currently in progress.
• The PPL 237 phase 3 Triceratops seismic acquisition program, which included four lines for a total of 50 kilometres,
was acquired between April and August 2011. This program increased our total seismic data acquisition over the area
to 140 kilometers in eleven lines. The objective of the program was to investigate the structure, seismic character, and
the aerial closure of the Triceratops field. Following the interpretation of the new seismic data, a review of the field was
completed and the conclusion reached that both the Bwata-1 and Triceratops-1 wells lay in the same zone, the same
pool and the same field. Subsequently, the field was renamed the Triceratops field. Following the mapping of the
seismic there has also been a review and increase in what we believe is the prospective size of the Triceratops field.
This potential increase is due to increased size of the closure and the identification of several potential shallow marine
reefal carbonate build ups.
• The preparation of the Triceratops 2 well site was completed at the end of 2011 and the Triceratops 2 well was
spudded on January 15, 2012. The Triceratops 2 well is an appraisal well to test the presence of hydrocarbons and
determine whether a potential reefal carbonate reservoir exists in the Triceratops field.
• During 2011, we contracted for airborne magnetic, gravity and gamma ray prospecting over PPL 236, PPL 237 and
PPL 238. Five acquisition blocks were acquired for a total of 14,288 line kilometers of airborne data. Data processing
over this airborne data is currently undergoing final quality control assessment.
• During 2011, the FEED work was carried out on Condensate Stripping Project. The FEED phase generated
deliverables to technically and commercially define the project and prepare it for execution (detailed engineering,
procurement, construction, fabrication, commissioning, and hand-over to operations) and proposals were solicited
from potential Engineering, Procurement and Construction (“EPC”) contractors. We are continuing the planning and
preparation efforts for Condensate Stripping Project execution which includes preparing a detailed project execution
plan, execution schedule and risk assessment work. At the end of 2011, agreement was reached with Mitsui to extend
the target date for FID on the CSP Project until March 31, 2012, which has been extended from the previously
disclosed targeted date of December 31, 2011 to be realigned with the targeted FID dates for our LNG Project.
• In June 2011, our Board of Directors approved capital expenditures on certain critical steel infrastructure ahead of FID
on our LNG Project in order to help preserve the proposed schedule and take advantage of advantageous steel
pricing. Total expenditure of up to $100.0 million was authorized for condensate and processed gas line pipe, and
other required items with long lead times.
• At the end of 2011, we agreed with Petromin that the Investment Agreement we entered into in 2008 was no longer
valid or intended to operate and should terminate. The agreement provided for Petromin to take a direct interest in the
Elk and Antelope fields and fund 20.5% of the costs of their development, if certain conditions were met. Petromin
remains the State’s nominee to acquire this interest under relevant Papua New Guinean’s legislation, once a PDL is
granted. We have proposed to Petromin that cash contributions made by Petromin under the Agreement to fund
development, amounting to approximately $15.4 million, be held and credited against the State’s obligation to refund
its portion of such costs upon grant of the PDL.
Midstream – Refining
• Total refinery throughput for the year ended December 31, 2011, was 24,856 barrels per operating day, compared with
29

24,682 barrels per operating day during 2010.
• Capacity utilization of the refinery for 2011, based on 36,500 barrels per day operating capacity, was 54% compared
with 53% in 2010. During the years ended December 31, 2011 and 2010, our refinery was shut down for 82 days and
81 days respectively.
• The catalytic reformer unit (“CRU”), which allows the refinery to produce reformate for gasoline, remained shut down
through the year due to technical operating issues. As a result, we were required to import unleaded gasoline to satisfy
PNG’s domestic needs. It is anticipated that the CRU will be re-commissioned and returned to service during 2012,
upon the successful conclusion of major maintenance and catalyst regeneration.
• During the year, a decommissioning provision of $4.1 million relating to the future retirement obligations associated with
the refinery was initially recognized. This decommissioning provision represents the net present value of the estimated
costs of future dismantlement, site restoration and abandonment of properties based upon regulations and economic
circumstances. This provision balance as at December 31, 2011 was $4.6 million.
• In June 2011, OPIC signed agreements agreeing to release all of the sponsor support collateral and requirements for
the loan granted to us in 2001 in recognition of our financial and operational maturity.
• On May 23, 2011, the BNP Paribas working capital facility agreement was amended to allow a $10.0 million increase
in the facility limit. Total facility limit stood at $230.0 million subsequent to its amendment. In November 2011, our
Midstream working capital facility with BNP Paribas was increased temporarily by $30.0 million to $260.0 million till
January 31, 2012, and reverting back to $230.0 million on that date. Subsequent to the year end, the facility has been
extended and further amended in February 2012 with the allowance of a further $10.0 million increase in the facility limit
to $240.0 million until January 31, 2013.
Midstream – Liquefaction
• On February 2, 2011, we signed a Project Funding and Construction Agreement and Shareholder Agreement with
Energy World Corporation Limited (“EWC”) governing the parameters in respect of the development, construction,
financing and operation of the planned 3 mtpa land based modular LNG plant in the Gulf Province of Papua New
Guinea. The agreements with EWC, as amended, contemplate the negotiation of further definitive agreements and are
conditional on reaching FID to proceed with the LNG plant no later than March 31, 2012.
• On April 11, 2011, we and Pac LNG entered into certain conditional framework agreements with FLEX LNG and
Samsung Heavy Industries for the proposed construction of a 1.8 mtpa or 2 mtpa fixed-floating liquefied natural gas
vessel. The framework agreements provided that the parties were to undertake project specific FEED work and
negotiate final binding agreements in time for a FID decision in mid-December 2011. Project specific FEED work was
carried out. However, as FID was not reached by mid-December 2011, these framework agreements with FLEX LNG
and Samsung lapsed and were not extended. We are continuing to negotiate with FLEX LNG. Under the framework
agreement we entered into with FLEX LNG, an equity purchase option was granted to us to acquire common shares
in FLEX LNG at an average strike price of 4.5909 Norwegian Kroner. On May 16, 2011, this option was exercised, with
our acquisition of 8,938,913 common shares of FLEX LNG at a cost of $7.5 million.
• During the year, site-specific engineering for the land based modular LNG and fixed-floating LNG facilities were
undertaken along with other pre-investment in the LNG Project to lower bidder risks and to secure our LNG Project
timeline and costs.
• On August 1, 2011, Rt. Hon Sir Rabbie Namaliu, former Prime Minister and former Petroleum and Energy Minister of
Papua New Guinea, joined us to chair our PNG Advisory Board. The PNG Advisory Board is a management group
formed to assist us in discussions with government departments in developing the LNG Project.
• On August 3, 2011, we signed a Heads of Agreement with Noble Clean Fuels Limited, a wholly owned subsidiary of
Noble Group Limited, for the supply of one mtpa of LNG per annum from the LNG Project for a ten year period
beginning in 2014. Definitive, binding agreements are currently being negotiated.
• The PNG government’s Minister for Petroleum and Energy and the Secretary of his department issued certain press
releases and correspondence during 2011 asserting that our development of the LNG Project may not, were it to
continue without amendment to its current form, be in compliance with the terms of the LNG Project Agreement signed
with the State in December 2009, and would not be approved by the State. We have provided appropriate assurances
to the PNG government in relation to the development of this Project and are continuing to work with the PNG
30

government and its relevant departments in relation to our development plans for the Elk and Antelope fields and the
LNG Project. Additionally, the constitution of the PNG government became a matter of dispute during 2011 and
remains so. National elections are due to take place in mid-2012.
• In September 2011, we retained Morgan Stanley & Co.LLC, Macquarie Capital (USA) Inc. and UBS AG as joint financial
advisors to assist us with soliciting and evaluating proposals from potential strategic partners. We anticipate that these
proposals will relate to obtaining an internationally recognized LNG operating and equity partner for development of the
LNG Project’s gas liquefaction and associated facilities in the Gulf Province of Papua New Guinea, and may include a
sale of an interest in the Elk and Antelope fields, and in our other exploration tenements in Papua New Guinea. No
assurances can be given that we will be able to attract strategic partners on terms acceptable to us, how such an
agreement will affect our current LNG Project plans or whether such a partner will be acceptable to the PNG
government.
• On November 25, 2011, a Heads of Agreement was signed with Gunvor Singapore Pte. Ltd. for the supply of one
mtpa of LNG from the LNG Project in Papua New Guinea. Definitive binding agreements are currently being
negotiated.
• On December 2, 2011, a further Heads of Agreement was signed with ENN Energy Trading Company Ltd of China, for
the supply of one to one and one half mtpa of LNG from the LNG Project. The Heads of Agreement, while not binding,
provides exclusivity on the LNG volumes, during negotiation of the definitive agreement, and set out the basis upon
which the parties intend to negotiate and document terms for the purchase and sale of LNG, for a period of 15 years,
commencing in 2015.
Downstream
• In 2011, we signed supply agreements with several key contractors and sub-contractors associated with the Exxon
Mobil LNG project, Papua New Guinea’s largest resource project to date. In addition, we re-signed all existing major
customers in the agricultural, commercial and aviation sectors to further three year term supply agreements.
• Year on year, sales volumes for 2011 were 678.0 million liters and were up by 51.5 million liters, or 8.2%, on the 2010
volumes of 626.5 million liters.
• Our retail business accounted for approximately 13% of our total downstream sales in 2011. Investments were made in
2010 and 2011 in new electronic systems for both pumps and the forecourt control units to support the further
development of this business.
• On December 8, 2011, the ICCC advised that margins for wholesale will increase in line with the ICCC mandated
formula for a five year period. A CPI increase of 7% is reflected in these revised margins. These increases apply to
unleaded gasoline, diesel and kerosene and are effective for the fiscal year ending December 31, 2012.
• Subsequent to year end in February 2012, Westpac working capital facility was increased by $4.7 million (PGK 10.0
million) bringing the total Downstream working capital facility to $65.3 million (PGK 140.0 million). In addition, a
secured loan of $15.0 million was provided by Westpac which is repayable in equal installments over 3.5 years with an
interest rate of LIBOR + 4.4% per annum.
Corporate
• The shipping business, which operates two vessels transporting petroleum products for us and external customers
both within PNG and for export in the South Pacific region, was transferred from our Downstream business segment to
Corporate during the year.
31

Selected Annual Financial Information and Highlights
Consolidated – Operating results Year ended December 31,
($ thousands, except per share data) 2011 2010 2009
Sales and operating revenues 1,106,534 802,374 688,479
Interest revenue 1,356 151 351
Other non-allocated revenue 11,058 4,470 4,228
Total revenue 1,118,948 806,995 693,058
Cost of sales and operating expenses (1,020,932) (701,557) (601,983)
Office and administration and other expenses (52,793) (52,650) (44,894)
Derivative gain/(loss) 2,006 (1,065) 1,009
Exploration costs (18,435) (16,982) (209)
Gain on sale of oil and gas properties assets - 2,141 7,364
Loss on extinguishment of IPI liability - (30,569) (31,710)
Litigation settlement expense - (12,000) -
Loss on Flex LNG Investment (3,420) - -
Foreign exchange gain/(loss) 25,019 (10,777) (3,305)
EBITDA (1) 50,393 (16,464) 19,330
Depreciation and amortization (20,137) (14,275) (14,322)
Interest expense (13,333) (7,364) (9,993)
Profit/(loss) before income taxes 16,923 (38,103) (4,985)
Income tax benefit/(expense) 736 (6,410) 11,076
Net profit/(loss) 17,659 (44,513) 6,091
Net profit/(loss) per share (dollars) (basic) 0.37 (1.00) 0.15
Net profit/(loss) per share (dollars) (diluted) 0.36 (1.00) 0.15
Total assets 1,088,355 975,743 631,754
Total liabilities 328,464 272,841 189,764
Total long-term liabilities 128,072 130,323 96,225
Gross margin (2) 85,602 100,817 86,496
Cash flows generated from/(used in) operating activities (3) 62,670 (13,561) 44,500
•
•
•
•
EBITDA, is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”.
Gross margin is a non-GAAP measure and is “sales and operating revenues” less ”cost of sales and operating expenses” and is reconciled to IFRS in the
section to this document entitled ”Non-GAAP Measures and Reconciliation”.
Refer to “Liquidity and Capital Resources – Summary of Cash Flows” for detailed cash flow analysis.
The 2009 selected financial information was prepared in accordance with the Company’s former GAAP, and has not been restated in accordance with
IFRS.
Analysis of Financial Condition Comparing Years Ended December 31, 2011, 2010 and 2009
During the year ended December 31, 2011, our debt-to-capital ratio (being debt/[shareholders’ equity + debt]) was 12%
(13% as at December 31, 2010 and 11% as at December 31, 2009), well below our targeted maximum gearing level of 50%.
Gearing targets are based on a number of factors including operating cash flows, future cash needs for development, capital
market conditions, economic conditions, and are assessed regularly.
Our current ratio (being current assets/current liabilities), which measures our ability to meet short term obligations, was 2.1
times as at December 31, 2011 (3.2 times as at December 31, 2010 and 2.2 times as at December 31, 2009). The quick
ratio (or acid test ratio, (being [current assets less inventories]/current liabilities)) which is a more conservative measure of our
ability to meet short term obligations, was 1.3 times as at December 31, 2011 (2.3 times as at December 31, 2010 and 1.5
times as at December 31, 2009). These ratios satisfy our internal targets to be above 1.5 times for the current ratio and 1.0
times for the quick ratio.
As at December 31, 2011, our total assets amounted to $1,088.4 million, compared with $975.7 million as at December 31,
2010 and $631.8 million as at December 31, 2009. The increase of $112.7 million or 11.5% from December 31, 2010 was
primarily due to increases in the value of our oil and gas properties of $107.6 million associated with the appraisal and of
the Elk and Antelope fields, preparation for drilling the Triceratops 2 well, and continued development of the LNG Project; an
increase in inventory balances and trade receivable balances of $43.9 million and $87.2 million respectively due to higher
32

working capital needs on higher average crude prices during the current period; a net $20.8 million increase in plant and
equipment (after depreciation) from capitalization of refinery asset retirement obligations, tank upgrades, camp and office
building works, and new business system implementation costs; $7.5 million increase in deferred tax benefits mainly due to
the temporary difference arising on foreign exchange translation of non-monetary assets of the refinery operation; and $3.7
million for our investment in shares in FLEX LNG. These increases were offset by net decreases in our cash, cash equivalents,
cash restricted, and short term treasury bills of $160.9 million, due primarily to expenditure on development of our oil and gas
properties. The increase in total assets of $344.0 million or 54.4% from December 31, 2009 to December 31, 2010 was due
primarily to a $187.1 million increase in cash and cash equivalents following the concurrent common share and convertible
notes offerings, increases in our oil and gas properties of $82.8 million associated with the appraisal and development of the
Elk and Antelope fields and furthering of the Condensate Stripping Project and LNG Project, and an increase in inventory
balances of $57.0 million at our refinery due to the timing of shipments.
As at December 31, 2011, our total liabilities amounted to $328.5 million, compared with $272.8 million at December 31,
2010 and $189.8 million as at December 31, 2009. The increase of $55.7 million or 20.4% from December 31, 2010 was
primarily due to an increase in accounts payable and accrued liabilities of $84.7 million, offset in part by a reduction of $34.8
million in the working capital facility which is mainly a function of timing of crude purchases for the refining operation. The
increase in liability of $83.0 million or 43.7% as at December 31, 2010 from December 31, 2009 was primarily due to the
recognition of a $52.4 million liability relating to the fair value of the debt component of the unsecured 2.75% convertible notes
issuance in November 2010 and an increase in the working capital facility balance of $26.6 million.
Analysis of Consolidated Financial Results Comparing Years and Quarters Ended December 31, 2011, 2010 and 2009
Annual Comparative
Net profit for the year ended December 31, 2011 was $17.7 million compared with a net loss of $44.5 million for the same
period in 2010, an improvement of $62.2 million. The operating segments of Corporate, Midstream Refining and Downstream
collectively returned a net profit for the year of $82.3 million. The development segments of Upstream and Midstream
Liquefaction yielded a net loss of $64.6 million.
The main items contributing towards the loss in 2010 were unusual, one time charges including a loss on extinguishment of
IPI liability of $30.6 million and a $12.0 million expense relating to settlement of certain long-standing litigation.
Total revenues for the year ended December 31, 2011 were $1,118.9 million compared with $807.0 million and $693.1 million
respectively for the same periods in 2010 and 2009. This increase in the year ended 2011 compared to the same period in
2010 was due to the higher crude price environment in the 2011 year and an increase in domestic volumes of product sold
for higher margin products. The total volume of all products sold by us was 7.5 million barrels for fiscal year 2011, compared
with 7.2 million barrels in 2010 and 6.5 million barrels in 2009.
EBITDA for the year ended December 31, 2011 was $50.4 million, an increase of $66.9 million over negative EBITDA of $16.5
million for the same period in 2010, mainly due to the unusual, one time charges in 2011 as detailed above. The current year
also had an improvement in our net foreign exchange gain/loss for the year of $35.8 million compared to the prior period as a
result of rising Papua New Guinea Kina (“PGK”) against USD.
The Upstream segment realized a net loss of $49.1 million in 2011 (2010 – loss of $78.6 million, 2009 – loss of $39.5 million).
The reduction in the loss in 2011 by $29.4 million from 2010 was mainly due to one-time events in the prior year of $30.6
million loss on extinguishment of IPI liability and $2.1 million gain on sale of oil and gas properties. During 2011, there has
been an increase of $11.5 million on intercompany interest charges due to higher loan balances from the parent entity
(Corporate segment) to fund the exploration activities. This increase has been offset by a $8.6 million reduction in office and
administration expenses as more expenses have been capitalized (mainly relating to rig expenditure associated with mud
corrosion caused during the drilling of Antelope 2 well, and expenditure associated with rig standby on Triceratops 2 well
drilling due to delays in finalization of the location of the well and weather associated delays), and a $6.5 million increase in
other revenue driven by higher recovery of construction and related equipments on their better utilization during the period on
LNG Project related civil works and related infrastructure development. The increase in the loss in 2010 by $39.1 million from
2009 was mainly due to a $16.8 million increase in exploration costs relating to the Triceratops field and Wolverine seismic,
$9.2 million higher intercompany interest charges, and a $5.2 million reduction in the gain on sale of exploration assets in
2010 compared to 2009 as the prior year included conveyance accounting on the IPI agreement for conversion rights waived
by certain IPI investors.
The Midstream Refining segment generated a net profit of $46.7 million in 2011 (2010 - $33.5 million, 2009 - $41.8 million)
mainly on account of a $34.0 million increase in foreign exchange gains as a result of rising PGK against USD, a $7.5 million
33

improvement to income tax expense arising primarily from the temporary differences due to translation of the non-monetary
assets held by the Refinery using period end rates, and a $3.6 million increase in derivative gains. These increases have been
partly offset by lower gross margins (a decrease of $27.1 million from 2010) due primarily to lower crack spreads, and a $3.1
million increase in interest expense charged on higher loan balances from the parent entity. The net profit in 2010 decreased
from 2009 mainly on account of the initial recognition of $14.3 million of deferred tax assets in 2010.
The Midstream Liquefaction segment had a net loss of $15.5 million during the 2011 year (2010 – loss of $8.4 million, 2009
– loss of $8.4 million) resulting from higher management expenses and share compensation costs related to the LNG Project
development which are not capitalized. As the LNG Project Agreement was signed by the Government of Papua New Guinea
in December 2009, all direct project related costs since that date have been capitalized to the project rather than expensed.
The Downstream segment generated a net profit of $11.6 million in 2011 (2010 – profit of $6.7 million, 2009 – profit of $8.5
million). The increased profit was mainly due to a $5.6 million improvement in gross margins due to an increase in domestic
volumes resulting from various development projects being undertaken in Papua New Guinea, the positive impact from the
revised pricing formula that came into effect in late 2010 following the ICCC’s review of wholesale, distribution and retail
margins set by the PNG State for the petroleum industry, and the impact of the increasing price environment during the period
leading to higher margins on inventories sold. This improvement in gross margins has been partly offset by a $1.2 million
increase in depreciation and amortization on capital purchases related primarily to office refurbishment and upgrade
projects across various terminals and depots. The decreased profit in 2010 compared to 2009 was mainly due to a $3.0
million increase in office and administration expenses, a $2.0 million increase in foreign exchange loss and a $1.7 million
increase in income tax expense offset in part by a $4.6 million improvement in gross margin.
The Corporate segment generated a net profit of $21.9 million (2010 – profit of $3.3 million, 2009 – loss of $4.3 million). The
2010 results included a $12.0 million settlement expense to finalize certain long-standing litigation, and a $14.2 million
increase in interest charges to other business segments on increased loan balances. These expenses have been partly offset
by a $4.5 million increase in interest expense due to the 2.75% convertible notes issued on November 10, 2010 and a $3.4
million impairment loss on our investment in shares in Flex LNG held by us as part of the framework agreements entered into
with FLEX LNG and Samsung Heavy Industries in April 2011.
Quarterly Comparative
The net profit for the quarter ended December 31, 2011 was $13.2 million compared with a loss of $34.8 million for the same
quarter of 2010, an improvement of $48.0 million. This movement was mainly due to a $21.8 million loss on extinguishment of
IPI liability in the prior year quarter in relation to a 1.0% IPI interest buyback, an $11.8 million reduction in expensed
exploration costs on lower seismic activity, a $10.5 million increase in foreign exchange gains, and an $18.7 million
improvement in income tax expense primarily from the impact of foreign exchange movements impacting temporary
differences on translation of the nonmonetary assets of the refinery operation using period end rates. These gains have been
offset in part by an $18.3 million reduction in gross margin for the quarter due primarily to decreased export product crack
spreads and the impact of both the CRU and Crude Distillation Unit (“CDU”) being shut down.
The operating segments of Corporate, Midstream Refining and Downstream collectively derived a net profit for the fourth
quarter of $27.2 million, while the development segments of Upstream and Midstream Liquefaction had a net loss of $14.0
million, for an aggregate net profit of $13.2 million.
Total revenues increased by $95.2 million from $194.4 million in the quarter ended December 31, 2010 to $289.6 million in
the quarter ended December 31, 2011 primarily due to higher volumes and prices during the quarter. The total volume of all
products sold by us was 1.9 million barrels for quarter ended December 2011, compared with 1.6 million barrels in the same
quarter of 2010.
Variance Analysis
A complete discussion of each of our business segments’ results can be found under the section ”Year and Quarter in
Review”. The following analysis outlines the key variances, the net of which are the primary explanations for the changes in
the consolidated results between the years and quarters ended December 31, 2011 and 2010.
34

Yearly
Variance
($ millions)
Quarterly
Variance
($ millions)
$62.2 $48.0 Net profit/(loss) variance for the comparative periods primarily due to:
($15.2) ($18.3) Reduction in gross margin for the year driven by increase in crude costs, decreases in export product
crack spreads and reduced demand for export products, offset by volume increases and improved
margins in the domestic market.
$6.6 $1.5 Increase in other non-allocated revenue due to better utilization of construction and related equipment on
civil works and related infrastructure development associated with the LNG Project.
($0.1) $4.9 Decrease in office and administration and other expenses in the current quarter on higher capitalization of
expenses (mainly relating to rig expenditure associated with corrosion caused by drilling mud, and
expenditure associated with rig standby on the Triceratops 2 well drilling due to delays in finalization of the
location of the well and weather associated delays).
$3.1 $1.4 Movement in gains from derivative contracts that were not accounted for as hedge accounted contracts.
($1.5) $11.8 Higher exploration costs for seismic activity on our licenses PPL 236, 237 and 238 during the year. The
majority of the seismic costs were incurred during the first three quarters of the current year and the fourth
quarter of 2010. These seismic costs were expensed as incurred.
$30.6 $21.8 Loss on extinguishment of IPI liability in 2010 in relation to the interest buyback of 1.4%, 1.0% of which
was purchased in the fourth quarter. There have been no such buybacks during 2011.
$12.0 - Litigation settlement expense in the third quarter of 2010 on settlement of the Todd Peters et al litigation for
which we issued 199,677 common shares to the plaintiffs valued at $12.0 million.
($3.4) ($1.6) Loss recognized on our investment in shares in FLEX LNG held by us as part of the framework agreements
entered into with FLEX LNG and Samsung Heavy Industries in April 2011.
$35.8 $10.5 The PGK strengthened against the USD from 0.3785 at the start of the year to 0.4665 as at December 31,
2011. We are currently holding more PGK cash balances in PNG to partly mitigate the risk of a rising PGK
which would affect exploration and development costs.
($5.9) ($2.0) Increase in depreciation expense mainly due to the depreciation of construction machinery which was
acquired over the last year, and the depreciation of the new ERP system.
($6.0) ($1.0) Higher interest expense for the quarter and year primarily due to higher utilization of our Midstream and
Downstream working capital facilities, and interest on the 2.75% convertible senior notes issued on
November 10, 2010.
$7.1 $18.7 Decrease in income tax expense for the year primarily from the impact of foreign exchange movements
impacting temporary differences on translation of the nonmonetary assets of the refinery operation using
period end rates.
Analysis of Consolidated Cash Flows Comparing Years and Quarters Ended December 31, 2011 and 2010
As at December 31, 2011, we had cash, cash equivalents, and cash restricted of $108.1 million (December 2010 – $280.9
million), of which $39.3 million (December 2010 - $47.3 million) was restricted. In addition, we also had $11.8 million
equivalent of PGK in short term treasury bills issued by the Bank of Papua New Guinea (December 2010 – nil). Of the total
cash restricted of $39.3 million, $33.0 million (December 2010 - $40.7 million) was restricted pursuant to the BNP Paribas
working capital facility utilization requirements, $5.9 million (December 2010 – $6.3 million) was restricted as a cash deposit
on the OPIC secured loan relating to our half yearly instalment of $4.5 million and the related interest that will be payable with
the next instalment on June 30, 2012, and the balance was made up of a cash deposit on office premises together with term
deposits on our PPLs.
Our cash inflows from operations for the year ended December 31, 2011 were $62.7 million compared with outflows of $13.6
million for the year ended December 31, 2010, a net increase in cash inflows of $76.3 million. This increase in cash inflows is
mainly due to a $26.2 million change in cash generated by operations prior to changes in operating working capital, related
to net profits generated from operations less any non-cash expenses for the year. There was also a $50.1 million decrease in
working capital associated with trade receivables, inventories and accounts payables.
Cash outflows for investing activities for the year ended December 31, 2011 were $204.2 million compared with $111.2
million for the year ended December 31, 2010. These outflows mainly relate to the net cash expenditure on exploration,
appraisal and development activities (net of IPI cash calls) of $134.1 million, expenditure on plant and equipment of $42.1
million, acquisition of FLEX LNG shares net of transaction costs of $7.5 million, investments in short term PGK treasury bills
of $11.8 million, a $10.0 million increase in trade receivables and a $6.7 million decrease in working capital requirements of
development segments relating to the timing of receipts and payments. These outflows were partly offset by a decrease of
$8.0 million in the restricted cash balance under the BNP Paribas working capital facility.
35

Cash outflows from financing activities for the year ended December 31, 2011 amounted to $27.2 million, compared with
$311.8 million inflows for the year ended December 31, 2010. These cash outflows include two repayments of the OPIC
secured loan of $9.0 million and $34.8 million repayments of the working capital facility. These outflows have been partly
offset by receipts of cash contributions from Mitsui for the Condensate Stripping Project of $9.9 million, receipts from PNG
LNG cash call of $2.2 million, and receipts of cash from the exercise of stock options of $4.5 million. The cash inflows /
outflows associated with the working capital facility drawdown/repayments are due to the timing of cash flows and the use of
working capital. The inflows from financing activities in the prior year relate primarily to the receipt of cash from the concurrent
common shares and 2.75% convertible notes offerings in November 2010.
Summary of Consolidated Quarterly Financial Results for Past Eight Quarters
The following is a table containing the consolidated results for the eight quarters ended December 31, 2011 by business
segment, and on a consolidated basis. Our IFRS transition date was January 1, 2010 and as such, the 2010 comparative
information in the table below has been restated in accordance with IFRS.
Quarters ended
($ thousands except per
share data)
2011 2010
Dec 31 Sept 30 June 30 March 31 Dec 31 Sept 30 June 30 March 31
Upstream 1,891 2,645 4,638 668 245 714 1,349 998
Midstream – Refining 237,640 231,455 262,111 217,743 158,092 173,379 194,016 152,093
Midstream – Liquefaction - - - - - - - -
Downstream 209,678 186,304 191,431 157,709 143,364 133,508 119,300 109,687
Corporate 21,831 25,078 26,548 18,659 15,213 18,295 11,321 12,093
Consolidation entries (181,428) (163,584) (180,945) (151,125) (122,545) (117,437) (100,637) (96,053)
Total revenues 289,612 281,898 303,783 243,654 194,369 208,459 225,349 178,818
Upstream 665 (6,169) 593 (10,957) (41,681) (11,753) (3,498) (1,964)
Midstream – Refining 2,604 3,461 27,967 26,632 13,780 15,785 16,962 4,402
Midstream – Liquefaction (4,123) (3,602) (4,035) (2,375) (1,959) (4,588) (3) (563)
Downstream 6,808 3,570 5,777 8,744 4,709 1,674 7,060 4,492
Corporate 10,134 1,548 13,940 5,223 4,566 (4,510) 1,751 4,402
Consolidation entries (11,280) (10,263) (5,270) (9,200) (7,004) (5,229) (7,384) (5,911)
EBITDA (1) 4,808 (11,455) 38,972 18,067 (27,589) (8,621) 14,888 4,858
Upstream (9,402) (15,080) (6,703) (17,949) (47,845) (16,585) (7,943) (6,182)
Midstream – Refining 15,684 (1,201) 17,314 14,894 9,504 11,998 12,056 (74)
Midstream – Liquefaction (4,574) (3,980) (4,309) (2,604) (2,114) (4,970) (360) (911)
Downstream 3,621 1,146 2,306 4,491 2,643 (325) 3,719 671
Corporate 7,616 (473) 11,275 3,463 3,381 (5,398) 1,796 3,544
Consolidation entries 252 (190) 3,657 (1,596) (401) 908 (1,435) (190)
Net profit/(loss) 13,197 (19,778) 23,540 699 (34,832) (14,372) 7,833 (3,142)
Net profit/(loss) per share (dollars)
Per Share – Basic 0.27 (0.41) 0.49 0.01 (0.76) (0.33) 0.18 (0.07)
Per Share – Diluted 0.27 (0.41) 0.48 0.01 (0.76) (0.33) 0.17 (0.07)
1 EBITDA is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”.
36

Year and Quarter in Review
The following section provides a review of the year and quarter ended December 31, 2011 for each of our business segments.
Upstream - Year and Quarter in Review
Upstream – Operating results
($ Thousands)
Year ended December 31,
2011 2010
Other non-allocated revenue 9,841 3,305
Total revenue 9,841 3,305
Office and administration and other expenses (5,122) (13,746)
Exploration costs (18,435) (16,982)
Gain on sale of oil and gas properties - 2,141
Loss on extinguishment of IPI liability - (30,569)
Foreign exchange loss (2,153) (3,044)
EBITDA (1) (15,869) (58,895)
Depreciation and amortization (3,255) (1,132)
Interest expense (30,013) (18,528)
Loss before income taxes (49,137) (78,555)
Income tax expense - -
Net loss (49,137) (78,555)
1 EBITDA is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”.
Analysis of Upstream Financial Results Comparing Year and Quarter Ended December 31, 2011 and 2010
The following analysis outlines the key movements, the net of which primarily explains the difference in the results between the
years and quarters ended December 31, 2011 and 2010.
Yearly Variance
($ millions)
Quarterly Variance
($ millions)
$29.4 $38.4 Net profit/(loss) variance for the comparative periods primarily due to:
$6.5 $1.6 Increase in other non-allocated revenue driven by higher recovery of construction and related
equipment charges on their better utilization during the period on LNG Project related civil works
and related infrastructure development. Recoveries in relation to our percentage interest of the
development projects are offset against the relevant expenses, while the recoveries of the portion
relating to external party interests in the development projects are classified under other
non-allocated revenue.
($1.5) $11.8 Higher exploration costs for seismic activity during the year on PPL 236. The majority of the
seismic costs were incurred during the first three quarters of 2011 and the fourth quarter of 2010.
These seismic costs were expensed as incurred under the successful efforts method of
accounting.
($2.1) - Gain recognized on the sale of our 15% interest in PPL 244 in the year ended December 31,
2010.
$30.6 $21.8 Loss on extinguishment of IPI liability in 2010 in relation to the buyback of IPI interests amounting
to 1.4%, 1.0% of which was purchased in the fourth quarter of 2010. There have been no such
buybacks during 2011.
$8.6 $7.0 Reduction in office and administration expenses as more expenses have been capitalized (mainly
relating to rig expenditure associated with corrosion caused by drilling mud, and expenditure
associated with rig standby on the Triceratops 2 well drilling due to delays in finalization of the
location of the well and weather associated delays).
($11.5) ($3.2) Higher interest expense due to an increase in inter-company loan balances provided to fund
exploration and development activities.
37

Midstream - Refining - Year and Quarter in Review
Midstream Refining – Operating results
($ thousands)
Year ended December 31,
2011 2010
External sales 362,606 298,071
Inter-segment revenue - Sales 576,672 376,066
Inter-segment revenue - Recharges 8,841 3,278
Interest and other revenue 831 166
Total segment revenue 948,950 677,581
Cost of sales and operating expenses (897,825) (605,603)
Office and administration and other expenses (18,939) (11,940)
Derivative gain/(loss) 2,018 (1,592)
Foreign exchange gain/(loss) 26,458 (7,518)
EBITDA (1) 60,662 50,928
Depreciation and amortization (11,254) (10,355)
Interest expense (9,664) (6,585)
Profit before income taxes 39,744 33,988
Income tax benefit/(expense) 6,946 (505)
Net profit 46,690 33,483
Gross Margin (2) 41,453 68,534
1 EBITDA is a non-GAAP measure and is reconciled to IFRS 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 – sales” less “cost of sales and operating expenses” and is
reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”.
Midstream - Refining Operating Review
Key Refining Metrics
Quarter ended December 31, Quarter ended December 31,
2011 2010 2011 2010
Throughput (barrels per day) (1) 24,644 21,550 24,856 24,682
Capacity utilization
(based on 36,500 barrels per day operating capacity)
50% 34% 54% 53%
Cost of production per barrel (2) $5.18 $3.66 $4.58 $2.84
Working capital financing cost per barrel of production (2) $0.76 $0.58 $0.73 $0.47
Distillates as percentage of production 57.1% 58.70% 57.5% 51.00%
1 Throughput per day has been calculated excluding shut down days. During 2011 and 2010, the refinery was shut down for 82 days and 81 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.
The increase in the cost of production per barrel for the current periods is mainly due to the depreciation of the USD against the PGK and AUD, the
currencies in which we incur our operating expenditures, and a general inflationary increase, higher personnel costs and system and IT upgrades performed
during the current periods.
During the second half of 2011, the PNG Customs Service commenced an audit of our petroleum product imports into Papua
New Guinea for the years 2007 to 2010. We received a letter in November 2011 from the then Commissioner of Customs
setting out certain findings from the audit. This letter included comments alleging that payment of import goods and services
taxes (“GST”) was required and had not been made on imports of certain refined products. As well as requiring payment of
GST, the letter noted that administrative penalties were able to be levied by Customs in the range of 50% to 200% of the
assessed amounts as per the PNG Customs Act. We have since met with the Customs Service and provided it with
supporting documentation to demonstrate that the GST amounts claimed in their letter have all been paid. We have currently
made a provision based on our best estimate in relation to this matter and are working closely with the authority to provide all
requested information in order to finalize the audit.
38

Analysis of Midstream - Refining Financial Results Comparing the Year and Quarter Ended December 31, 2011 and 2010
The following analysis outlines the key changes, the net of which primarily explains the variance in the results between the
years and quarters ended December 31, 2011 and 2010.
Yearly Variance
($ millions)
Quarterly Variance
($ millions)
$13.2 $6.2 Net profit/(loss) variance for the comparative periods primarily due to:
($27.1) ($19.9) Decrease in gross margin for the year mainly due to the following contributing factors:
- Decreases in export product crack spreads due to increase in crude costs and reduced
demand for export products
+ Increases in crude and product flat pricing over the year contributing to increased inventory
gains for all products
+ Better crude mix resulting in increased distillate yield percentage
$34.0 $8.0 Increase in foreign exchange gain due to the strengthening of the PGK against the USD. The PGK
strengthened against the USD from 0.3785 at the start of the year to 0.4665 as at December 31,
2011. As part of our foreign exchange risk management strategy, we have begun holding more
PGK cash balances in PNG to partly mitigate the risk of a rising PGK affecting our operations.
($1.4) ($0.8) Increase in office and administration costs net of recharge revenue for the year was driven by
higher salaries, wages and share compensation expenses, which were to a large extent impacted
by the strengthening of the PGK and Australian Dollar (“AUD”) against the USD during the period.
$3.6 $1.3 Movement in gains from derivative contracts that were not accounted for as hedge accounted
contracts.
($3.1) ($1.8) Increase in interest expense on higher utilization of the working capital facilities.
$7.5 $19.3 Decrease in income tax expense in 2011 primarily from the impact of foreign exchange
movements impacting temporary differences on translation of the nonmonetary assets of the
refinery operation using period end rates, offset by income tax expense on profits generated by
the operations.
Midstream - Liquefaction - Year and Quarter in Review
Midstream Liquefaction – Operating results
($ thousands)
Year ended December 31,
2011 2010
Interest and other revenue - 1
Total segment revenue - 1
Office and administration and other expenses (14,121) (7,023)
Foreign exchange loss (13) (90)
EBITDA (1) (14,134) (7,112)
Depreciation and amortization (26) (25)
Interest expense (1,308) (1,253)
Loss before income taxes (15,468) (8,390)
Income tax benefit - 36
Net loss (15,468) (8,354)
1 EBITDA is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”.
Analysis of Midstream - Liquefaction Financial Results Comparing the Year and Quarter Ended December 31, 2011
and 2010
This segment’s results include the proportionate consolidation of our interest in the joint venture development of the proposed
midstream facilities of the LNG Project. The development of these facilities is being progressed in joint venture with Pac LNG
through PNG LNG. We currently have an economic interest of 84.582% in this Joint Venture Company. This interest was
reduced from 86.66% in December 2011 following the receipt of cash calls from Pac LNG.
All costs incurred in connection with the LNG Project, subsequent to the execution of the shareholders’ agreement governing
the development of the midstream facilities of the LNG Project on July 31, 2007, and through the pre-acquisition and
feasibility stage have been expensed as incurred, unless they were directly identified as property, plant and equipment. Since
the execution of the LNG Project Agreement with the State in December 2009, all project-related direct costs have been
capitalized, other than overheads and other costs that are incurred in the normal course of running the business, which are
expensed.
39

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the
years and quarters ended December 31, 2011 and 2010.
Yearly Variance
($ millions)
Quarterly Variance
($ millions)
($7.1) ($2.5) Net profit/(loss) variance for the comparative periods primarily due to:
($7.7) ($3.1) Increase in office, administration and other expenses for the year due to higher management
expenses and share compensation costs related to the midstream facilities of the LNG Project
development which are not capitalized. The increases are the result of increased activities
undertaken to negotiate long term LNG offtake agreements, pre-feed work being undertaken for
the LNG Project’s proposed land based liquefaction and fixed-floating liquefaction facilities, and
also further the discussions with the State to achieve approvals.
$0.6 $0.6 Gain on proportionate consolidation of PNG LNG following a reduction in ownership from 86.66%
to 84.582% in December 2011.
Downstream - Year and Quarter in Review
Midstream Refining – Operating results
($ thousands)
Year ended December 31,
2011 2010
External sales 743,663 504,303
Inter-segment revenue - Sales 197 483
Interest and other revenue 1,263 1,072
Total segment revenue 745,123 505,858
Cost of sales and operating expenses (704,213) (470,772)
Office and administration and other expenses (15,780) (15,975)
Foreign exchange loss (229) (1,176)
EBITDA (1) 24,901 17,935
Depreciation and amortization (4,026) (2,787)
Interest expense (4,346) (3,739)
Profit before income taxes 16,529 11,409
Income tax expense (4,962) (4,701)
Net profit 11,567 6,708
Gross Margin (2) 39,647 34,014
1 EBITDA is a non-GAAP measure and is reconciled to IFRS 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 - sales” less “cost of sales and operating expenses” and is reconciled
to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”.
Downstream Operating Review
Key Refining Metrics
Quarter ended December 31, Quarter ended December 31,
2011 2010 2011 2010
Sales volumes (millions of liters) 187.7 170.2 678.0 626.5
Average sales price per liter (PGK) 2.43 2.07 2.55 2.19
Analysis of Downstream Financial Results Comparing the Year and Quarter Ended December 31, 2011 and 2010
The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the
years and quarters ended December 31, 2011 and 2010.
40

Yearly Variance
($ millions)
Quarterly Variance
($ millions)
$4.9 $1.0 Net profit/(loss) variance for the comparative periods primarily due to:
$5.6 ($0.1) Gross margins increased compared to the prior year mainly due to an increase in domestic sales
volumes resulting from various development projects being undertaken in Papua New Guinea, the
impact of the revised pricing formula that came into effect in late 2010, and the increasing price
environment during the period leading to higher margins on inventories sold.
$0.9 $1.8 Increase in foreign exchange gain due to the strengthening of the PGK against the USD. The PGK
strengthened against the USD from 0.3785 at the start of the year to 0.4665 as at December 31,
2011.
($1.2) ($0.7) Increase in depreciation and amortization expenses due to the impact of capital additions over the
past year related primarily to office refurbishment and upgrade projects across various terminals
and depots.
($0.6) ($0.3) Increase in interest expense due to the increased utilization of the working capital facility during the
year.
Corporate - Year and Quarter in Review
Corporate – Operating results
($ thousands)
Year ended December 31,
2011 2010
External sales 266 -
Inter-segment revenue - Sales 13,859 402
Inter-segment revenue - Recharges 39,503 32,162
Interest revenue 38,512 24,335
Other non-allocated revenue (23) 23
Total revenue 92,117 56,922
Cost of sales and operating expenses (11,421) -
Office and administration and other expenses (47,371) (40,291)
Derivative (loss)/gain (11) 527
Foreign exchange gain 954 1,051
Loss on Flex LNG investment (3,420) -
Litigation settlement expense - (12,000)
EBITDA (1) 30,848 6,209
Depreciation and amortization (1,706) (106)
Interest expense (6,012) (1,541)
Profit before income taxes 23,130 4,562
Income tax expense (1,248) (1,240)
Net profit 21,882 3,322
1 EBITDA is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”.
Analysis of Corporate Financial Results Comparing the Year and Quarter Ended December 31, 2011 and 2010
During 2011, our Corporate segment took over the management of our shipping business from Downstream operations. We
currently operate two vessels transporting petroleum products for our Downstream segment and external customers, both
within PNG and for export in the South Pacific region. External sales above relates to the shipping charges billed to external
customers, and inter-segment revenue - sales relates to shipping charges billed to our Downstream segment.
The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the
years and quarters ended December 31, 2011 and 2010.
41

Yearly Variance
($ millions)
Quarterly Variance
($ millions)
$18.6 $4.2 Net profit/(loss) variance for the comparative periods primarily due to:
$12.0 - One time litigation settlement expense in the prior year on account of the agreed settlement of the
Todd Peters et al litigation for which we issued 199,677 common shares to the plaintiffs.
($3.4) ($1.6) Loss recognized on our investment in shares in Flex LNG held by us as part of the framework
agreements entered into with FLEX LNG and Samsung Heavy Industries in April 2011. As per the
guidance under IFRS, an impairment loss has to be recognized in the income statement if
reduction in fair value of the investment is evidenced by significant or prolonged declined in the fair
value of the investment.
$9.7 $4.6 Reduced interest expenses (net of recharged intercompany interest revenue from other segments)
due to higher interest charges to other business segments on increased loan balances.
($0.1) $0.6 Movement in foreign exchange gain mainly in relation to the strengthening of the AUD and SGD
against the USD.
Consolidated Adjustments - Year and Quarter in Review
Consolidation adjustment – Operating results
($ thousands)
Year ended December 31,
2011 2010
Inter-segment revenue - Sales (590,729) (376,951)
Inter-segment revenue - Recharges (48,344) (35,440)
Interest revenue (5) (38,010) (24,281)
Other non-allocated revenue - -
Total revenue (677,083) (436,672)
Cost of sales and operating expenses (1) 592,527 374,818
Office and administration and other expenses (2) 48,541 36,325
EBITDA (3) (36,015) (25,529)
Depreciation and amortization (4) 130 130
Interest expense (5) 38,010 24,282
Profit/(loss) before income taxes 2,125 (1,117)
Income tax expense - -
Net profit/(loss) 2,125 (1,117)
Gross Margin (6) 1,798 (2,133)
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 IFRS 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 IFRS in the section to this document entitled “Non-GAAP Measures and
Reconciliation”.
Analysis of Consolidation Adjustments Comparing the Year and Quarter Ended December 31, 2011 and 2010
The following table outlines the key movements, the net of which primarily explains the variance in the results between the
years and quarters ended December 31, 2011 and 2010.
Yearly Variance
($ millions)
Quarterly Variance
($ millions)
$3.2 $0.7 Net profit/(loss) variance for the comparative periods primarily due to:
$3.2 $0.7 Variance 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.
Liquidity and Capital Resources
Summary of Debt Facilities
42

Summarized below are the debt facilities available to us and the balances outstanding as at December 31, 2011.
Organization
Facility
Balance outstanding
December 31, 2011
Effective interest rate Maturity date
OPIC secured loan $35,500,000 $35,500,000 6.93% December 2015
BNP Paribas working capital facility $260,000,000 (2) $10,030,131 (1) 3.38% January 2012 (3)
Westpac PGK working capital facility $37,320,000 (4) $6,450,372 9.65% November 2014
BSP PGK working capital facility $23,325,000 $0 9.47% August 2012
2.75% convertible notes $70,000,000 $70,000,000 7.91% (6) November 2015
Mitsui unsecured loan (5) $10,393,023 $10,393,023 6.23% See detail below
1 Excludes letters of credit totaling $164.9 million, which reduce the available balance of the facility to $85.1 million at December 31, 2011.
2 The facility was increased by $30.0 million during the quarter ended March 31, 2011 from $190.0 million to $220.0 million, and was then increased by a further
$10.0 million during the quarter ended June 30, 2011 to $230.0 million. During the quarter ended December 31, 2011 there was a temporary $30.0 million
increase to $260.0 million. The facility reverted back to a maximum availability of $230.0 million at the end of January 2012.
3 The facility was extended after the end of the year, and it now matures on January 31, 2013.
4 Subsequent to the year end, the limit on this facility was increased by approximately $4.7 million, with a new limit of approximately $42.0 million.
5 Facility is to fund our share of the Condensate Stripping Project costs as they are incurred pursuant to the JVOA.
6 Effective rate after bifurcating the equity and debt components of the $70 million principal amount of 2.75% convertible senior notes due 2015.
OPIC Secured Loan (Midstream Refinery)
In 2001, one of our subsidiaries entered into a loan agreement with OPIC for provision of an $85.0 million project financing
facility for the development of our refinery in PNG. The loan is primarily secured by the assets of the refinery. On June 20,
2011, OPIC signed agreements agreeing to release all of the sponsor support collateral and requirements for the loan granted
in 2001 in recognition of our financial and operational maturity. The balance outstanding under the loan as at December 31,
2011 was $35.5 million. The interest rate on the loan is equal to the agreed U.S. Government treasury cost applicable to each
promissory note that was issued and is outstanding plus 3%, and is payable quarterly in arrears. Principal repayments of $4.5
million each are due on June 30 and December 31 of each year until December 31, 2015. At December 31, 2011, $5.9
million was, and is still, being held on deposit to secure our June 30, 2012 principal and interest payments on the secured
loan.
BNP Paribas Working Capital Facility (Midstream Refinery)
This working capital facility is used to finance purchases of crude feedstock for our refinery. In accordance with the agreement
with BNP Paribas, the total facility is split into two components, Facility 1 and Facility 2 which are renewable annually. At
December 31, 2011, Facility 1 had a limit of $200.0 million (increased temporarily from $170.0 million during the quarter
ended December 31, 2011) and finances the purchases of crude and hydrocarbon products through the issuance of
documentary letters of credit and standby letters of credit, short term advances, advances on merchandise, freight loans, and
has a sublimit of Euro 18.0 million or the USD equivalent for hedging transactions. At January 31, 2012, the limit on Facility 1
reverted back to $170.0 million. Facility 2 allows borrowings of up to $60.0 million and can be used for partly cash-secured
short term advances and for discounting of any monetary receivables acceptable to BNP Paribas in order to reduce Facility 1
balances. The facility is secured by sales contracts, purchase contracts, certain cash accounts associated with the refinery, all
crude and refined products of the refinery and trade receivables.
As of December 31, 2011, $85.1 million remained available for use under the facility. The facility bears interest at LIBOR plus
3.5% on short term advances. The weighted average interest rate under the working capital facility was 3.38% for the year
ended December 31, 2011 (compared with 2.69% for the same period of 2010), after including the reduction in interest due
to the deposit amounts (restricted cash) maintained as security.
Bank South Pacific and Westpac Working Capital Facility (Downstream)
On October 24, 2008, we secured a PGK 150.0 million (approximately $70.0 million) combined revolving working capital
facility for our Downstream wholesale and retail petroleum products distribution business from Bank of South Pacific Limited
and Westpac Bank PNG Limited. The facility limit as at December 31, 2011 was PGK 130.0 million (approximately $60.6
million).
The Westpac facility limit is PGK 80.0 million (approximately $37.3 million). This facility was for an initial term of three years
and was renewed in November 2011 for a further three years to November 2014. Subsequent to year end, the limit of this
facility was increased by PGK 10.0 million (approximately $4.7 million) with an increased limit of PGK 90.0 million
(approximately $42.0 million). In addition, a secured loan of $15.0 million was provided as part of this increased facility which
43

is repayable in equal installments over 3.5 years with an interest rate of LIBOR + 4.4% per annum. The BSP facility limit is
PGK 50.0 million (approximately $23.3 million), and was renewed in August 2011 for another year. As at December 31, 2011,
PGK 13.8 million (approximately $6.5 million) of this combined facility had been utilized.
The weighted average interest rate under the Westpac facility was 10.0% for the quarter and 9.65% for the year ended
December 31, 2011, while the weighted average interest rate under the BSP facility was 9.94% for the quarter and 9.47% for
the year ended December 31, 2011.
2.75% Convertible Notes (Corporate)
On November 10, 2010, we completed the issuance of $70.0 million unsecured 2.75% convertible notes with a maturity of
five years. The convertible notes rank junior to any secured indebtedness and to all existing and future liabilities of us and our
subsidiaries, including the BNP Paribas working capital facility, the OPIC secured loan facility, the BSP and Westpac working
capital facilities, the Mitsui preliminary financing agreement, trade payables and lease obligations.
We pay interest on the notes semi-annually on May 15 and November 15. The notes are convertible into cash or common
shares, based on an initial conversion rate of 10.4575 common shares per $1,000 principal amount, which represents an
initial conversion price of approximately $95.625 per common share. The initial conversion price is subject to standard
anti-dilution provisions designed to maintain the value of the conversion option in the event we take certain actions with
respect to our common shares, such as stock splits, reverse stock splits, stock dividends and cash dividends, that affect all
of the holders of our common shares equally and that could have a dilutive effect on the value of the conversion rights of the
holders of the notes or that confer a benefit upon our current shareholders not otherwise available to the convertible notes.
Upon conversion, holders will receive cash, common shares or a combination thereof, at our option. The convertible notes
are redeemable at our option if our share price has been at least 125% ($119.53 per share) of the conversion price for at least
15 trading days during any 20 consecutive trading day period. Upon a fundamental change, which would include a change
of control, holders may require us to repurchase their convertible notes for cash at a purchase price equal to the principal
amount of the notes to be repurchased, plus accrued and unpaid interest.
Mitsui Unsecured Loan (Upstream)
On April 15, 2010, we entered into preliminary joint venture and financing agreements with Mitsui relating to the Condensate
Stripping Project. On August 4, 2010, we entered into the Condensate Stripping Project Joint Venture with Mitsui for the
condensate stripping facilities. Mitsui and InterOil hold equal interest in the joint venture. Mitsui is to be responsible for
arranging or providing financing for the capital costs of the condensate stripping facility.
The portion of funding that relates to Mitsui’s share of the Condensate Stripping Project as at December 31, 2011,
amounting to approximately $11.4 million, is held in current liabilities as the agreement requires refund of all funds advanced
by Mitsui under the preliminary financing agreement if a positive FID is not reached. The portion of funding that relates to our
share of the Condensate Stripping Project (amounting to $10.4 million), funded by Mitsui, is classed as an unsecured loan and
interest accrues daily based on LIBOR plus a margin of 6%.
While cash flows from operations are expected to be sufficient to cover our operating commitments, should there be a major
long term deterioration in refining or wholesale and retail margins, our operations may not generate sufficient cash flows to
cover all of the interest and principal payments under our debt facilities noted above. Also, our exploration and development
activities require funding beyond our operational cash flows and the cash balances we currently hold. As a result, we will be
required to raise additional capital and/or refinance these facilities in the future. We can provide no assurances that we will
be able to obtain such additional capital or that our lenders will agree to refinance these debt facilities, or, if available, that the
terms of any such capital raising or refinancing will be acceptable to us.
Other Sources of Capital
Currently our share of expenditures on exploration wells, appraisal wells and extended well programs is funded by a
combination of contributions made by capital raising activities, operational cash flows, IPI investors and asset sales.
Cash calls are made on IPI investors and Pac LNG (for its 2.5% direct interest in the Elk and Antelope field acquired during
2009) for their share of amounts spent on certain appraisal wells and extended well programs where they participate in such
wells and programs pursuant to the relevant agreements in place with them.
44

Summary of Cash Flows
($ Thousands)
Year ended December 31,
2011 2010 2009
Net cash inflows/(outflows) from:
Operations 62,670 (13,561) 44,500
Investing (204,241) (111,158) (85,567)
Financing (27,165) 311,846 38,546
Net cash movement (168,736) 187,127 (2,521)
Opening cash 233,577 46,450 48,971
Exchange gains on cash and cash equivalents 4,005 - -
Closing cash 68,846 233,577 46,450
Analysis of Cash Flows Provided By/(Used In) Operating Activities Comparing the Years ended December 31, 2011
and 2010
The following table outlines the key variances in the cash flows from operating activities between the years ended December
31, 2011 and 2010:
Yearly Variance
($ millions)
$76.2 Variance for the comparative periods primarily due to:
$26.1 Increase in cash generated by operations prior to changes in operating working capital for the year ended December
31, 2011, mainly due to the increased profits from operations adjusted for non cash items mainly relating to the loss
on extinguishment of IPI liability and non cash litigation settlement expense in the prior year.
$50.1 Decrease in cash used by operations relating to changes in operating working capital. The decrease in cash used for
the year is due primarily to a $28.0 million decrease in inventories due to timing of crude and export shipments and a
$71.6 million increase in accounts payable and accrued liabilities, partially offset by a $43.8 million increase in trade
receivables.
Analysis of Cash Flows Provided By/(Used In) Investing Activities Comparing the Years Ended December 31, 2011
and 2010
The following table outlines the key variances in the cash flows from investing activities between the years ended December
31, 2011 and 2010:
Yearly Variance
($ millions)
($93.1) Variance for the comparative periods primarily due to:
($21.8) Higher cash outflows on exploration and development program expenditures related to seismic activity on PPL 236
and PPL 237, FEED work for the Condensate Stripping Project and LNG Project, and site preparations for the
Triceratops 2 field appraisal well.
($23.0) Lower cash calls and related inflows from IPI investors due to activity being focused on seismic activities, for which
no contribution is required, rather than appraisal drilling and subsequent work program activities.
($19.5) Higher expenditure on plant and equipment. The expenditures were mainly associated with refurbishment of retail
sites, tank upgrades, camp and office refurbishments and, less significantly, relocation of the corporate offices in
PNG and Australia.
($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.
($11.8) Investment in short term PGK Treasury bills.
($7.5) Acquisition of FLEX LNG shares net of transaction costs.
$26.0 Higher cash inflows due to reduction in our cash restricted balances in line with the usage of the BNP working
capital facility.
($20.0) Increase in cash used in our Upstream segment for working capital requirements. This working capital relates to
movements in accounts receivable, accounts payable and accruals in our Upstream and Midstream Liquefaction
operations.
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Analysis of Cash Flows Provided By/(Used In) Financing Activities Comparing the Years Ended December 31, 2011 and
2010
The following table outlines the key variances in the cash flows from financing activities between years ended December 31,
2011 and 2010:
Yearly Variance
($ millions)
($339.0) Variance for the comparative periods primarily due to:
($61.4) Higher repayments of the BNP Paribas working capital facility due to increased working capital requirements.
($206.7) Net proceeds after transaction costs from the issuance of shares relating to the issuance of 2,800,000 common
shares in November 2010.
($66.3) Net proceeds after transaction costs from the issuance of $70.0 million of 2.75% convertible notes in November
2010.
$1.4 Proceeds received from Pac LNG for its share of costs incurred in developing the LNG Project.
($2.0) Reduction in funding received from Mitsui relating to the Condensate Stripping Project.
($5.0) Proceeds received from Petromin for contributions towards cash calls made with respect to development activities
for the Elk and Antelope fields. No proceeds were received during 2011.
Capital Expenditures
Upstream Capital Expenditures
Capital expenditures for exploration in Papua New Guinea for the year to December 31, 2011 were $107.6 million, compared
with $82.8 million during the same period of 2010.
The following table outlines the key expenditures in the year ended December 31, 2011:
Yearly Variance
($ millions)
$107.6 Expenditures in the year ended December 31, 2011 primarily due to:
$7.1 Completion costs on the Antelope-2 well, mainly relating to expenditure on our drilling rig necessitated by corrosion
caused by the use of drilling mud used to conduct the side tracks and complete the well.
$16.9 Costs for early works in respect of the Condensate Stripping Project.
$24.2 Costs associated with the Triceratops 2 well relating to pre-spud and standby costs.
$16.7 Costs for the construction of a road from our Antelope field to our river-based logistics hub on the Purari river.
$6.2 Capital works costs on infrastructure at the river based logistics hub.
$36.5 Other expenditures, including heavy equipment purchases and drilling inventory.
IPI investors and Pac LNG (2.5% direct interest in Elk and Antelope fields) are presently required to fund 24.3886% of the
Elk and Antelope fields extended well program costs to maintain their interest in those fields. The amounts capitalized in our
books, or expensed as incurred, in relation to the extended well program are the net amounts after adjusting for these
interests.
Petromin had agreed to fund 20.5% of ongoing costs for developing the fields. There were no contributions from Petromin
during the year ended December 31, 2011 and therefore the total advance payment received from Petromin remains at $15.4
million. At the end of the 2011 year, the parties agreed that the investment agreement between Petromin and InterOil
governing Petromin’s participation in the Elk and Antelope fields should terminate. Petromin remains the State’s nominee to
acquire the State’s interest in the Elk and Antelope fields under relevant Papua New Guinean legislation, once a PDL is
granted. We have proposed that cash contributions made by Petromin to date to fund the development will be held and
credited against the State’s obligation to contribute its portion of sunk costs upon grant of the PDL.
The preliminary financing agreement entered into with Mitsui provides for funding by Mitsui of all the costs relating to the
Condensate Stripping Project. 50% of the funding is for Mitsui’s share of the project and the other 50% is funding by Mitsui
of all the costs relating to the Condensate Stripping Project. 50% of the funding is for Mitsui’s share of the project and the
other 50% is funding by Mitsui of our share of the project. Mitsui contributed $9.9 million during the year for both Mitsui’s and
our share, and has contributed $21.8 million in aggregate. In the event that a positive FID is not reached or made, we will be
required to refund all of Mitsui’s contributions (i.e. for our share and Mitsui’s) within a specified period.
46

Midstream Capital Expenditures
Capital expenditures totaled $15.9 million in our Midstream Refining segment for the year ended December 31, 2011, mainly
associated with camp and office building works, motor vehicles and heavy pumper tanker purchases.
Following the signing of the LNG Project Agreement with the State in December 2009, $5.3 million of costs incurred during
the year in relation to the Midstream - Liquefaction segment have been capitalized.
Downstream Capital Expenditures
Capital expenditures for the Downstream segment totaled $10.2 million for the year ended December 31, 2011. These
expenditures mainly related to a number of upgrade projects across various terminals and depots, and office refurbishments.
Corporate Capital Expenditures
Capital expenditures for the Corporate segment totaled $3.1 million for the year ended December 31, 2011. These
expenditures mainly related to project costs in relation to the new business system implementation in the Downstream
business and costs associated with relocation of the corporate office in Cairns, Australia.
Capital Requirements
The oil and gas exploration and development, refining and liquefaction industries are capital intensive and our business plans
necessarily involve raising additional capital. The availability and cost of such capital is highly dependent on market conditions
at the time we raise such capital. No assurance can be given that we will be successful in obtaining new capital on terms that
are acceptable to us, particularly given current market volatility.
The majority of our “net cash from operating activities” adjusted for “proceeds from/(repayments of) working capital facilities”
is used in our appraisal and development programs for the Elk and Antelope, and Triceratops fields in PNG. Our net cash
from working activities is not sufficient to fund those appraisal and development programs.
Upstream
We are required under our $125.0 million IPI Agreement of 2005 to drill eight exploration wells. We have drilled four wells to
date. As at December 31, 2011, we are committed under the terms of our exploration licenses or PPL’s to spend a further
$61.9 million through 2015. As at December 31, 2011, management estimates that satisfying these license commitments
with the expenditure of $61.9 million 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 PRL 15 require us to spend a further $73.0 million on the development of the Elk and
Antelope fields by the end of 2014.
We do not have sufficient funds to complete planned exploration and development and we will need to raise additional funds
in order for us to complete the programs and meet our exploration commitments. Therefore, we must extend or secure
sufficient funding through renewed borrowings, equity raising and or asset sales to enable the availability of sufficient cash to
meet these obligations over time and complete these long term plans. No assurances can be given that we will be successful
in obtaining new capital on terms acceptable to us, particularly given recent market volatility.
We will also be required to obtain substantial amounts of financing for the development of the Elk and Antelope fields,
condensate stripping and associated facilities, pipelines and LNG export terminal facilities, and it will take a number of years
to complete these projects. In the event that positive FID is reached in respect of these projects, we seek to be in a position to
access the capital markets and/or sell an interest in our upstream properties in order to raise adequate capital. In September
2011, we retained financial advisors to help solicit and evaluate proposals from potential strategic partners to acquire
interests in our Elk and Antelope fields, LNG Project and exploration licenses. The solicitation process is now under way and
we believe, it will, if successful, provide a further source of funds for exploration and development activities. No assurances
can be given that we will be able to attract strategic partners on terms acceptable to us.
The availability and cost of various sources of financing is highly dependent on market conditions and our condition at the
time we raise such capital and we can provide no assurances that we will be able to obtain such financing or conduct such
sales on terms that are acceptable.
47

Midstream - Refining
We believe that we will have sufficient funds from our operating cash flows to pay our estimated capital expenditures
associated with our Midstream Refining segment in 2012. We also believe cash flows from operations will be sufficient to
cover the costs of operating our refinery and the financing charges incurred under our crude import facility. Should there be a
long term deterioration in refining margins, our refinery may not generate sufficient cash flows to cover all of the interest and
principal payments under our secured loan agreements. As a result, we may be required to raise additional capital and/or
refinance these facilities in the future.
Midstream - Liquefaction
On September 28, 2010, we and LNGL (a wholly owned subsidiary of PNG LNG) signed a heads of agreement with EWC to
construct a three mtpa land based liquefaction facility in the Gulf Province of Papua New Guinea. Following this agreement,
on February 2, 2011, the parties signed certain conditional framework agreements defining certain parameters for the
aforementioned development, construction, financing and the operation of the planned land-based liquefaction facilities.
These facilities are intended to be developed in phases and further definitive agreements are contemplated.
The LNG facilities are intended to be developed in two phases, an initial two mtpa followed by a one mtpa expansion. In
return for its commitment to fully fund the construction of the facilities, EWC is to be entitled to a fee of 14.5% of the proceeds
from LNG revenue from these facilities, less agreed deductions, and subject to adjustments based on timing and execution.
On April 11, 2011, we and Pac LNG entered into certain conditional framework agreements with FLEX LNG and Samsung
Heavy Industries for the proposed construction of a 1.8 mtpa or 2 mtpa fixed-floating liquefied natural gas vessel. Such a
vessel is expected to integrate with and augment the land-based modules to be developed with EWC. The framework
agreements provided that the parties were to undertake project specific FEED work and negotiate final binding agreements in
time for a FID decision in mid-December 2011. Project specific FEED work was carried out. However, as FID was not reached
by mid-December 2011, these framework agreements with FLEX LNG and Samsung lapsed and were not extended. We are
continuing to negotiate with FLEX LNG.
The fixed-floating project is intended to integrate with and augment proposed on-shore infrastructure to transport LNG from
the onshore Elk and Antelope fields in the Gulf Province of Papua New Guinea pursuant to arrangements with EWC and
Mitsui.
In September 2011, we retained financial advisors to help solicit and evaluate proposals from potential strategic partners to,
amongst other things, obtain an interest in, operate and help finance the development of the LNG Project. No assurances can
be given that we will be able to attract strategic partners on terms acceptable to us, how such an agreement will affect our
current LNG Project plans or whether such a partner will be acceptable to the PNG government.
Completion of the LNG Project will require substantial amounts of financing and construction will take a number of years to
complete. As a joint venture partner in development, if the project is completed, we would be required to fund our share of
certain common facilities of the development. No assurances can be given that we will be able to source sufficient gas,
successfully construct such a facility, or as to the timing of such construction. The availability and cost of capital is highly
dependent on market conditions and our circumstances at the time we raise such capital.
Downstream
We believe on the basis of current market conditions and the status of our business that our cash flows from operations will
be sufficient to meet our estimated capital expenditures for our wholesale and retail distribution business segment for 2012.
Contractual Obligations and Commitments
The following table contains information on payments required to meet contracted exploration and debt obligations due for
each of the next five years and thereafter. It should be read in conjunction with our financial statements for the year ended
December 31, 2011 and the notes thereto:
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Contractual obligations
($ thousands)
Payments Due by Period
Total Less than 1 year 1 - 2 years 2 - 3 years 3 - 4 years 4 - 5 years
More than
5 years
Petroleum prospecting and retention
licenses (a) 134,900 44,400 36,350 44,050 9,900 200 -
Secured and unsecured loans (b) 51,586 21,727 10,749 10,131 8,979 - -
2.75% Convertible notes obligations 77,540 1,925 1,925 1,925 71,765 - -
Indirect participation interest - PNGDV 1,384 540 844 - - - -
Total 265,410 68,592 49,868 56,106 90,644 200 -
A 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 $61.9 million as a condition of renewal of our petroleum prospecting licenses through 2014 under our exploration
licenses. As at December 31, 2011, management estimates that satisfying this license commitment with the expenditure of $61.9 million 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 $73.0 million on the development of the Elk and Antelope fields by the end of 2014.
B The effective interest rate on these loans for the year ended December 31, 2011 was 6.93%.
The following table contains information on payments required to meet our operating lease commitments. It should be read in
conjunction with our financial statements for the year ended December 31, 2011 and the notes thereto:
($ Thousands)
Year ended December 31,
2011 2010
Not later than 1 year 6,983 6,257
Later than 1 year and not later than 5 years 6,560 8,558
Later than 5 years 2,958 458
Total 16,501 15,273
Off Balance Sheet Arrangements
Neither during the year ended, nor as at December 31, 2011, did we have any off balance sheet arrangements or any
relationships with unconsolidated entities or financial partnerships.
Transactions with Related Parties
Petroleum Independent and Exploration Corporation, is owned by Mr. Mulacek, our Chairman and Chief Executive Officer.
Prior to 2011, Petroleum Independent and Exploration Corporation received a management fee in its capacity as the General
Manager of one of our subsidiaries, S.P. InterOil LDC, in compliance with OPIC loan requirements. During the year ended
December 31, 2010, Petroleum Independent and Exploration Corporation received $150,000. On June 20, 2011, OPIC
signed agreements agreeing to release all of the sponsor support collateral and requirements for the loan granted to us in
2001 in recognition of our financial and operational maturity. As a result, no fees were paid to Petroleum Independent and
Exploration Corporation in the year ended December 31, 2011. In November of 2011, we elected to exchange the 5,000
shares held in S.P. InterOil LDC by Petroleum Independent and Exploration Corporation for 5,000 shares in InterOil
Corporation. The sponsor agreements were terminated with Petroleum Independent and Exploration Corporation on
exchange of the share holding interest in S.P. InterOil LDC. Subsequent to year end, S.P. InterOil LDC has been renamed
South Pacific Refining Limited.
Breckland Limited, a company controlled by Mr. Roger Grundy, one of our directors, previously provided technical and
advisory services to us on normal commercial terms. Amounts paid or payable to Breckland for technical services during the
year ended December 31, 2011 amounted to $nil (December 2010 - $21,923).
Share Capital
Our authorized share capital consists of an unlimited number of common shares and unlimited number of preferred shares, of
which 1,035,554 series A preferred shares are authorized (none of which are outstanding). As of December 31, 2011, we had
48,121,071 common shares (50,833,593 common shares on a fully diluted basis) and no preferred shares outstanding. The
potential dilutive instruments outstanding as at December 31, 2011 included employee stock options and restricted stock in
respect of 1,640,017 common shares, IPI conversion rights to 340,480 common shares and 732,025 common shares
relating to the $70.0 million principal amount 2.75% convertible senior notes due November 15, 2015. The 5,000 common
shares previously recorded as potentially dilutive instruments were issued to Petroleum Independent and Exploration
49

Corporation in the quarter ended December 31, 2011 in exchange for the 5,000 shares it held in our subsidiary, S.P. InterOil
LDC.
Derivative Instruments
Our revenues are derived from the sale of refined products. Prices for refined products and crude feedstocks can be
volatile and sometimes experience large fluctuations over short periods of time as a result of relatively small changes in
supplies, weather conditions, economic conditions and government actions. Due to the nature of our business, there is
always a time difference between the purchase of a crude feedstock and its arrival at the refinery and the supply of finished
products to the various markets.
Generally, we purchase crude feedstock two months in advance, whereas the supply/export of finished products will take
place after the crude feedstock is discharged and processed. Due to the fluctuation in prices during this period, we use
various derivative instruments as a tool to reduce the risks of changes in the relative prices of our crude feedstocks and
refined products. These derivatives, which we use to manage our price risk, effectively enable us to lock-in the refinery margin
such that we are protected in the event that the difference between our sale price of the refined products and the acquisition
price of our crude feedstocks contracts is reduced. Conversely, when we have locked-in the refinery margin and if the
difference between our sales price of the refined products and our acquisition price of crude feedstocks expands or
increases, then the benefits would be limited to the locked-in margin.
The derivative instruments which we generally use are the over-the-counter swaps. The swap transactions are concluded
between counterparties in the derivatives swaps market, unlike futures which are transacted on the International Petroleum
Exchange and Nymex Exchanges. We believe these hedge counterparties to be credit worthy. It is common place among
refiners and trading companies in the Asia Pacific market to use derivatives swaps as a tool to hedge their price exposures
and margins. Due to the wide usage of derivatives tools in the Asia Pacific region, the swaps market generally provides
sufficient liquidity for the hedging and risk management activities. The derivatives swap instrument covers commodities or
products such as jet and kerosene, diesel, naphtha, and also bench-mark crudes such as Tapis and Dubai. By using these
tools, we actively engage in hedging activities to lock in margins. Occasionally, there is insufficient liquidity in the crude swaps
market and we then use other derivative instruments such as Brent futures on the IPE to hedge our crude costs.
At December 31, 2011, we had a net receivable of $0.6 million (December 2010 – payable of $0.2 million) relating to open
contracts to sell gasoil crack swaps and sell dated Brent swaps for which hedge accounting has not been applied, and Brent
swaps that have been priced out and will be settled in January and February 2012.
A gain of $2.0 million was recognized on the non-hedge accounted derivative contracts for the year ended December 31,
2011 (December 2010 – $1.6 million loss).
In addition to the commodity derivative contracts, we have also entered into foreign exchange derivative contracts to manage
our foreign exchange risk in relation to AUD. As at December 31, 2011, we had $11,457 payable (December 2010 - nil)
relating to our foreign currency derivatives. An $11,457 loss has been recognized on foreign exchange derivative contracts for
the year ended December 31, 2011 (December 2011 - $0.5 million gain).
Industry Trends and Key Events
Competitive Environment and Regulated Pricing
We are currently the sole refiner of hydrocarbons in Papua New Guinea although there is no legal restraint upon other
refineries being established. The PNG Government has agreed to ensure that all domestic distributors purchase their refined
petroleum products from our refinery, or any other refinery which is constructed in Papua New Guinea, at an Import Parity
Price (“IPP”). The IPP is monitored by the ICCC. In general, the IPP is the price that would be paid in Papua New Guinea for a
refined product being imported. For all price controlled products (diesel, unleaded petrol, kerosene and aviation fuel) produced
and sold locally in Papua New Guinea, the IPP is calculated by adding the costs that would typically be incurred to import
such product to Mean of Platts Singapore (“MOPS”) which is the benchmark price for refined products in the region in which
we operate.
In our refining business, we compete with several companies for available supplies of crude oil and other feedstocks and for
outlets for our refined products. Many of our competitors obtain a significant portion of their feedstocks from company owned
production, which may enable them to obtain feedstocks at a lower cost. The high cost of transporting goods to and from
Papua New Guinea reduces the availability of alternate fuel sources and retail outlets for our refined products. Competitors
that have their own production or extensive distribution networks are at times able to offset losses from refining operations
50

and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, new
technology is making refining more efficient, which could lead to lower prices and reduced margins. We cannot be certain that
we will be able to implement new technologies in a timely basis or at a cost that is acceptable to us.
We are also a significant participant in the retail and wholesale distribution business in Papua New Guinea. The ICCC
regulates the maximum prices and margins that may be charged by the wholesale and retail hydrocarbon distribution
industry in Papua New Guinea. Margins were last reviewed by the ICCC in 2010 and will be further reviewed in 2014. We and
our competitors may charge less than the maximum margin set by the ICCC in order to maintain competitiveness.
Our main competitor in the wholesale and retail distribution business in Papua New Guinea is ExxonMobil. We also compete
with smaller local distributors of petroleum products. Our competitors source small quantities from our refinery from both the
refinery gantry for the Port Moresby market and by tanker vessel for the markets outside Port Moresby. Our major competitive
advantage is the large widespread distribution network we maintain with adequate storage capacity that services most areas
of PNG. We also believe that our commitment to the distribution business in Papua New Guinea at a time when major
integrated oil and gas companies exited the Papua New Guinea fuel distribution market provides us with a competitive
advantage. However, major-integrated oil and gas companies such as ExxonMobil have greater resources than we do and
could if they decided to do so, expand much more rapidly in this market than we can.
Our proposed LNG Project faces competition, including competing liquefaction facilities and related infrastructure, from
competitors with far greater resources, including major international energy companies. Many competing companies have
secured access to, or are pursuing development or acquisition of, liquefaction facilities to serve the same markets we intend
to target. In addition, competitors have developed or reopened additional liquefaction facilities in other international
markets, which may also compete with our LNG Project. Almost all of these competitors have longer operating histories,
more development experience, greater name recognition, larger staffs and substantially greater financial, technical and
marketing resources and access to natural gas and LNG supplies than we do. The superior resources that these competitors
have available for deployment could allow them to compete successfully against our LNG businesses, which could have a
material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
Financing Arrangements
We continue to monitor liquidity risk by setting of acceptable gearing levels and ensuring they are monitored. Our aim is to
maintain our debt-to-capital ratio, or gearing levels, (debt/(shareholders’ equity + debt)) at 50% or less. This was achieved
throughout 2011 and 2010. Gearing levels were 12% in December 2011 and 13% in December 2010.
On November 10, 2010, we completed concurrent public offerings of $70.0 million aggregate principal amount of 2.75%
convertible senior notes due 2015 and 2,800,000 common shares at a price of $75.00 per share for proceeds of $210.0
million, raising gross proceeds of $280.0 million from the combined offerings.
No financing arrangements were entered into in 2011.
For details of other financial arrangements in place, see “Liquidity and Capital Resources – Summary of Debt Facilities”.
We had cash, cash equivalents and cash restricted of $108.1 million as at December 31, 2011, of which $39.3 million was
restricted (as governed by BNP working capital facility utilization requirements and OPIC secured loan facility). In addition, we
also had $11.8 million equivalent of PGK in short term treasury bills issued by the Bank of Papua New Guinea. With regard to
our cash and cash equivalents, we invest in bankers acceptances and money market instruments with major financial
institutions that we believe are creditworthy. We also had $85.1 million of the combined BNP working capital facility available
for use in our Midstream – Refining operations, and $54.2 million of the Westpac/BSP combined working capital facility
available for use in our Downstream operations.
Crude Prices
Crude prices increased steadily throughout 2011, with the price of Dated Brent crude oil (as quoted by Platts) starting the
year at $97 per bbl and closing the year at $108 per bbl. The average price for Dated Brent for 2011 was $111 per bbl
compared with $79 per bbl for Dated Brent for 2010.
At year end we had $85.1 million of the combined BNP working capital facility available for use in our Midstream –
Refining operations, and approximately $54.2 million of the Westpac/BSP combined working capital facility available for use
in our Downstream operations. Any increase in prices will have an impact on the utilization of our working capital facilities, and
related interest and financing charges on the utilized amounts.
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Any volatility of crude prices means that we face significant timing and margin risk on our crude cargos. A significant
portion of this timing and margin risk is managed by us through short and long term hedges. There was a net receivable of
$0.6 million relating to open contracts to sell gasoil crack swaps and sell Dated Brent swaps for which hedge accounting has
not been applied, and Brent swaps that have been priced out and were settled in January and February of 2012.
Refining Margin
The distillation process used by our refinery to convert crude feedstocks into refined products is commonly referred to as
hydroskimming. While the Singapore Tapis hydroskimming margin is a useful indicator of the general margin available for
hydroskimming refineries in the region in which we operate, it should be noted that the differences in our approach to crude
selection, transportation costs and IPP pricing work so that our realized margin generally differs to some extent.
Distillate margins to Dated Brent strengthened during 2011 compared with historical levels due to increasing demand.
Naphtha crack spreads were negative for all of 2011, which has negatively affected our gross margin for the period.
Domestic Demand
Sales results for our refinery for 2011 indicate that Papua New Guinea’s domestic demand for middle distillates (which
includes diesel and jet fuels) from the refinery has increased by approximately 6.4% compared with 2010. However, the total
volume of all products sold by us was 7.4 million barrels for fiscal year 2011 compared with 7.5 million barrels in 2010. Total
volume of PNG domestic sales only for 2011 was 4.9 million barrels as compared with 4.6 million barrels in 2010.
The refinery on average sold 12,649 bbls per day of refined petroleum products to the domestic market during fiscal year
2011 compared with 11,780 bbls per day in 2010.
Interest Rates
The LIBOR USD overnight rate is the benchmark floating rate used in our midstream working capital facility and therefore
accounts for a significant proportion of our interest rate exposure. The LIBOR USD overnight rate remained constant at
between 0.2% and 0.3% for 2010 and then reduced to between 0.15% and 0.2% for the majority of 2011. Any rate
increases would add additional cost to financing our crude cargoes and vice versa as our BNP Paribas working capital facility
is linked to LIBOR rates. See “Liquidity and Capital Resources – Summary of Debt Facilities”.
Exchange Rates
Changes in the PGK to USD exchange rate can affect our Midstream Refinery results as there is a timing difference between
the foreign exchange rates utilized when setting the monthly IPP, which is set in PGK, and the foreign exchange rate used to
convert the subsequent receipt of PGK proceeds to USD to repay our crude cargo borrowings. The PGK has strengthened
against the USD every month during the year ended December 31, 2011 (from 0.3785 to 0.4665).
Changes in the AUD and SGD to USD exchange rate can affect our Corporate results as the expenses of the Corporate
offices in Australia and Singapore are incurred in the respective local currencies. The AUD and SGD exposures are minimal
currently as funds are transferred to AUD and SGD from USD as required. No material balances are held in AUD or SGD.
However, we are exposed to translation risks resulting from AUD and SGD fluctuations as in country costs are being incurred
in AUD and SGD and reporting for those costs being in USD. We have entered into AUD to USD foreign currency forward
contracts to manage the foreign exchange risk in relation to the expenses to be incurred in AUD.
Risk Factors
Our business operations and financial position are subject to a range of risks. A summary of the key risks that may impact
upon the matters addressed in this document have been included under section “Forward Looking Statements” above.
Detailed risk factors can be found under the heading “Risk Factors” in our 2011 Annual Information Form available at
www.sedar.com.
Critical Accounting Estimates
The preparation of financial statements in accordance with IFRS requires our management to make estimates and
assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual
results could differ from those estimates. The effect of changes in estimates on future periods have not been disclosed in the
consolidated financial statements as estimating it is impracticable. The following accounting policies involve estimates that
52

are considered critical due to the level of sensitivity and judgment involved, as well as the impact on our consolidated financial
position and results of operations. The information about our critical accounting estimates should be read in conjunction with
Note 2 of the notes to our consolidated financial statements for the year ended December 31, 2011, available at
www.sedar.com which summarizes our significant accounting policies.
Income Taxes
We use the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax
assets and liabilities are recognized for the deferred tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities
are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences
are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized
in income in the period that includes the date of enactment. In considering the recoverability of deferred tax assets and
liabilities, we consider a number of factors, including the consistency of profits generated from the refinery, likelihood of
production from Upstream operations to utilize the carried forward exploration costs, etc. If actual results differ from the
estimates or we adjust the estimates in future periods, a reduction in our deferred tax assets will result in a corresponding
increase in deferred tax expenses.
Oil and Gas Properties
We use the successful-efforts method to account for our oil and gas exploration and development activities. Under this
method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being
expensed as incurred. We continue to carry as an asset the cost of drilling exploratory wells if the required capital
expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near future, or when
exploration and evaluation activities have not yet reached a stage to allow reasonable assessment regarding the existence of
economical reserves. Capitalized costs for producing wells will be subject to depletion using the units-of-production method.
Geological and geophysical costs are expensed as incurred. If our plans change or we adjust our estimates in future periods,
a reduction in our oil and gas properties asset will result in a corresponding increase in the amount of our exploration
expenses.
Asset Retirement Obligations
A liability is recognized for future legal or constructive retirement obligations associated with the Company’s property, plant
and equipment. The amount recognized is the net present value of the estimated costs of future dismantlement, site
restoration and abandonment of properties based upon current regulations and economic circumstances at period end.
During the quarter ended June 30, 2011, Management received the results of an independent assessment of the potential
asset retirement obligations of the refinery. As a result of this assessment, Management has recognized an asset retirement
obligation at December 31, 2011 of $4,562,269. If we adjust the estimates in future periods, it may result in increased capital
expenditures and a corresponding increase in liabilities.
Environmental Remediation
Remediation costs are accrued based on estimates of known environmental remediation exposure. Ongoing environmental
compliance costs, including maintenance and monitoring costs, are expensed as incurred. Provisions are determined on an
assessment of current costs, current legal requirements and current technology. Changes in estimates are dealt with on a
prospective basis. We currently do not have any amounts accrued for environmental remediation obligations as current
legislation does not require it. Future legislative action and regulatory initiatives could result in changes to our operating
permits which may result in increased capital expenditures and operating costs.
Impairment of Long-Lived Assets
We are required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas
assets, and goodwill for potential impairment. We test long-lived assets for recoverability whenever events or changes in
circumstances indicate that its carrying amount may not be recoverable by the future undiscounted cash flows. If impairment
is indicated, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to
earnings. In order to determine fair value, our management must make certain estimates and assumptions including, among
other things, an assessment of market conditions (including estimation of gross refining margins, crude price environments
and its impact on IPP, etc), projected cash flows, investment rates, interest/equity rates and growth rates, that could
significantly impact the fair value of the asset being tested for impairment. Due to the significant subjectivity of the
assumptions used to test for recoverability and to determine fair value, changes in market conditions could result in significant
53

significant impairment charges in the future, thus affecting our earnings. Our impairment evaluations are based on
assumptions that are consistent with our business plans.
Legal and Other Contingent Matters
We are required to determine whether a loss is probable based on judgment and interpretation of laws and regulations and
whether the loss can reasonably be estimated. When the amount of a contingent loss is determined it is charged to earnings.
Our management continually monitors known and potential contingent matters and makes appropriate provisions by charges
to earnings when warranted by circumstances.
During the second half of 2011, the PNG Customs Service commenced an audit of our petroleum product imports into Papua
New Guinea for the years 2007 to 2010. We received a letter in November 2011 from the then Commissioner of Customs
setting out certain findings from the audit. This letter included comments alleging that payment of import GST was required
and had not been made on imports of certain refined products. As well as requiring payment of GST, the letter noted that
administrative penalties were able to be levied by Customs in the range of 50% to 200% of the assessed amounts as per the
PNG Customs Act. We have since met with the Customs Service and provided it with supporting documentation to
demonstrate that the GST amounts claimed in their letter have all been paid. We have currently made a provision based on
our best estimate in relation to this matter and are working closely with the authority to provide all requested information in
order to finalize the audit.
New Accounting Standards
New accounting standards not yet applicable as at December 31, 2011
The following new standards have been issued but are not yet effective for the financial year beginning January 1, 2011 and
have not been early adopted:
• IFRS 9 ‘Financial Instruments’ (effective from January 1, 2015): This addresses the classification and measurement of
financial assets. The standard is not applicable until January 1, 2013 but is available for early adoption. We have yet to
assess IFRS 9’s full impact. We have not yet decided to adopt IFRS 9 early.
• IFRS 10 ‘Consolidated Financial Statements’ (effective from January 1, 2013): This builds on existing principles by
identifying the concept of control as the determining factor in whether an entity should be included within the
consolidated financial statements. The standard provides additional guidance to assist in determining control where this
is difficult to assess. This new standard might impact the entities that a group consolidates as its subsidiaries. We have
yet to assess IFRS 10’s full impact.
• IFRS 11 ‘Joint Arrangements’ (effective from January 1, 2013): This provides for a more realistic reflection of joint
arrangements by focusing on the rights and obligations of the arrangement, rather than its legal form. There are two
types of joint arrangements: joint operations and joint ventures. Joint operations arise where a joint operator has rights
to the assets and obligations relating to the arrangement and hence accounts for its interest in assets, liabilities,
revenue and expenses. Joint ventures arise where the joint operator has rights to the net assets of the arrangement
and hence equity accounts for its interest. Proportional consolidation of joint ventures is no longer allowed. We have yet
to assess IFRS 11’s full impact.
• IFRS 12 ‘Disclosure of Interests in Other Entities’ (effective from January 1, 2013): This standard is a new standard on
disclosure requirements for all forms of interests in other entities, including joint arrangements, associates, special
purpose vehicles and other off balance sheet vehicles. We have yet to assess IFRS 12’s full impact.
• IFRS 13 ‘Fair Value Measurement’ (effective from January 1, 2013): This aims to improve consistency and reduce
complexity by providing a precise definition of fair value and a single source of fair value measurement and disclosure
requirements for use across IFRS. We have yet to assess IFRS 13’s full impact.
• IAS 27 ‘Separate Financial Statements’ (effective from January 1, 2013): This includes the provisions on separate
financial statements that are left after the control provisions of IAS 27 have been included in the new IFRS 10. We have
yet to assess IAS 27’s full impact.
• IAS 28 ‘Investments in Associates and Joint Ventures’ (effective from January 1, 2013): This now includes the
requirements for joint ventures, as well as associates, to be equity accounted following the issue of IFRS 11. We have
yet to assess IAS 28’s full impact.
54

• IAS 1 ‘Presentation of financial statements’ (amendment): The IASB has issued an amendment to IAS 1, which
changes the disclosure of items presented in other comprehensive income (OCI) in the statement of comprehensive
income. The IASB originally proposed that all entities should present profit or loss and OCI together in a single
statement of comprehensive income. The proposal has been withdrawn and IAS 1 will still permit profit or loss and OCI
to be presented in either a single statement or in two consecutive statements. The amendment was developed jointly
with the FASB, which has removed the option in US generally accepted accounting principles to present OCI in the
statement of changes in equity. The amendment is effective for annual periods starting on or after July 1, 2012, subject
to EU endorsement. This amendment will not have any material impact on our financial statements.
Changeover to International Financial Reporting Standards
The AcSB adopted IFRS as issued by IASB as GAAP, effective January 1, 2011, with a transition date of January 1, 2010. We
have adopted IFRS and have prepared our financial statements for the year ended December 31, 2011 in accordance with
IFRS and restated our financial statements for the year ended December 31, 2010 to comply with IFRS. The financial
information contained in this MD&A that relates to periods prior to January 1, 2010 has been prepared under our previous
GAAP and has not been restated.
(i) Application of IFRS 1:
Our financial statements for the year ended December 31, 2011, are the first annual financial statements prepared in
compliance with IFRS. We have applied IFRS 1 in preparing the consolidated financial statements for the year ended
December 31, 2011.
Our transition date to IFRS was January 1, 2010 and we have prepared our opening IFRS balance sheet at that date. In
preparing the consolidated financial statements for the year ended December 31, 2011 in accordance with IFRS 1, we have
applied the relevant mandatory exceptions and certain optional exemptions from full retrospective application of IFRS.
(ii) Exemptions from full retrospective application – elected by the Company
We have elected to apply the following optional exemptions from full retrospective application.
• Business combinations exemption: 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 IFRS). 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.
• Fair value as deemed cost exemption: An entity may elect to measure an item of property, plant and equipment at the
date of transition to IFRS 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.
• Cumulative translation differences exemption: Consistent with the previous GAAP treatment in prior periods, 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 restate our cumulative
translation differences balance to zero, and have elected to continue with the current translation differences in
comprehensive income as these are already in compliance with IAS 21.
• Oil and Gas assets exemption: Oil and Gas industry specific accounting under IFRS or previous GAAP is currently not
as comprehensive as the guidance provided under U.S. generally accepted accounting principles accounting for
industry specific oil and gas transactions. Paragraph D8A 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 GAAP into IFRS. We have availed this exemption and
elected to maintain our Oil and Gas assets at carrying amount under GAAP treatment in prior periods, which will be the
deemed cost under IFRS.
• Interests in joint ventures entities exemption: Superseded CICA Section 3055 differs from IAS 31 as IAS 31 permits the
55

• use of either the proportionate consolidation method or the equity method to account for joint venture entities. 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. Superseded CICA Section 3055 only allows the use of proportionate
consolidation method to account for joint venture entities. We have elected to maintain our joint venture accounting
under the proportionate consolidation model for both our incorporated and unincorporated joint venture interests.
The remaining optional exemptions are not applicable to us.
(iii) Exceptions from full retrospective application followed by the Company
All mandatory exceptions in IFRS 1 were not applicable because there were no significant differences in management’s
application of GAAP in these areas.
Impact of adoption of IFRS on financial reporting
Following a review of the IFRS, there were two IFRS adjustments to the opening January 1, 2010 balance sheet:
a) In relation to the deferred gain on contributions to the LNG Project recorded on our balance sheet, under IFRS, we were
required to offset these deferred gains against any underlying assets that are carried in relation to these deferred gains. Based
on this guidance, we have offset the deferred gains against deferred LNG project costs carried within the plant and equipment
in the balance sheet under the Midstream – Liquefaction segment. For further details, please refer to Note 3(b) in the
Condensed Consolidated Financial Statements for the year ended December 31, 2011.
b) In accordance with guidance under IFRS, deferred tax assets have been recognized for temporary differences that arise on
translation of the nonmonetary assets held by Midstream refining operations that are translated from the functional currency of
the tax return (PGK) to the reporting currency (USD) using period end rates. Previously under GAAP, these temporary
differences in relation to functional currency translation of nonmonetary assets were specifically disallowed from recognition.
Other than the transition adjustments affecting the consolidated balance sheets, consolidated income statements,
consolidated statements of comprehensive income and consolidated statements of changes in equity as noted above, there
were no transition differences noted in relation to consolidated statement of cash flows.
Non-GAAP Measures and Reconciliation
Non-GAAP measures, including gross margin and EBITDA, included in this MD&A are not defined nor have a standardized
meaning prescribed by IFRS or our previous GAAP; accordingly, they may not be comparable to similar measures provided by
other issuers. Gross margin is a non-GAAP measure and is “sales and operating revenues” less “cost of sales and operating
expenses”. The following table reconciles sales and operating revenues, a GAAP measure, to Gross margin:
Consolidated – Operating results
($ thousands)
Quarter ended December 31,
2011 2010 2011
Midstream – Refining 939,278 674,137 574,409
Downstream 743,860 504,786 388,991
Corporate 14,125 402 21,194
Consolidation Entries (590,729) (376,951) (296,115)
Sales and operating revenues 1,106,534 802,374 688,479
Midstream – Refining (897,825) (605,603) (516,349)
Downstream (704,213) (470,772) (359,623)
Corporate (1) (11,421) - -
Consolidation Entries 592,527 374,818 273,989
Cost of sales and operating expenses (1,020,932) (701,557) (601,983)
Midstream – Refining 41,453 68,534 58,060
Downstream 39,647 34,014 29,368
Corporate (1) 2,704 402 21,194
Consolidation Entries 1,798 (2,133) (22,126)
Gross Margin 85,602 100,817 86,496
1 Corporate expenses are classified below the gross margin line and mainly relates to ‘Office and admin and other expenses’ and ‘Interest expense’.
2 The 2009 financial information was prepared in accordance with the Company’s former GAAP, and has not been restated in accordance with IFRS.
56

EBITDA represents our net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income
tax expense, depreciation and amortization expense. EBITDA is used by us to analyze operating performance. EBITDA does
not have a standardized meaning prescribed by GAAP (i.e., IFRS) and, therefore, may not be comparable with the calculation
of similar measures for other companies. The items excluded from EBITDA are significant in assessing our operating results.
Therefore, EBITDA should not be considered in isolation or as an alternative to net earnings, operating profit, net cash
provided from operating activities and other measures of financial performance prepared in accordance with IFRS. Further,
EBITDA is not a measure of cash flow under IFRS and should not be considered as such. For reconciliation of EBITDA to the
net income (loss) under IFRS, refer to the following table.
The following table reconciles net income (loss), a GAAP measure, to EBITDA, a non-GAAP measure for each of the last eight
quarters. Our IFRS transition date was January 1, 2010 and as such, the 2010 comparative information has been restated in
accordance with IFRS.
Quarters ended
($ thousands)
2011 2010
Dec 31 Sep 31 Jun 30 Mar 31 Dec 31 Sep 30 Jun 30 Mar 31
Upstream 665 (6,169) 593 (10,957) (41,681) (11,753) (3,498) (1,964)
Midstream – Refining 2,604 3,461 27,967 26,632 13,780 15,785 16,962 4,402
Midstream – Liquefaction (4,123) (3,602) (4,035) (2,375) (1,959) (4,588) (3) (563)
Downstream 6,808 3,570 5,777 8,744 4,709 1,674 7,060 4,492
Corporate 10,134 1,548 13,940 5,223 4,566 (4,510) 1,751 4,402
Consolidation Entries (11,280) (10,263) (5,270) (9,200) (7,004) (5,229) (7,384) (5,911)
Earnings before interest,
taxes, depreciation and
amortization
Subtract:
4,808 (11,455) 38,972 18,067 (27,589) (8,621) 14,888 4,858
Upstream (8,712) (7,806) (7,142) (6,352) (5,481) (4,600) (4,367) (4,081)
Midstream – Refining (3,285) (2,494) (2,211) (1,675) (1,509) (1,693) (1,651) (1,731)
Midstream – Liquefaction (445) (372) (268) (223) (184) (376) (351) (342)
Downstream (1,170) (1,233) (1,116) (826) (835) (938) (1,167) (800)
Corporate (1,498) (1,477) (1,641) (1,395) (1,158) (342) (20) (20)
Consolidation Entries 11,500 10,041 8,894 7,572 6,571 6,107 5,917 5,688
Interest expense (3,610) (3,341) (3,484) (2,899) (2,596) (1,842) (1,639) (1,286)
Upstream 0 - - - - - - -
Midstream – Refining 19,243 678 (5,677) (7,298) (65) 101 (366) (173)
Midstream – Liquefaction 0 - - - 36 - - -
Downstream (595) (297) (1,449) (2,623) (495) (322) (1,524) (2,360)
Corporate (493) (195) (629) 71 (11) (529) 97 (797)
Consolidation Entries 0 0 0 - (2) (2) (1) -
Income taxes 18,155 186 (7,755) (9,850) (537) (752) (1,794) (3,330)
Upstream (1,355) (1,105) (154) (641) (683) (232) (78) (138)
Midstream – Refining (2,878) (2,846) (2,764) (2,765) (2,700) (2,195) (2,888) (2,571)
Midstream – Liquefaction (6) (6) (6) (6) (7) (6) (6) (6)
Downstream (1,422) (894) (906) (804) (737) (739) (651) (660)
Corporate (527) (349) (395) (435) (16) (17) (32) (41)
Consolidation Entries 32 32 32 32 33 32 33 32
Depreciation and
amortisation
(6,156) (5,168) (4,193) (4,619) (4,110) (3,157) (3,622) (3,384)
Upstream (9,402) (15,080) (6,703) (17,949) (47,845) (16,585) (7,943) (6,182)
Midstream – Refining 15,684 (1,201) 17,314 14,894 9,504 11,998 12,056 (74)
Midstream – Liquefaction (4,574) (3,980) (4,309) (2,604) (2,114) (4,970) (360) (911)
Downstream 3,621 1,146 2,306 4,491 2,643 (325) 3,719 671
Corporate 7,616 (473) 11,275 3,463 3,381 (5,398) 1,796 3,544
Consolidation Entries 252 (190) 3,657 (1,596) (401) 908 (1,435) (190)
Net profit/(loss) per
segment
13,197 (19,778) 23,540 699 (34,832) (14,372) 7,833 (3,142)
57

Public Securities Filings
You may access additional information about us, including our 2011 Annual Information Form, in documents filed with the
Canadian Securities Administrators at www.sedar.com, and in documents, including our Form 40-F, filed with the U.S.
Securities and Exchange Commission at www.sec.gov. Additional information is also available on our website
www.interoil.com.
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS
OVER FINANCIAL REPORTING
Our certifying officers have designed disclosure controls and procedures, as such term is defined in National Instrument
52-109 - Certification of Disclosure in Issuer’s Annual and Interim Filings (“National Instrument 52-109”), or caused them to
be designed under their supervision. As of December 31, 2011, our Chief Executive Officer (“CEO”) and our Chief Financial
Officer (“CFO”) carried out an internal evaluation of the effectiveness of our disclosure controls and procedures. Based on that
evaluation, our CEO and CFO concluded that the disclosure controls and procedures provide reasonable assurance that all
material information relating to us is made known to us by others and all information required to be disclosed in our annual
and interim filings is recorded, processed, summarized and reported within the time periods specified in applicable
Canadian securities legislation. Our CEO and CFO are responsible for establishing and maintaining internal control over
financing reporting (“ICFR”), as such term is defined in National Instrument 52-109. The control framework the CEO and CFO
used to design the Company’s ICFR is the framework established by the Committee of Sponsoring Organizations entitled
Internals Controls – Integrated Framework (the “COSO Framework”).
Under the supervision of the CEO and the CFO, the Company conducted an evaluation of the effectiveness of our ICFR as
at December 31, 2011 based on the COSO Framework. Based on this evaluation, they concluded that as of December 31,
2011, our ICFR provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with IFRS.
Effective April 26, 2011, we migrated our downstream segment to the new ERP system, Microsoft Dynamics AX, to complete
the roll out of the system implementation which started during 2010 financial year. In addition to the MS Dynamics AX, the
downstream segment also implemented MS Dynamics NAV, fuel distribution system to process sales orders and manages
inventory and warehousing. This migration has effectively completed the ERP system implementation resulting in all our
business segments running on a single ERP platform.
Management has reviewed the internal controls over financial reporting affected by the implementation of the new ERP
System and made appropriate changes to internal controls as part of the implementation. Following the implementation,
these new controls were evaluated and tested according to our established processes. Based on this evaluation, we believe
that we have designed adequate and appropriate internal control over financial reporting to ensure that the financial
statements were materially accurate for the year ended December 31, 2011.
During the year ended December 31, 2011, there has been no other change in our internal control over financial reporting that
has materially affected, or is reasonably likely to affect, our internal control over financial reporting, other than as noted above.
58

Management’s Report
The management of InterOil Corporation is responsible for the financial information and operating
data presented in this Annual Report.
The consolidated financial statements have been prepared by management in accordance with
International Financial Reporting Standards. When alternative accounting methods exist, management has
chosen those it deems most appropriate in the circumstances. Financial statements are not precise as they
include certain amounts based on estimates and judgments. Management has determined such amounts
on a reasonable basis in order to ensure that the financial statements are presented fairly, in all material
respects. Financial information presented elsewhere in this Annual Report has been prepared on a basis
consistent with that in the consolidated financial statements.
InterOil Corporation maintains systems of internal accounting and administrative controls. These systems
are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate
and that the Company’s assets are properly accounted for and adequately safeguarded.
The Audit Committee, appointed by the Board of Directors, is composed of independent non-management
directors. The Committee meets regularly with management, as well as the independent auditors, to
discuss auditing, internal controls, accounting policy and financial reporting matters. The Committee reviews
the annual consolidated financial statements with both management and the independent auditors and
reports its findings to the Board of Directors before such statements are approved by the Board.
The 2011 consolidated financial statements have been audited by PricewaterhouseCoopers, the
independent auditors, in accordance with Canadian generally accepted auditing standards and auditing
standards issued by the Public Company Accounting Oversight Board, on behalf of the shareholders.
PricewaterhouseCoopers has full and free access to the Audit Committee.
Phil E. Mulacek
Chief Executive Officer
Collin F. Visaggio
Chief Financial Officer
59

March 16, 2012
Independent Auditor’s Report
To the Shareholders of InterOil Corporation
We have completed an integrated audit of InterOil Corporation 2011 consolidated financial statements and its
internal control over financial reporting as at December 31, 2011 and an audit of its 2010 consolidated financial
statements. Our opinions, based on our audits, are presented below.
Report on the consolidated financial statements
We have audited the accompanying consolidated financial statements of InterOil Corporation, which comprise the
Consolidated Balance Sheets as at December 31, 2011, December 31, 2010 and January 1, 2010 and the
Consolidated Income Statements, Statements of Comprehensive Income, Changes in Equity and Cash Flows for
the years ended December 31, 2011 and December 31, 2010, and the related notes, which comprise a summary of
significant accounting policies and other explanatory information.
Management’s responsibility for the consolidated financial statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in
accordance with International Financial Reporting Standards as issued by the International Accounting Standards
Board and for such internal control as management determines is necessary to enable the preparation of
consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditor’s responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We
conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the
Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform
an audit to obtain reasonable assurance about whether the consolidated financial statements are free from material
misstatement. Canadian generally accepted auditing standards require that we comply with ethical requirements.
An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and
disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment,
including the assessment of the risks of material misstatement of the consolidated financial statements, whether due
to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the company’s
preparation and fair presentation of the consolidated financial statements in order to design audit procedures that
are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting principles
and policies used and the reasonableness of accounting estimates made by management, as well as evaluating the
overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for
our audit opinion on the consolidated financial statements.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of
InterOil Corporation as at December 31, 2011, December 31, 2010 and January 1, 2010 and its financial
performance and its cash flows for years ended December 31, 2011 and December 31, 2010 in accordance with
International Financial Reporting Standards as issued by the International Accounting Standards Board.
PricewaterhouseCoopers, ABN 52 780 433 757
Darling Park Tower 2, 201 Sussex Street, GPO BOX 2650, SYDNEY NSW1171
T +61 2 8266 0000, F +61 2 8266 9999, www.pwc.com.au
60

Report on internal control over financial reporting
We have also audited InterOil Corporation’s internal control over financial reporting as at December 31, 2011, based
on criteria established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).
Management’s responsibility for internal control over financial reporting
Management is responsible for maintaining effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting included in Management’s Report on Internal Control over
Financial Reporting.
Auditor’s responsibility
Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our
audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained
in all material respects.
An audit of internal control over financial reporting includes obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and
operating effectiveness of internal control, based on the assessed risk, and performing such other procedures as we
consider necessary in the circumstances.
We believe that our audit provides a reasonable basis for our audit opinion on the company’s internal control over
financial reporting.
Definition of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.
Inherent limitations
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may
deteriorate.
Opinion
In our opinion, InterOil Corporation maintained, in all material respects, effective internal control over financial
reporting as at December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued
by COSO.
Charterd Accountants
March 16, 2012
PricewaterhouseCoopers
Sydney, Australia
PricewaterhouseCoopers, ABN 52 780 433 757
Darling Park Tower 2, 201 Sussex Street, GPO BOX 2650, SYDNEY NSW1171
T +61 2 8266 0000, F +61 2 8266 9999, www.pwc.com.au
61

Consolidated Financial Statements
Consolidated Income Statements
(Expressed in United States dollars)
Year ended December 31,
2011 2010
$ $
Revenue
Sales and operating revenues 1,106,533,853 802,374,399
Interest 1,356,124 150,816
Other 11,058,090 4,470,048
1,118,948,067 806,995,263
Changes in inventories of finished goods and work in progress 43,934,439 57,010,311
Raw materials and consumables used (1,064,866,361) (758,566,961)
Administrative and general expenses (41,160,824) (41,047,949)
Derivative gains/(losses) 2,006,321 (1,065,188)
Legal and professional fees (6,801,334) (6,902,241)
Exploration costs, excluding exploration impairment (note 13) (18,435,150) (16,981,929)
Finance costs (18,163,769) (12,064,982)
Depreciation and amortization (20,136,649) (14,274,922)
Gain on sale of oil and gas properties - 2,140,783
Loss on extinguishment of liability - (30,568,710)
Litigation settlement expense - (12,000,000)
Loss on available-for-sale investment (note 14) (3,420,406) -
Foreign exchange gains/(losses) 25,018,661 (10,776,823)
(1,102,025,072) (845,098,611)
Profit/(loss) before income taxes 16,922,995 (38,103,348)
Income taxes
Current tax expense (note 15) (5,512,842) (3,898,067)
Deferred tax benefit/(expense) (note 15) 6,248,509 (2,511,656)
735,667 (6,409,723)
Profit/(loss) for the year 17,658,662 (44,513,071)
Profit/(loss) is attributable to:
Owners of InterOil Corporation 17,652,461 (44,519,573)
Non-controlling interest 6,201 6,502
17,658,662 (44,513,071)
Basic profit/(loss) per share 0.37 (1.00)
Diluted profit/(loss) per share 0.36 (1.00)
Weighted average number of common shares outstanding
Basic (Expressed in number of common shares) 47,977,478 44,329,670
Diluted (Expressed in number of common shares) 49,214,190 44,329,670
Year ended December 31,
2011 2010
$ $
Profit/(loss) for the year 17,658,662 (44,513,071)
Other comprehensive income:
Exchange difference on translation of foreign operations, net of tax 20,527,270 1,110,201
Movement on available-for-sale financial assets, net of tax (407,565) -
Other comprehensive income for the year, net of tax 20,119,705 1,110,201
Total comprehensive income/(loss) for the year 37,778,367 (43,402,870)
Total comprehensive income/(loss) for the year is attributable to:
Owners of InterOil Corporation 37,772,166 (43,409,372)
Non-controlling interests 6,201 6,502
37,778,367 (43,402,870)
See accompanying notes to the consolidated financial statements
62

Consolidated Balance Sheet
(Expressed in United States dollars)
Year ended December 31,
2011 2010 2009
$ $ $
Assets
Current assets:
Cash and cash equivalents (note 6) 68,846,441 233,576,821 46,449,819
Cash restricted (note 9) 32,982,001 40,664,995 22,698,829
Short term treasury bills - held-to-maturity (note 8) 11,832,110 - -
Trade and other receivables (note 10) 135,273,600 48,047,496 61,194,136
Derivative financial instruments (note 9) 595,440 - -
Other current assets 867,967 505,059 639,646
Inventories (note 11) 171,071,799 127,137,360 70,127,049
Prepaid expenses 5,477,596 3,593,574 6,964,950
Total current assets 426,946,954 453,525,305 208,074,429
Non-current assets:
Cash restricted (note 9) 6,268,762 6,613,074 6,609,746
Goodwill (note 17) 6,626,317 6,626,317 6,626,317
Plant and equipment (note 12) 246,043,948 225,205,427 218,794,649
Oil and gas properties (note 13) 362,852,766 255,294,738 172,483,562
Deferred tax assets (note 15) 35,965,273 28,477,690 30,319,163
Available-for-sale investments (note 14) 3,650,786 - -
Total non-current assets 661,407,852 522,217,246 434,833,437
Total assets 1,088,354,806 975,742,551 642,907,866
Liabilities and shareholders' equity
Current liabilities:
Trade and other payables (note 16) 159,882,177 75,132,880 59,372,354
Income tax payable 4,085,137 955,074 -
Derivative financial instruments (note 9) 11,457 178,578 -
Working capital facilities (note 18) 16,480,503 51,254,326 24,626,419
Unsecured loan and current portion of secured loan (note 20) 19,393,023 14,456,757 9,000,000
Current portion of Indirect participation interest (note 21) 540,002 540,002 540,002
Total current liabilities 200,392,299 142,517,617 93,538,775
Non-current liabilities:
Secured loan (note 20) 26,037,166 34,813,222 43,589,278
2.75% convertible notes liability (note 26) 55,637,630 52,425,489 -
Deferred gain on contributions to LNG project (note 22) 5,810,775 8,949,857 10,824,212
Indirect participation interest (note 21) 34,134,840 34,134,387 39,559,718
Asset retirement obligations (note 23) 4,562,269 - -
Deferred tax liabilities (note 15) 1,889,391 - -
Total non-current liabilities 128,072,071 130,322,955 93,973,208
Total liabilities 328,464,370 272,840,572 187,511,983
Equity:
Equity attributable to owners of InterOil Corporation:
Share capital (note 25) 905,981,614 895,651,052 613,361,363
Authorized - unlimited
Issued and outstanding - 48,121,071 (Dec 31, 2010 - 47,800,552)
2.75% convertible notes (note 26) 14,298,036 14,298,036 -
Contributed surplus 25,644,245 16,738,417 21,297,177
Accumulated Other Comprehensive Income 29,380,882 9,261,177 8,150,976
Conversion options (note 21) 12,150,880 12,150,880 13,270,880
Accumulated deficit (227,565,221) (245,217,682) (200,698,109)
63

Year ended December 31,
2011 2010 2009
$ $ $
Total equity attributable to owners of InterOil Corporation 759,890,436 702,881,880 455,382,287
Non-controlling interest - 20,099 13,596
Total equity 759,890,436 702,901,979 455,395,883
Total liabilities and equity 1,088,354,806 975,742,551 642,907,866
See accompanying notes to the consolidated financial statements
Consolidated Statements of Changes in Equity
(Expressed in United States dollars)
Year ended December 31,
Transactions with owners as owners:
2011 2010
$ $
Share capital
At beginning of year 895,651,052 613,361,363
Issue of capital stock (note 25) 10,330,562 282,289,689
At end of year 905,981,614 895,651,052
2.75% convertible notes
At beginning of year 14,298,036 -
Issue of convertible notes (note 26) - 14,298,036
At end of year 14,298,036 14,298,036
Contributed surplus
At beginning of year 16,738,417 21,297,177
Fair value of options and restricted stock transferred to share capital (note 27) (5,598,009) (8,454,758)
Stock compensation expense (note 27) 14,721,387 11,804,000
Loss on extinguishment of IPI conversion options (note 21) - (7,908,002)
Loss on buyback of non-controlling interest (note 24) (217,550) -
At end of year 25,644,245 16,738,417
Accumulated Other Comprehensive Income
Foreign currency translation reserve
At beginning of year 9,261,177 8,150,976
Foreign currency translation movement for the year, net of tax 20,527,270 1,110,201
Foreign currency translation reserve at end of year 29,788,447 9,261,177
Gain/(loss) on available-for-sale financial assets
At beginning of year - -
Gain/(loss) on available-for-sale financial assets, net of tax (note 14) (407,565) -
Gain/(loss) on available-for-sale financial assets at end of year (407,565) -
Accumulated other comprehensive income at end of year 29,380,882 9,261,177
Conversion options
At beginning of year 12,150,880 13,270,880
Movement for the year (note 21) - (1,120,000)
At end of year 12,150,880 12,150,880
Accumulated deficit
At beginning of year (245,217,682) (200,698,109)
Net profit/(loss) for the year 17,652,461 (44,519,573)
At end of year (227,565,221) (245,217,682)
Total InterOil Corporation shareholders’ equity at end of year 759,890,436 702,881,880
Transactions with non-controlling interest
At beginning of year 20,099 13,597
Net profit for the year 6,201 6,502
Buyback of non-controlling interest (note 24) (26,300) -
At end of year - 20,099
Total equity at end of year 759,890,436 702,901,979
64

Consolidated Statements of Changes in Equity
(Expressed in United States dollars)
Year ended December 31,
Transactions with owners as owners:
2011 2010
$ $
Share capital
At beginning of year 895,651,052 613,361,363
Issue of capital stock (note 25) 10,330,562 282,289,689
At end of year 905,981,614 895,651,052
2.75% convertible notes
At beginning of year 14,298,036 -
Issue of convertible notes (note 26) - 14,298,036
At end of year 14,298,036 14,298,036
Contributed surplus
At beginning of year 16,738,417 21,297,177
Fair value of options and restricted stock transferred to share capital (note 27) (5,598,009) (8,454,758)
Stock compensation expense (note 27) 14,721,387 11,804,000
Loss on extinguishment of IPI conversion options (note 21) - (7,908,002)
Loss on buyback of non-controlling interest (note 24) (217,550) -
At end of year 25,644,245 16,738,417
Accumulated Other Comprehensive Income
Foreign currency translation reserve
At beginning of year 9,261,177 8,150,976
Foreign currency translation movement for the year, net of tax 20,527,270 1,110,201
Foreign currency translation reserve at end of year 29,788,447 9,261,177
Gain/(loss) on available-for-sale financial assets
At beginning of year - -
Gain/(loss) on available-for-sale financial assets, net of tax (note 14) (407,565) -
Gain/(loss) on available-for-sale financial assets at end of year (407,565) -
Accumulated other comprehensive income at end of year 29,380,882 9,261,177
Conversion options
At beginning of year 12,150,880 13,270,880
Movement for the year (note 21) - (1,120,000)
At end of year 12,150,880 12,150,880
Accumulated deficit
At beginning of year (245,217,682) (200,698,109)
Net profit/(loss) for the year 17,652,461 (44,519,573)
At end of year (227,565,221) (245,217,682)
Total InterOil Corporation shareholders’ equity at end of year 759,890,436 702,881,880
Transactions with non-controlling interest
At beginning of year 20,099 13,597
Net profit for the year 6,201 6,502
Buyback of non-controlling interest (note 24) (26,300) -
At end of year - 20,099
Total equity at end of year 759,890,436 702,901,979
See accompanying notes to the consolidated financial statements.
65

Consolidated Statement of Cash Flows
(Expressed in United States dollars)
Year ended December 31,
2011 2010
$ $
Cash flows generated from (used in):
Operating activities
Net profit/(loss) for the year 17,658,662 (44,513,071)
Adjustments for non-cash and non-operating transactions
Depreciation and amortization 20,136,649 14,274,922
Deferred tax assets (5,598,192) 1,841,473
Gain on sale of exploration assets - (2,140,783)
Accretion of convertible notes liability 3,212,141 432,632
Amortization of deferred financing costs 223,944 1,223,944
Timing difference between derivatives recognized and settled (762,561) 178,578
Stock compensation expense, including restricted stock 14,721,387 11,804,000
Movement in net realizable value write down 259,406 -
Accretion of asset retirement obligation liability 159,356 -
Oil and gas properties expensed 18,435,150 16,981,929
Loss on extinguishment of IPI Liability - 30,568,710
Non-cash litigation settlement expense - 12,000,000
Loss on Flex LNG investment 3,420,406 -
Gain on proportionate consolidation of LNG project (555,030) -
Unrealized foreign exchange gain (2,618,814) (72,456)
Change in operating working capital
Increase in trade and other receivables (53,064,305) (9,224,005)
(Increase)/decrease in other current assets and prepaid expenses (2,246,930) 3,505,963
Increase in inventories (28,003,484) (56,115,637)
Increase in trade and other payables 77,291,915 5,692,543
Net cash generated from/(used in) operating activities 62,669,700 (13,561,258)
Investing activities
Expenditure on oil and gas properties (134,927,701) (113,128,916)
Proceeds from IPI cash calls 749,794 23,723,752
Expenditure on plant and equipment (42,050,435) (22,560,055)
Proceeds received on sale of exploration assets - 15,544,465
Investment in short term treasury bills (11,832,110) -
Acquisition of Flex LNG Ltd shares, including transaction costs (7,478,756) -
Decrease/(increase) in restricted cash held as security on borrowings 8,027,306 (17,969,494)
Change in non-operating working capital
Increase in trade and other receivables (10,000,000) -
(Decrease)/increase in trade and other payables (6,727,960) 3,232,029
Net cash used in investing activities (204,239,862) (111,158,219)
Financing activities
Repayments of OPIC secured loan (9,000,000) (9,000,000)
Proceeds from Mitsui for Condensate Stripping Plant 9,872,532 11,913,514
Proceeds from/(repayments of) Clarion Finanz secured loan, net of transaction costs - (1,000,000)
Proceeds from PNG LNG cash call 2,247,533 866,600
Proceeds from Petromin for Elk and Antelope field development - 5,000,000
(Repayments of)/proceeds from working capital facility (34,773,823) 26,627,907
Proceeds from issue of common shares, net of transaction costs 4,488,703 211,147,565
Proceeds from issue of convertible notes, net of transaction costs - 66,290,893
Net cash (used in)/generated from financing activities (27,165,055) 311,846,479
(Decrease)/increase in cash and cash equivalents (168,735,217) 187,127,002
Cash and cash equivalents, beginning of year 233,576,821 46,449,819
66

Year ended December 31,
2011 2010
$ $
Exchange gains on cash and cash equivalents 4,004,837 -
Cash and cash equivalents, end of year (note 6) 68,846,441 233,576,821
Comprising of:
Cash on Deposit 18,758,288 233,576,821
Term Deposits 50,088,153 -
Total cash and cash equivalents, end of year 68,846,441 233,576,821
See accompanying notes to the consolidated financial statements
Notes to Consolidated Financial Statements
(Expressed in United States dollars)
1. General Information
InterOil Corporation (the “Company” or “InterOil”) is a publicly traded, integrated oil and gas company operating in Papua
New Guinea (“PNG”). The Company is incorporated and domiciled in Canada. The Company is a Yukon Territory corporation,
continued under the Business Corporations Act (Yukon Territory) on August 24, 2007. The address of its registered office is
300-204 Black Street, Whitehorse, Yukon, Canada.
Management has organized the Company’s operations into four major segments - Upstream, Midstream, Downstream and
Corporate. Upstream includes exploration, appraisal and development operations for crude oil and natural gas structures in
PNG. Upstream currently includes the development of the Elk and Antelope fields infrastructure, including the condensate
stripping and associated facilities, and the gas gathering and associated common facilities, in connection with
commercializing significant gas discoveries. Midstream consists of both Midstream Refining and Midstream Liquefaction.
Midstream Refining includes refining of products for the domestic market in PNG and exports, and Midstream Liquefaction
includes the work being undertaken to develop liquefaction and associated facilities (”LNG project”) in PNG for the export of
liquefied natural gas. Downstream includes wholesale and retail distribution of refined products in PNG. Corporate engages
in business development and improvement, common services and management, financing and treasury, product shipping,
government and investor relations. Common and integrated costs are recovered from reporting segments on an equitable
driver basis.
These consolidated financial statements were approved for issue on March 16, 2012.
2. Significant accounting policies
The accounting policies set out below have been applied consistently to all years presented in these consolidated financial
statements and in preparing the opening IFRS balance sheet at January 1, 2010 for the purposes of the transition to IFRSs as
if these policies had always been in effect unless otherwise indicated.
(a) Basis of preparation and adoption of IFRS
The Company prepares its consolidated financial statements in accordance with Canadian generally accepted
accounting principles as set out in the Handbook of the Canadian Institute of Chartered Accountants (“CICA Handbook”). In
2010, the CICA Handbook was revised to incorporate International Financial Reporting Standards (“IFRS”) and to require
publicly accountable enterprises to apply such standards effective for years beginning on or after January 1, 2011.
Accordingly, the company has commenced reporting on this basis from January 1, 2011, and in these consolidated financial
statements prepared for the year ended December 31, 2011 (“financial statements”). In these consolidated financial
statements, the term “Canadian GAAP” refers to Canadian GAAP before the adoption of IFRS.
These consolidated financial statements have been prepared in accordance with IFRS as issued by the IASB applicable to the
preparation of financial statements including IFRS 1 – ‘First-time Adoption of International Financial Reporting Standards’.
The effective date of transition is January 1, 2010. An explanation of how the transition to IFRSs has affected the reported
balance sheets, income statements and cash flows of the Company is provided in note 3.
67

This note includes reconciliations of equity and total comprehensive income for comparative years and of equity at the date
of transition reported under Canadian GAAP to those reported for those years and at the date of transition under IFRSs. The
consolidated financial statements for the year ended December 31, 2011 have been prepared under the historical cost
convention, except for derivative financial instruments and available-for-sale investments which are measured at fair value.
The preparation of financial statements requires the use of certain critical accounting estimates. It also requires management
to exercise its judgment in the process of applying the Company’s accounting policies. Estimates and judgments are
continually evaluated and are based on historical experience and other factors, including expectations of future events that are
believed to be reasonable under the circumstances. The Company makes estimates and assumptions concerning the future.
The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and assumptions
that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next
financial year are addressed below.
• Net realizable value of inventory: Inventory is recorded at the lower of cost or net realizable value. To determine the net
realizable value of finished goods inventory, the IPP pricing from January 2012 is considered (IPP is based on
December MOPS product pricing) along with estimated Naphtha, LSWR and LPG pricing based on the expected date
of sale. The estimates are based on the most reliable evidence available at the time the estimates are made, of the
amounts that are expected to be realized. These estimates take into consideration fluctuations of price or cost directly
relating to events occurring after the end of the period to the extent that such events confirm conditions existing at the
end of the reporting period.
• Convertible notes: The convertible notes are assessed based on the substance of the contractual arrangement in
determining whether it exhibits the fundamental characteristic of a financial liability or equity. Management has
assessed that the note instrument mainly exhibits characteristics that are liability in nature, however, the embedded
conversion feature is in equity in nature and needs to be bifurcated and disclosed separately within equity.
Management applied residual basis and valued the liability component first and assigned the residual value to the
equity component. Management fair valued the liability component by deducting the premium paid by holders
specifically for the conversion feature. The conversion price of $95.625 per share includes a premium of 27.5% to the
issue price of the concurrent common shares offering of $75 per share. Therefore, the $70,000,000 total issue
represents 127.5% of the liability portion.
• Deferred gain on contributions to LNG project: The Company has a recognized deferred gain on its contributions to the
Joint Venture based on the share of other joint venture partners in the project. As InterOil’s shareholding within the Joint
Venture Company as at December 31, 2011 is 84.582%, the gain on contribution of non cash assets to the
project by InterOil relating to other joint venture partners’ shareholding (15.418% - amounting to $15,113,190) has
been recognized by InterOil in its balance sheet as a deferred gain. This deferred gain will increase/decrease as the
other Joint Venture partners decrease/increase their shareholding in the project.
This amount has been recorded as a reduction of deferred LNG project costs of $9,302,415 at December 31, 2011
which has reduced the LNG project costs to nil at December 31, 2011, with the remaining balance of $5,810,775
being recorded as a deferred gain. The deferred gain will be recognized in the consolidated income statement when
the risks and rewards have considered to be passed.
• Asset retirement obligation: A liability is recognized for future legal or constructive retirement obligations associated with
the Company’s property, plant and equipment. The amount recognized is the net present value of the estimated costs
of future dismantlement, site restoration and abandonment of properties based upon current regulations and economic
circumstances at period end. During the quarter ended June 30, 2011, Management received the results of an
independent assessment of the potential asset retirement obligations of the refinery. As a result of this assessment,
Management has recognized an asset retirement obligation at December 31, 2011 of $4,562,269.
• Share-based payments: The fair value of stock options at grant date is determined using a Black-Scholes option
pricing model that takes into account the exercise price, the terms of the option, the vesting criteria, the share price at
grant date, expected price volatility of the underlying share, the expected yield and risk-free interest rate for the term
of the option. Upon exercise of options, the balance of the contributed surplus relating to those options is transferred
to share capital. The fair value of restricted stock on grant date is the market value of the stock. The Company uses
the fair value based method to account for employee stock based compensation benefits. Under the fair value based
method, compensation expense is measured at fair value at the date of grant and is expensed over the award’s vesting
period.
68

Rate Regulation
InterOil is currently the sole refiner of hydrocarbons in PNG. The Company’s 30 year project agreement with the Independent
State of Papua New Guinea (“the State”) expires in 2035. The State has undertaken to ensure that all domestic distributors
purchase their refined petroleum products from the Company’s refinery, or any other refinery which is constructed in PNG, at
an Import Parity Price (”IPP”). The IPP is monitored by the Papua New Guinea Independent Consumer and Competition
Commission (”ICCC”). In general, the IPP is the price that would be paid in PNG for a refined product being imported. For all
price controlled products (diesel, unleaded petrol, kerosene and aviation fuel) produced and sold locally in PNG, the IPP is
calculated by adding the costs that would typically be incurred to import such product to ‘Mean of Platts Singapore’ (“MOPS”)
which is the benchmark price for refined products in the region in which the Company operates.
InterOil is also a significant participant in the retail and wholesale distribution business in PNG. The ICCC regulates the
maximum prices that may be charged by the wholesale and retail hydrocarbon distribution industry in PNG. The Downstream
business may charge less than the maximum margin set by the ICCC in order to maintain its competitiveness with other
participants in the market. In November 2010, the ICCC released its review report which will govern the pricing arrangements
for petroleum products in PNG until the end of 2014, taking effect from November 1, 2010. 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. The report recommended an increase in margins for wholesale business
and certain other activities, while the retail margin is to remain the same. It also recommended some increases in monitoring
industry activity in PNG mainly, relating to import of products by distributors and in relation to aviation fuel pricing.
No rate regulated assets or liabilities have been recognized.
(b) Going concern
These consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of
assets and settlement of liabilities in the normal course of business as they become due.
The net current assets as at December 31, 2011 amounted to $226.6 million compared to $311.0 million as at December 31,
2010. The Company has cash, cash equivalents and cash restricted of $108.1 million as at December 31, 2011 (December
2010 - $280.9 million), of which $39.3 million is restricted (December 2010 - $47.3 million). The Company also has
investments in Bank of PNG treasury bills of $11.8 million as at December 31, 2011 (December 2010 - $nil).
With respect to its Upstream operations, the Company has no obligation to execute exploration activities within a set
timeframe and therefore has the ability to select the timing of these activities as long as the minimum license commitments in
relation to the Company’s Petroleum Prospecting Licenses (“PPL”) and Petroleum Retention Licenses (“PRL”) are met. Refer
note 29 for further information on these commitments.
The Company has a short term total working capital facility of $230.0 million (increased temporarily to $260.0 million in
November 2011, and reverted back to $230.0 million on January 31, 2012) for its Midstream – Refining operation that is
renewable annually with BNP Paribas. This facility is secured by the assets it is drawn down against. As at December 31,
2011 $174.9 million of the combined facility has been utilized, and the remaining facility of $85.1 million (including the
temporary increase of $30.0 million) remains available for use. The facility was renewed in February 2012 at an increased limit
of $240.0 million until January 31, 2013.
The Company has an approximate $60.6 million (Papua New Guinea Kina (“PGK”) 130.0 million) revolving working capital
facility for its Downstream operations in PNG from Bank of South Pacific Limited (“BSP”) and Westpac Bank PNG Limited
(“Westpac”). As at December 31, 2011, $6.4 million (PGK 13.8 million) of this combined facility has been utilized, and $54.2
million (PGK 116.2 million) of this facility remains available for use. The Westpac facility was for an initial term of three years
and was renewed in November 2011 through to November 2014. The facility was further increased, subsequent to year end
in February 2012, by $4.7 million (PGK 10.0 million) bringing the total facility to $65.3 million (PGK 140.0 million). In addition a
secured loan of $15.0 million was provided as part of this increased facility which is repayable in equal installments over 3.5
years with an interest rate of LIBOR + 4.4% per annum. The BSP facility is renewable annually and was renewed in August
2011 through to August 2012.
The Company believes that it has sufficient funds for the Midstream Refinery and Downstream operations; however, existing
cash balances and ongoing cash generated from these operations will not be sufficient to facilitate further necessary
development of the Elk and Antelope fields, condensate stripping and liquefaction facilities. Therefore the Company must
extend or secure sufficient funding through renewed or additional borrowings, equity raising and or asset sales to enable
sufficient cash to be available to further its development plans. Management expects that the Company will be able to secure
69

the necessary financing through one, or a combination of, the aforementioned alternatives. Accordingly, these consolidated
financial statements have been prepared on a going concern basis in the belief that the Company will realize its assets and
settle its liabilities and commitments in the normal course of business and for at least the amounts stated.
(c) New standards issued but not yet effective
The following new standards, new interpretations and amendments to standards and interpretations have been issued but are
not yet effective for the financial year beginning January 1, 2011 and have not been early adopted:
• IFRS 9 ‘Financial Instruments’ (effective from January 1, 2015): This addresses the classification and measurement of
financial assets. The standard is not applicable until January 1, 2015 but is available for early adoption. The Company
is yet to assess IFRS 9’s full impact. The Company has not yet decided to early adopt IFRS 9.
• IFRS 10 ‘Consolidated Financial Statements’ (effective from January 1, 2013): This builds on existing principles by
identifying the concept of control as the determining factor in whether an entity should be included within the
consolidated financial statements. The standard provides additional guidance to assist in determining control where
this is difficult to assess. This new standard might impact the entities that a group consolidates as its subsidiaries. The
Company is yet to assess IFRS 10’s full impact.
• IFRS 11 ‘Joint Arrangements’ (effective from January 1, 2013): This provides for a more realistic reflection of joint
arrangements by focusing on the rights and obligations of the arrangement, rather than its legal form. There are two
types of joint arrangements: joint operations and joint ventures. Joint operations arise where a joint operator has rights
to the assets and obligations relating to the arrangement and hence accounts for its interest in assets, liabilities,
revenue and expenses. Joint ventures arise where the joint operator has rights to the net assets of the arrangement
and hence equity accounts for its interest. Proportional consolidation of joint ventures is no longer allowed. The
Company is yet to assess IFRS 11’s full impact.
• IFRS 12 ‘Disclosure of Interests in Other Entities’ (effective from January 1, 2013): This is a new standard on
disclosure requirements for all forms of interests in other entities, including joint arrangements, associates, special
purpose vehicles and other off balance sheet vehicles. The Company is yet to assess IFRS 12’s full impact.
• IFRS 13 ‘Fair Value Measurement’ (effective from January 1, 2013): This aims to improve consistency and reduce
complexity by providing a precise definition of fair value and a single source of fair value measurement and disclosure
requirements for use across IFRSs. The Company is yet to assess IFRS 13’s full impact.
• IAS 27 ‘Separate Financial Statements’ (effective from January 1, 2013): This includes the provisions on separate
financial statements that are left after the control provisions of IAS 27 have been included in the new IFRS 10. The
Company is yet to assess IAS 27’s full impact.
• IAS 28 ‘Investments in Associates and Joint Ventures’ (effective from January 1, 2013): This now includes the
requirements for joint ventures, as well as associates, to be equity accounted following the issue of IFRS 11. The
Company is yet to assess IAS 28’s full impact.
• IAS 1 ‘Presentation of financial statements’ (amendment): The IASB has issued an amendment to IAS 1, which
changes the disclosure of items presented in other comprehensive income (“OCI”) in the statement of comprehensive
income. The IASB originally proposed that all entities should present profit or loss and OCI together in a single
statement of comprehensive income. The proposal has been withdrawn and IAS 1 will still permit profit or loss and OCI
to be presented in either a single statement or in two consecutive statements. The amendment was developed jointly
with the FASB, which has removed the option in US GAAP to present OCI in the statement of changes in equity. The
amendment is effective for annual periods starting on or after 1 July 2012, subject to EU endorsement. This
amendment will not have any material impact on the Company’s financial statements.
(d) Principles of Consolidation
• Business combinations: The Company applies the acquisition method to account for business combinations. The
consideration transferred for the acquisition of a subsidiary is the fair value of the assets transferred, the liabilities
incurred to the former owners of the acquiree and the equity interests issued by the group. The consideration
transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement.
Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured
initially at their fair values at the acquisition date. The Company recognizes any non-controlling interest in the acquiree
on an acquisition-by-acquisition basis, either at fair value or at the non-controlling interest’s proportionate share of the
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ecognized amounts of acquiree’s identifiable net assets.
If the business combination is achieved in stages, the acquisition date fair value of the acquirer’s previously held equity
interest in the acquire is remeasured to fair value at the acquisition date through profit or loss. Any contingent
consideration to be transferred by the Company is recognized at fair value at the acquisition date. Subsequent
changes to the fair value of the contingent consideration that is deemed to be an asset or liability is recognized in
accordance with IAS 39 either in profit or loss or as a change to other comprehensive income. Contingent
consideration that is classified as equity is not remeasured, and its subsequent settlement is accounted for within
equity.
The Company measures goodwill at the acquisition date as the fair value of the consideration transferred including the
recognized amount of any non-controlling interests in the acquiree, less the fair value of the identifiable assets acquired
and liabilities assumed, all measured as of the acquisition date.
Transaction costs, other than those associated with the issue of debt or equity securities, that the Company incurs in
connection with a business combination are expensed as incurred.
• Subsidiaries: The consolidated financial statements of the Company incorporates the assets, liabilities and results of
InterOil Corporation and of all subsidiaries as at December 31, 2011 and December 31, 2010, and for the periods then
ended. Subsidiaries of InterOil Corporation as at December 31, 2011 included SP InterOil LDC (100%), SPI E
xploration and Production Corporation (100%), SPI Distribution Limited (100%), InterOil LNG Holdings Inc. (100%),
InterOil Australia Pty Ltd (100%), Direct Employment Services Company (100%), InterOil New York Inc. (100%), InterOil
Singapore Pte Ltd (100%), InterOil Finance Inc. (100%), InterOil Shipping Pte Ltd (100%) and their subsidiaries. InterOil
Corporation and its subsidiaries together are referred to in these consolidated financial statements as the Company or
the consolidated entity.
Subsidiaries are all those entities over which the Company has the power to determine strategic operating, investing
and financing policies without the cooperation of others. The existence and effect of potential voting rights that are
currently exercisable or convertible are considered when assessing whether the Company controls another entity.
Subsidiaries are fully consolidated from the date on which control is transferred to the Company. They are de
consolidated from the date that control ceases.
Intercompany transactions, balances and unrealized gains on transactions between companies are eliminated on
consolidation. Non-controlling interests in the results and equity of subsidiaries are shown separately in the
consolidated income statements, statements of comprehensive income, balance sheets and statement of changes in
equity.
In April 2010, InterOil Shipping Pte Ltd. was incorporated in Singapore as a 100% subsidiary of InterOil Corporation to
provide shipping services to domestic customers within PNG and also to export customers from PNG.
In May 2010, SPI CSP Holdings Limited was incorporated in PNG as a 100% subsidiary of SPI Exploration &
Production Corporation to hold InterOil’s interest in the proposed condensate stripping facilities, including gathering
condensate pipeline, condensate storage and associated facilities being progressed in joint venture with Mitsui & Co.
Ltd. (“CS Project”).
In May 2010, SPI Holdings No.1 Limited was incorporated in PNG as a 100% subsidiary of SPI (208) Limited to hold an
interest in PRL15. There have been no transactions in this entity as of December 31, 2011.
In May 2010, SPI Holdings No.2 Limited was incorporated in PNG as a 100% subsidiary of SPI (208) Limited to hold an
interest in PRL15. There have been no transactions in this entity as of December 31, 2011.
In June 2010, Champion No. 50 Limited was incorporated in PNG as a 100% subsidiary of Liquid Niugini Gas Limited.
In January 2011, this company underwent a change of name to LNG Train 1 Limited and then a further name change
in February 2011 to LNGL Train 1 Limited. The purpose of LNGL Train 1 Limited is to be the owner and operator of a
modular LNG plant to be acquired from Energy World Corporation. There have been no transactions in this entity as of
December 31, 2011.
In May 2011, SPI Holdings No.3 Limited was incorporated in PNG as a 100% subsidiary of SPI (208) Limited to hold an
interest in PRL15. There have been no transactions in this entity as of December 31, 2011.
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• Proportionate consolidation of Joint Venture interests: The Company’s interests in PNG LNG Inc. is governed by a
Shareholders’ Agreement signed on July 30, 2007 between the Joint Ventures’. Guidance under IAS 31 – ‘Interest
in Joint Ventures’ is followed and the entity has been proportionately consolidated in InterOil’s consolidated financial
statements. The consolidated results of InterOil’s proportionate shareholding in the LNG Project has been disclosed
separately within the segment notes under Midstream - Liquefaction, refer to note 5.
(e) Segment Reporting
An operating segment is a component of an enterprise:
• that engages in business activities from which it may earn revenues and incur expenses (including revenues and
expenses relating to transactions with other segments of the same enterprise),
• whose operating results are regularly reviewed by the chief operating decision maker to make decisions about
resources to be allocated to the segment and assess its performance, and
• for which discrete financial information is available.
Segment capital expenditure is the total cost incurred during the period to acquire property, plant and equipment, and
intangible assets other than goodwill. Refer to note 1 for the management’s organization of the Company by reporting segment.
(f) Foreign Currency
• Functional and presentation currency: These consolidated financial statements are presented in United States Dollars
(“USD”) which is InterOil’s functional and presentation currency.
• Foreign currency transactions: Transactions in foreign currencies are translated to the respective functional currencies
of Company entities at exchange rates at the dates of the transactions. Monetary assets and liabilities denominated
in foreign currencies at the reporting date are retranslated to the functional currency at the exchange rate at that date.
The foreign currency gain or loss on monetary items is the difference between amortized cost in the functional currency
at the beginning of the period, adjusted for effective interest and payments during the period, and the amortized cost in
foreign currency translated at the exchange rate at the end of the period.
Non-monetary assets and liabilities denominated in foreign currencies that are measured at fair value are retranslated
to the functional currency at the exchange rate at the date that the fair value was determined. Non-monetary items in a
foreign currency that are measured in terms of historical cost are translated using the exchange rate at the date of the
transaction. Foreign currency differences arising on retranslation are recognized in profit or loss.
• Foreign operations: For subsidiaries considered to be foreign operations, all assets and liabilities denominated in
foreign currency are translated to USD at exchange rates in effect at the balance sheet date and all revenue and
expense items are translated at the rates of exchange in effect at the time of the transactions. Foreign exchange gains
or losses are recognized and presented in other comprehensive income and in the foreign currency translation reserve
in equity. Goodwill and fair value adjustments arising on the acquisition of a foreign operation are treated as assets and
liabilities of the foreign operation and translated at the closing rate.
(g) Financial Instruments
(i) Non-derivative financial assets
The Company initially recognizes loans and receivables and deposits on the date that they are originated. All other financial
assets (including assets designated at fair value through profit or loss) are recognized initially on the trade date at which the
Company becomes a party to the contractual provisions of the instrument. The Company derecognizes a financial asset when
the contractual rights to the cash flows from the asset expire, or it transfers the rights to receive the contractual cash flows
on the financial asset in a transaction in which substantially all the risks and rewards of ownership of the financial asset are
transferred. Any interest in transferred financial assets that is created or retained by the Company is recognized as a separate
asset or liability. Financial assets and liabilities are offset and the net amount presented in the balance sheet when, and only
when, the Company has a legal right to offset the amounts and intends to either settle on a net basis or to realize the asset
and settle the liability simultaneously. The Company classifies non-derivative financial assets into the following categories:
financial assets at fair value through profit or loss, loans or receivables, held to maturity financial assets and available-for-sale
financial assets.
• Loans and receivables: Loans and receivables are financial assets with fixed or determinable payments that are not
quoted in an active market. Such assets are recognized initially at fair value plus any directly attributable transaction
costs. Subsequent to initial recognition loans and receivables are measured at amortized cost using the effective
interest method, less any impairment losses. Loans and receivables comprise of trade and other receivables.
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• Held-to-maturity: Held-to-maturity investments are non-derivative financial assets with fixed or determinable payments
and fixed maturities that the Company’s management has the positive intention and ability to hold to maturity.
Held-to-maturity financial assets are recognized initially at fair value plus any directly attributable transaction costs.
Subsequent to initial recognition, held-to-maturity financial assets are measured at amortized cost using the effective
interest method, less any impairment losses. If the Company were to sell other than an insignificant amount of
held-to-maturity financial assets, the whole category would be tainted and reclassified as available-for-sale.
Held-to-maturity financial assets are included in non-current assets, except for those with maturities less than 12
months from the end of the reporting period, which are classified as current assets.
• Available-for-sale: Available-for-sale financial assets are non-derivative financial assets that are designated as available
for sale or are not classified in any of the other categories. The Company’s investments in equity securities are
classified as available-for-sale financial assets. Subsequent to initial recognition, they are measured at fair value and
changes therein, other than impairment losses, are recognized in other comprehensive income. When an investment is
derecognized, the gain or loss accumulated in equity is reclassified to profit or loss.
(ii) Non-derivative financial liabilities
The Company initially recognizes debt securities issued and subordinated liabilities on the date that they originated. All other
financial liabilities (including liabilities designated at fair value through profit or loss) are recognized initially on the trade date at
which the Company becomes a party to the contractual provisions of the instrument. The Company derecognizes a financial
liability when its contractual obligations are discharged or cancelled or expire. Financial assets and liabilities are offset and the
net amount presented in the balance sheet when, and only when, the Company has a legal right to offset the amounts and
intends to either settle on a net basis or to realize the asset and settle the liability simultaneously.
The Company classifies non-derivative financial liabilities into the other financial liabilities category. Financial liabilities not
designated at fair value through profit or loss are recognized initially at fair value plus any directly attributable transaction
costs. Subsequent to initial recognition, these financial liabilities are measured at amortized cost using the effective interest
method. Other financial liabilities comprise secured and unsecured loans, bank overdrafts, and trade and other payables.
Trades and other payables represent liabilities for goods and services provided to the Company prior to the end of financial
period which are unpaid. These amounts are unsecured and are usually paid within 30 days of recognition.
(iii) Derivative financial instruments
Derivative financial instruments are utilized by the Company in the management of its crude purchase cost exposures, its
finished products sales price exposures and its foreign exchange management. The Company’s policy is not to utilize
derivative financial instruments for trading or speculative purposes. The Company may choose to designate derivative
financial instruments as hedges.
When applicable, at the inception of the hedge, the Company formally documents all relationships between hedging
instruments and the hedged items, as well as its risk management objective and strategy for undertaking various hedge
transactions, the nature of the risk being hedged, how the hedging instruments’ effectiveness in offsetting the hedged risk will
be assessed and a description of the method for measuring effectiveness. This process includes linking all derivatives to specific
assets and liabilities on the balance sheet or to specific firm commitments or anticipated transactions. The Company also
assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or
cash flows of hedged items at inception and on an ongoing basis.
Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are
recorded as a component of Other Comprehensive Income until earnings are affected by the variability in cash flows of the
designated hedged item. For cash flow hedges that have been terminated or cease to be effective, prospective gains or
losses on the derivative are recognized in earnings. Any gain or loss that has been included in accumulated other
comprehensive income at the time the hedge is discontinued continues to be deferred in accumulated other comprehensive
income until the original hedged transaction is recognized in earnings. If the likelihood of the original hedged transaction
occurring is no longer probable, the entire gain or loss in accumulated other comprehensive income related to this transaction
is immediately reclassified to earnings.
The Company discontinues hedge accounting prospectively when it is determined that the derivative is no longer effective in
offsetting changes in cash flows of the hedged item, the derivative expires or is sold, terminated or exercised, the derivative
is no longer designated as a hedging instrument because it is unlikely that a forecasted transaction will occur, a hedged firm
commitment no longer meets the definition of a firm commitment or management determines that designation of the
derivative as a hedging instrument is no longer appropriate.
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(iv) Compound financial instruments
Compound financial instruments issued by the Company comprise convertible notes that can be converted to share capital
at the option of the holder, when the number of shares to be issued does not vary with changes in their fair value. The liability
component of a compound financial instrument is recognized initially at fair value of a similar liability that does not have an
equity conversion option. The equity component is recognized initially at the difference between the fair value of the
compound financial instrument as a whole and the fair value of the liability component. Any directly attributable transaction
costs are allocated to the liability and equity components in proportion to their initial carrying amounts.
Subsequent to initial recognition, the liability component of a compound financial instrument is measured at amortized cost
using the effective interest method. The equity component of a compound financial instrument is not remeasured subsequent
to initial recognition. Interest and losses and gains relating to the financial liability are recognized in profit or loss. On
conversion, the financial liability is reclassified to equity and no gain or loss is recognized on conversion.
(h) Cash and cash equivalents
Cash and cash equivalents includes cash on hand, deposits held at call with financial institutions, other short-term, highly
liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and
which are subject to insignificant risk of changes in value.
(i) Cash restricted
Cash restricted consists of cash on deposit which is restricted from being used in daily operations. Cash restricted is carried
at cost and any accrued interest is classified under other assets.
(j) Inventory
• Raw materials and parts inventory: Raw materials and parts inventory are stated at the lower of costs and net
realizable value. Costs comprise direct materials, direct labor and an appropriate proportion of variable and fixed
overhead expenditure. Net realizable value is the estimated selling price in the ordinary course of the business less the
estimated costs of completion and the estimated costs necessary to make the sale.
• Crude oil and refined petroleum products: Crude oil and refined petroleum products are recorded on a first-in, first-out
basis and the net realizable value test for crude oil and refined petroleum products are performed separately. The cost
of Midstream Refining petroleum products consist of raw material, labor, direct overheads and transportation costs.
The cost of Downstream petroleum products includes the cost of the product plus related freight, wharfage and
insurance.
(k) Deferred financing costs
Deferred financing costs represent the unamortized financing costs paid to secure borrowings. Amortization is provided on an
effective yield basis over the term of the related debt and is included in expenses for the period. Unamortized deferred
financing costs are offset against the respective liability accounts.
(l) Plant and equipment
• Refinery assets: The Company’s most significant item of plant and equipment is the oil refinery in PNG which is
included within Midstream Refining assets. The pre-operating stage of the refinery ceased on January 1, 2005. Project
costs, net of any recoveries, incurred during the pre-operating stage were capitalized as part of plant and equipment.
Development costs and the costs of acquiring or constructing support facilities and equipment are also capitalized.
Interest costs relating to the construction and pre-operating stage of the development project prior to commencement
of commercial operations were capitalized as part of the cost of such plant and equipment.
The refinery assets are recorded at cost less accumulated depreciation and accumulated impairment losses, if any.
Refinery related assets are depreciated on straight line basis over their useful lives, at an average rate of 4% per
annum. The refinery is built on land leased from the State. The lease expires on July 26, 2097.
Repairs and maintenance costs, other than major turnaround costs, are expensed as incurred. Major turnaround costs
will be capitalized when incurred and amortized over the estimated period of time to the next scheduled turnaround.
Major turnaround work commenced at the refinery on October 1, 2010 and was completed on November 2, 2010 with
the refinery being shut down during the turnaround period. Turnaround costs of approximately $2.5 million had been
incurred during the year ended December 31, 2010, and no major turnaround costs have been incurred since.
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• Other assets: Property, plant and equipment are recorded at amortized cost. Depreciation of assets begins when the
asset is in place and ready for its intended use. Assets under construction and deferred project costs are not
depreciated. Depreciation of plant and equipment is calculated using the straight line method, based on the estimated
service life of the asset. Maintenance and repair costs are expensed as incurred. Improvements that increase the
capacity or prolong the service life of an asset are capitalized.
Land is not depreciated. Depreciation on other assets is calculated using the straight-line method to allocate their cost
or revalued amounts, net of their residual values, over their estimated useful lives as follows:
Leasehold land improvements
Refinery
Buildings
Plant and equipment
Motor vehicles
Shorter of 100 years or lease period
25 – 33 years
20 – 40 years
3 – 15 years
4 – 5 years
• Leased assets (accounting as lessee): Leases of property, plant and equipment where the Company has substantially
all the risks and rewards of ownership are classified as finance leases. Finance leases are classified at the inception of
the lease at the lower of the fair value of the leased property and the present value of the minimum lease payments.
The corresponding rental obligations, net of finance charges, are included in other long term payables. Each lease
payment is allocated between the liability and the finance charges so as to achieve a constant rate on the finance
balance outstanding. The interest element of the finance cost is charged to the comprehensive income statement over
the lease period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each
period. The property, plant and equipment acquired under finance leases are depreciated over the shorter of the
asset’s useful life and the lease term.
Leases in which a significant portion of the risks and rewards of ownership are retained by the lessor are classified as
operating leases. Operating lease payments are representative of the pattern of benefit derived from the leased asset
and accordingly are included in expenses on a straight line basis over the period of the lease.
• Leased assets (accounting as lessor): Assets are leased out under an operating lease. The asset is included in the
balance sheet based on the nature of the asset. Lease income is recognized over the term of the lease on a
straight-line basis.
• Asset retirement obligations: A liability is recognized for future legal or constructive retirement obligations associated
with the Company’s property, plant and equipment. The amount recognized is the net present value of the estimated
costs of future dismantlement, site restoration and abandonment of properties based upon current regulations and
economic circumstances at period end. During the quarter ended June 30, 2011, Management received the results of
an independent assessment of the potential asset retirement obligations of the refinery. As a result of this assessment,
Management has recognized an asset retirement obligation at December 31, 2011 of $4,562,269 (refer to note 23 for
further details). No asset retirement obligations had been recognized at December 31, 2010.
• Environmental remediation: Remediation costs are accrued based on estimates of known environmental remediation
exposure. Ongoing environmental compliance costs, including maintenance and monitoring costs, are expensed as
incurred. Provisions are determined on an assessment of current costs, current legal requirements and current
technology. Changes in estimates are dealt with on a prospective basis.
• Disposal of property, plant and equipment: At the time of disposal of plant and equipment, the carrying values of the
assets are written off along with accumulated depreciation and any resulting gain or loss is included in the income
statement. Gains and losses on disposals are determined by comparing proceeds with carrying amounts.
• IT Development and software: Costs incurred in development products or systems and costs incurred in acquiring
software and licenses that will contribute to future period financial benefits through revenue generation and/or cost
reduction are capitalized. Costs capitalized include external direct costs of materials and service, direct payroll and
payroll related costs of employees’ time spent on the project. Amortization is calculated on a straight line basis over
periods generally ranging from 3 to 5 years. IT development costs include only those costs directly attributable to the
development phase and are only recognized following completion of technical feasibility and where the Company has
an intention and ability to use the asset. These amounts are capitalized as part of property, plant and equipment in the
Corporate segment.
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(m) Oil and gas properties
The Company uses the successful-efforts method to account for its oil and gas exploration and development activities. Under
this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes
being expensed as incurred. The Company continues to carry as an asset the cost of drilling exploratory wells if the
required capital expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near
future or when exploration and evaluation activities have not yet reached a stage to allow reasonable assessment regarding
the existence of economic reserves. Capitalized costs for producing wells will be subject to depletion using the units of
production method.
Geological and geophysical costs are expensed as incurred, except when they have been incurred to facilitate production
techniques, to increase total recoverability and to determine the desirability of drilling additional development wells within a
proved area. Geological and geophysical costs capitalized would be included as part of the cost of producing wells and be
subject to depletion using the units-of-production method.
(n) Impairment
• Non-derivative financial assets: A financial asset not carried at fair value through profit or loss is assessed at each
reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to
be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future
cash flows of that asset.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between
its carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest
rate. An impairment loss in respect of an available-for-sale financial asset is calculated by reference to its fair value.
Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets
are assessed collectively in groups that share similar credit risk characteristics.
All impairment losses are recognized in the consolidated income statement. An impairment loss, other than relating to
available-for-sale equity instruments, is reversed through profit and loss if the reversal can be related objectively to an
event occurring after the impairment loss was recognized. The reversal of an impairment loss relating to available for
sale equity instruments is through other comprehensive income.
Trade receivables
The collectability of trade receivables is assessed on an ongoing basis. Debts which are known to be uncollectible are
written off by reducing the carrying amount directly. An allowance account (provision for impairment of trade
receivables) is used when there is objective evidence that the company will not be able to collect all amounts due
according to the original terms of the receivables. Significant financial difficulties of the debtor, probability that the
debtor will enter bankruptcy or financial reorganization, and default or delinquency in payments are considered
indicators that the trade receivable is impaired. The amount of the impairment allowance is the difference between the
asset’s carrying amount and the present value of estimated future cash flows, discounted at the original effective
interest rate. Cash flows relating to short-term receivables are not discounted if the effect of discounting is immaterial.
The amount of the impairment loss is recognized in the income statement. When a trade receivable for which an
impairment allowance had been recognized becomes uncollectible in a subsequent period, it is written off against the
allowance account. Subsequent recoveries of amounts previously written off are credited against the income
statement.
The Company sells certain trade receivables with recourse to BNP Paribas under its working capital facility. The
receivables are retained on the balance sheet as the Company retains the credit risk and control over these receivables.
• Non-financial assets: The carrying amounts of the Company’s non-financial assets, other than inventories and deferred
tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such
indication exists then the asset’s recoverable amount is estimated. For goodwill, and intangible assets that have
indefinite useful lives or that are not yet available for use, the recoverable amount is estimated each period at the same
time.
The recoverable amount of an asset is the greater of its value in use and its fair value less costs to sell and is
determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of
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those from other assets or groups of assets. In that situation, the assets are tested as part of a cash-generating unit
(“CGU”), which is the smallest identifiable group of assets, liabilities and associated goodwill that generates cash
inflows that are largely independent of the cash inflows from other assets or groups of assets.
Fair value is the amount of the consideration that would be agreed upon in an arm’s length transaction between
knowledgeable, willing parties who are under no compulsion to act. Value in use is determined as the net present value
of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its
eventual disposal, discounted at the risk free rate of interest plus a risk premium. If an impairment loss is
recognized, the adjusted carrying amount becomes the new cost basis.
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its recoverable amount.
Impairment losses are recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill
allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU on a pro rata basis.
Impairment losses are recognized in profit or loss.
Impairment losses recognized in prior periods are assessed at each reporting date for any indications that the loss
has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to
determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount
does not exceed the carrying amount that would have been determined, net of depreciation or amortization, if no
impairment loss had been recognized.
There has been no impairment of assets or goodwill based on the assessments performed during the period.
(o) Revenue recognition
Revenue is measured at the fair value of the consideration received or receivable. Amounts disclosed as revenue are net of
returns, trade allowances and duties and taxes paid. The following particular accounting policies, which significantly affect the
measurement of results, have been applied.
• Revenue from Midstream Refining operations: Revenue from sales of products is recognized when products are
shipped and the customer takes ownership and assumes risk of loss, collection of the relevant receivable is probable
and when the amount of revenue can be reliably measured. Sales between the operating segments of the Company
have been eliminated from sales and operating revenues and cost of sales.
• Revenue from Downstream operations: Sales of goods are recognized when the Company has delivered products to
the customer, the customer takes ownership and assumes risk of loss, collection of the receivable is probable, and
when the amount of revenue can be reliably measured. It is not the Company’s policy to sell products with a right of
return.
• Revenue from Upstream operations: Revenue from rig and constructions services are recognized in the accounting
period in with the services are rendered.
• Interest revenue: Interest revenue is recognized as the interest accrues using the effective interest rate.
(p) Income tax
Income tax comprises current and deferred tax. Income tax is recognized in the income statement except to the extent that
it relates to items recognized directly in other comprehensive income or directly in equity, in which case the income tax is also
recognized directly in other comprehensive income or equity respectively.
The income tax expense or benefit for the period is the tax payable on the current period’s taxable income based on the
national income tax rate for each jurisdiction; adjusted by changes in deferred tax assets and liabilities attributable to
temporary differences between the tax bases of assets and liabilities and their carrying amounts in the financial statements
and to unused tax losses.
Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation
is subject to interpretation.
Deferred tax assets and liabilities are recognized for temporary differences at the tax rates expected to apply when the assets
are recovered or liabilities are settled, based on those tax rates which are enacted or substantively enacted for each
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jurisdiction. The relevant tax rates are applied to the cumulative amounts of deductible and taxable temporary differences to
measure the deferred tax asset or liability. Deferred income tax assets and liabilities are presented as non-current.
Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets and liabilities
and when the deferred tax balances relate to the same taxation authority. Current tax assets and tax liabilities are offset where
the entity has a legally enforceable right to offset and intends either to settle on a net basis, or to realize the asset and settle
the liability simultaneously.
Deferred tax assets are recognized for deductible temporary differences and unused tax losses only if it is probable that future
taxable amounts will be available to utilize those temporary differences and losses. Deferred tax assets are reviewed at each
reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.
The Refinery Project Agreement gave “pioneer” status to InterOil Limited (”IOL”). This status gave IOL a tax holiday beginning
upon the date of the commencement of commercial production, January 1, 2005 and ended December 31, 2010.
In addition to income taxes, InterOil is subject to Goods and Services Tax, Excise Duty and other taxes in PNG, Australia,
Singapore and Canada. The consolidated financial statements are prepared on a net of Goods and Services Tax basis.
(q) Employee entitlements
• Wages and salaries, and annual leave: Liabilities for wages and salaries, including annual leave expected to be settled
within 12 months of the reporting date are recognized in accounts payable and accrued liabilities in respect of
employees’ services up to the reporting date and are measured at the amounts expected to be paid when liabilities are
settled.
• Long service leave: The liability for long service leave is recognized in the provision for employee benefits and
measured as the present value of expected future payments to be made in respect of services provided by employees
up to the reporting date. Consideration is given to expected future wage and salary levels, experience of employee
departures, periods of service and statutory obligations.
• Post-employment obligations: The Company contributed to a defined contribution plan and the Company’s legal or
constructive obligation is limited to these contributions. Contributions to the defined contribution fund are recognized
as an expense as they become payable.
• Share-based payments: Stock-based compensation benefits are provided to employees and directors pursuant to the
2009 Stock Incentive Plan (with options still in existence having been granted under the now superseded 2006 Stock
Incentive Plan). The Company currently issues stock options and restricted stock units as part of its stock-based
compensation plan. The fair value of stock options at grant date is determined using a Black-Scholes option pricing
model that takes into account the exercise price, the terms of the option, the vesting criteria, the share price at grant
date and expected price volatility of the underlying share, the expected yield and risk-free interest rate for the term of
the option. Upon exercise of options, the balance of the contributed surplus relating to those options is transferred to
share capital. The fair value of restricted stock units on grant date is the market value of the stock.
The Company uses the fair value based method to account for employee stock based compensation benefits. Under
the fair value based method, compensation expense is measured at fair value at the date of grant and is expensed over
the award’s vesting period.
• Profit-sharing and bonus plans: The Company recognizes a provision where contractually obliged or where there is a
past practice that has created a constructive obligation.
(r) Earnings per share
• Basic earnings per share: Basic common shares outstanding are the weighted average number of common shares
outstanding for each period. Basic earnings per share is calculated by dividing the profit or loss attributable to
shareholders of the Company by the weighted average number of common shares outstanding during the period.
• Diluted earnings per share: Diluted earnings per share is determined by adjusting the profit or loss attributable to
shareholders and the weighted average number of common shares outstanding, for the effects of all dilutive potential
ordinary shares, which comprise convertible notes and share options granted to employees.
78

3. Transition to International Financial Reporting Standards (“IFRS”)
(a) Basis of transition to IFRS
(i) Application of IFRS 1
The Company’s financial statements for the year ending December 31, 2011, are the first annual financial statements that
comply with IFRS as disclosed in Note 2(a). The Company has applied IFRS 1 in preparing these consolidated financial
statements.
The Company’s transition date is January 1, 2010. The Company prepared its opening IFRS balance sheet at that date. The
reporting date of these consolidated financial statements is December 31, 2011. In preparing these consolidated financial
statements in accordance with IFRS 1, the Company has applied the relevant mandatory exceptions and certain optional
exemptions from full retrospective application of IFRS.
(ii) Exemptions from full retrospective application – elected by the Company
The Company has elected to apply the following optional exemptions from full retrospective application.
• Business combinations exemption: 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. InterOil has made the election not to apply IFRS 3 retrospectively to past business combinations.
• Fair value as deemed cost exemption: 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. InterOil has made the
election not to use deemed cost. Historical cost will be maintained as plant and equipment cost base on transition.
• Cumulative translation differences exemption: Consistent with the Company’s Canadian GAAP treatment in prior
periods, 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. InterOil has not made the election to restate its
cumulative translation differences balance to zero, and has elected to continue with the current translation differences
in comprehensive income as these are already in compliance with IAS 21.
• Oil and Gas assets exemption: 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 D8A 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. InterOil has availed this exemption and elected to maintain the
Company’s Oil and Gas assets at carrying amount under Canadian GAAP treatment in prior periods, which will be the
deemed cost under IFRS.
• Interests in Joint Ventures entities exemption: Superseded 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 venture entities. 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. Superseded CICA Section 3055 only allows the use of proportionate
consolidation method to account for joint venture entities. InterOil has elected to maintain its joint venture accounting
under the proportionate consolidation model for both its incorporated and unincorporated joint venture interests.
The remaining optional exemptions are not applicable to the Company.
(iii) Exceptions from full retrospective application followed by the Company
All mandatory exceptions in IFRS 1 were not applicable because there were no significant differences in management’s
application of Canadian GAAP in these areas.
79

(b) Reconciliations between IFRS and Canadian GAAP
The following reconciliations provide a quantification of the effect of the transition to IFRS. The first reconciliation provides an
overview of the impact on equity of the transition at January 1, 2010 and December 31, 2010. The second reconciliation
provides an overview of the impact of the transition on comprehensive income for the year ended December 31, 2010. There
are no material differences between the statement of cash flows presented in accordance with IFRSs and the statement of
cash flows presented in accordance with Canadian GAAP.
(i) Reconciliation of equity
Assets
Current assets:
Candian GAAP
January 2, 2010
$
Effect of transition
to IFRSs
$
IFRS
January 1, 2010
Candian GAAP
December 31,
2010
$
Effect of transition
to IFRSs
$
IFRS
December 31, 2010
Cash and cash equivalents 46,449,819 - 46,449,819 233,576,821 - 233,576,821
Cash restricted 22,698,829 - 22,698,829 40,664,995 - 40,664,995
Trade receivables 61,194,136 - 61,194,136 48,047,496 - 48,047,496
Other assets 639,646 - 639,646 505,059 - 505,059
Inventories 70,127,049 - 70,127,049 127,137,360 - 127,137,360
Prepaid expenses 6,964,950 - 6,964,950 3,593,574 - 3,593,574
Total current assets 208,074,429 - 208,074,429 453,525,305 - 453,525,305
Non-current assets:
Cash restricted 6,609,746 - 6,609,746 6,613,074 - 6,613,074
Goodwill 6,626,317 - 6,626,317 6,626,317 - 6,626,317
Plant and equipment (1) 221,046,709 (2,252,060) 218,794,649 229,331,842 (4,126,415) 225,205,427
Oil and gas properties 172,483,562 - 172,483,562 255,294,738 - 255,294,738
Deferred tax assets (2) 16,912,969 13,406,194 30,319,163 14,098,128 14,379,562 28,477,690
Total non-current assets 423,679,303 11,154,134 434,833,437 511,964,099 10,253,147 522,217,246
Total assets 631,753,732 11,154,134 642,907,866 965,489,404 10,253,147 975,742,551
Liabilities and shareholders' equity
Current liabilities:
Accounts payable and accrued
liabilities
59,372,354 - 59,372,354 76,087,954 - 76,087,954
Derivative contracts - - - 178,578 - 178,578
Working capital facilities 24,626,419 - 24,626,419 51,254,326 - 51,254,326
Current portion of secured and
unsecured loans
Current portion of Indirect
participation interest
9,000,000 - 9,000,000 14,456,757 - 14,456,757
540,002 - 540,002 540,002 - 540,002
Total current liabilities 93,538,775 - 93,538,775 142,517,617 - 142,517,617
Non-current liabilities:
Secured loan 43,589,278 - 43,589,278 34,813,222 - 34,813,222
2.75% convertible notes liability - - - 52,425,489 - 52,425,489
Deferred gain on contributions to
LNG project (1)
13,076,272 (2,252,060) 10,824,212 13,076,272 (4,126,415) 8,949,857
Indirect participation interest 39,559,718 - 39,559,718 34,134,387 - 34,134,387
Total non-current liabilities 96,225,268 (2,252,060) 93,973,208 134,449,370 (4,126,415) 130,322,955
Total liabilities 189,764,043 (2,252,060) 187,511,983 276,966,987 (4,126,415) 272,840,572
Non-controlling interest 13,596 - 13,596 20,099 - 20,099
Shareholders' equity:
Share capital 613,361,363 - 613,361,363 895,651,052 - 895,651,052
2.75% convertible notes - - - 14,298,036 - 14,298,036
Contributed surplus 21,297,177 - 21,297,177 16,738,417 - 16,738,417
Accumulated Other Comprehensive
Income
8,150,976 - 8,150,976 9,261,177 - 9,261,177
Conversion options 13,270,880 - 13,270,880 12,150,880 - 12,150,880
Accumulated deficit (2) (214,104,303) 13,406,194 (200,698,109) (259,597,244) 14,379,562 (245,217,682)
Total shareholders' equity 441,976,093 13,406,194 455,382,287 688,502,318 14,379,562 702,881,880
Total liabilities and shareholders'
equity
631,753,732 11,154,134 642,907,866 965,489,404 10,253,147 975,742,551
80

(ii) Reconciliation of total comprehensive income
Canadian
GAAP
December 31,
2010
$
Year ended
Effect of transition
to IFRSs
$
IFRS
December 31,
2010
$
Loss for the period (2) (45,486,439) 973,368 (44,513,071)
Other comprehensive income/(loss):
Exchange difference on translation of foreign operations, net of tax 1,110,201 - 1,110,201
Other comprehensive income/(loss) for the period, net of tax 1,110,201 - 1,110,201
Total comprehensive income/(loss) for the period (44,376,238) 973,368 (43,402,870)
(iii) Notes to the reconciliations
• In September 2009, as part of acquisition by Pacific LNG of a 2.5% direct working interest in the Elk and Antelope
fields, Pacific LNG transferred to InterOil 2.5% of Pacific LNG’s unexercised economic interest in the joint venture
LNG Project. Based on this transaction, as at December 31, 2011, InterOil and Pacific LNG hold 52.5% and 47.5%
economic interest respectively in the LNG project, subject to the exercise of all their rights to the ‘B’ Class shares on
payment of cash calls.
To date InterOil has a recognized deferred gain on its contributions to the Joint Venture based on the share of other
joint venture partners in the project. As InterOil’s shareholding within the Joint Venture Company as at December 31,
2011 is 84.582% (Dec 2010 – 86.66%), the gain on contribution of non cash assets to the project by InterOil relating
to other joint venture partners’ shareholding (15.418% - amounting to $15,113,190) has been recognized by InterOil
in its balance sheet as a deferred gain. This deferred gain will increase/decrease as the other Joint Venture partners
decrease/increase their shareholding in the project. Previously under Canadian GAAP, the amount was recognized as
a deferred gain in full. However, under IFRS, unrealized gains or losses on non-monetary assets contributed to joint
ventures shall be eliminated against the underlying assets under the proportionate consolidation method. Such
unrealized gains or losses shall not be presented as deferred gains or losses in the venturer’s consolidated balance
sheet.
As such, the deferred gain has been recorded as a reduction of deferred LNG project costs of $9,302,415 at
December 31, 2011 (Dec 31, 2010 - $4,126,415, Jan 1, 2010 - $2,252,060), which has reduced the LNG project
costs to nil at December 31, 2011, with the remaining balance of $5,810,775 (Dec 31, 2010 - $8,949,857, Jan 1, 2010
- $10,824,212) being recorded as a deferred gain. The deferred gain will be recognized in the consolidated income
statement when the risks and rewards have considered to be passed. The intangible assets of the Joint Venture
Company, contributed by InterOil, have been eliminated on proportionate consolidation of the joint venture balances.
• In accordance with guidance under IFRS, deferred tax assets have been recognized for temporary differences that
arise on translation of the nonmonetary assets held by Midstream refining operations that are translated from the
functional currency of the tax return (PGK) to the reporting currency (USD) using period end rates. Previously under
Canadian GAAP, these temporary differences in relation to functional currency translation of nonmonetary assets were
specifically disallowed from recognition.
4. Financial Risk Management
The Company’s activities expose it to a variety of financial risks; market risk, credit risk, liquidity risk and geographic risk. The
Company’s overall risk management program focuses on the unpredictability of markets and seeks to minimize potential
adverse effects on the financial performance of the Company. The Company uses derivative financial instruments to hedge
certain price risk exposures.
Risk Management is carried out under policies approved by the Board of Directors. The Finance Department identifies,
evaluates and hedges financial risks in close cooperation with the Company’s operating units. The product pricing risks are
managed by the Supply and Trading Department under the guidance of the Risk Management Committee. The Board
provides written principles for overall risk management, as well as written policies covering specific areas, such as use of
derivative financial instruments. The Company’s overall risk management program seeks to minimize potential adverse effects
on the Company’s financial performance.
81

(a) Market risk
(i) Foreign exchange risk
Foreign exchange risk arises when future commercial transactions and recognized assets and liabilities are denominated in a
currency that is not the Company’s functional currency. The Company operates internationally and is exposed to foreign
exchange risk arising from currency exposures to the USD. The consolidated financial statements are presented in USD which
is the Company’s functional and reporting currency. Most of the Company’s transactions are undertaken in USD, PGK,
Australian Dollars (“AUD”) and Singapore Dollars (“SGD”).
The PGK exposures mainly relate to the exchange rates achieved from the banks on transfer of PGK sale proceeds to USD to
repay the Company’s crude cargo borrowings. The rates achieved fluctuate significantly based on other exporters /
importers looking to convert their USD into PGK, and is also impacted by seasonality based farm produce exports from PNG.
The Company is unable to do any hedging due to PGK illiquidity and small size of the market. The translation of PGK
denominated balances in the Company’s operating entities into USD at period ends can also result in material impact on the
foreign exchange gains/losses on consolidation.
Changes in the PGK to USD exchange rate can affect the Company’s Midstream Refining results as there is a timing
difference between the foreign exchange rates utilized when setting the monthly PGK IPP price and the foreign exchange
rate used to convert the subsequent receipt of PGK proceeds to USD to repay the Company’s crude cargo borrowings. The
foreign exchange movement also impacts equity as translation gains/losses of the Company’s Downstream operations from
PGK to USD is included in other comprehensive income. The PGK strengthened against the USD during the year ended
December 31, 2011 (from 0.3785 to 0.4665).
The financial instruments denominated in PGK and translated to USD as at December 31, 2011 are as follows:
Financial assets
December 31, 2011
$
December 31, 2010
$
Cash and cash equivalents 42,669,762 11,789,931
Cash restricted 161,801 130,486
Short term treasury bills 11,832,110 -
Receivables 96,322,533 42,006,504
Other financial assets 3,289,791 1,771,866
Financial liabilities
Payables 30,866,291 16,980,909
Working capital facility 6,450,372 1,230,767
The following table summarizes the sensitivity of financial instruments held at balance sheet date to movement in the
exchange rate of the USD to the PGK, with all other variables held constant. Certain USD debt and other financial assets and
liabilities are not held in the functional currency of the relevant subsidiary. This results in an accounting exposure to exchange
gains and losses as the financial assets and liabilities are translated into the functional currency of the subsidiary that accounts
for those assets and liabilities. These exchange gains and losses are recorded in the consolidated income statement except
to the extent that they can be taken to equity under the Company’s accounting policy. If PGK appreciates/(depreciates) by 5%
against the USD, it will result in a gain/(loss) as per the table below.
Post-tax gain/(loss)
Impact on profit
$
December 31, 2011
$
Impact on equity
- excluding profit
impact
$
Year ended
Impact on profit
$
December 31, 2010
$
Impact on equity
- excluding profit
impact
$
Effect of 5% appreciation of PGK 2,386,925 3,474,679 212,281 1,662,074
82

The changes in AUD and SGD to USD exchange rate can affect the Company’s Corporate results as the expenses of the
Corporate offices in Australia and Singapore are incurred in the respective local currencies. The AUD and SGD exposures
are minimal currently as funds are transferred to AUD and SGD from USD as required. No material balances are held in AUD
or SGD. However, the Company is exposed to translation risks resulting from AUD and SGD fluctuations as in country costs
are being incurred in AUD and SGD and reporting for those costs being in USD. The Company has entered into AUD to USD
foreign currency forward contracts to manage the foreign exchange risk in relation to the expenses to be incurred in AUD.
(ii) Price risk
Product Price Risk
The Midstream Refining operations of the Company are largely exposed to price fluctuations during the period between the
crude purchases and the refined products leaving the refinery when sold to Downstream operations and other distributors.
The Company actively tries to manage the price risk by entering into derivative contracts to buy and sell crude and finished
products.
The derivative contracts are entered into by Management based on documented risk management strategies which have
been approved by the Risk Management Committee. All derivative contracts entered into are reviewed by the Risk
Management Committee as part of the meetings of the Committee.
The following table summarizes the sensitivity of derivative financial instruments held at balance sheet date to $10.0
movement in benchmark pricing, with all other variables held constant. If the pricing increases/(declines) by $10.0, it will result
in a (loss)/gain as per the table below.
Post-tax gain/(loss)
$10 increase in benchmark pricing of derivative
contracts
Impact on profit
$
December 31, 2011
$
Impact on equity
- excluding profit
impact
$
Year ended
Impact on profit
$
December 31, 2010
$
Impact on equity
- excluding profit
impact
$
(6,550,000) - (540,000) -
Securities Price Risk
The Company is also exposed to equity securities price risk. This arises from investments held by the Company and
classified in the balance sheet as available-for-sale. The Company’s equity investments are publicly traded and are quoted on
the Oslo stock exchange Axess. Refer to note 14 for further details of this investment.
The following table summarizes the sensitivity of these investments held at balance sheet date to 10% movement in
benchmark pricing, with all other variables held constant. If the pricing increases/(declines) by 10%, it will result in a (loss)/gain
as per the table below.
Post-tax gain/(loss)
10% increase in benchmark pricing of equity investments
10% decrease in benchmark pricing of equity
investments
Impact on profit
$
(365,079)
December 31, 2011
$
Impact on equity
- excluding profit
impact
$
Year ended
Impact on profit
$
December 31, 2010
$
Impact on equity
- excluding profit
impact
$
365,079 - -
(iii) Interest rate risk
Interest rate risk is the risk that the Company’s financial position will be adversely affected by movements in interest rates that
will increase the cost of floating rate debt or opportunity losses that may arise on fixed rate borrowings in a falling interest rate
environment. As the Company has no significant interest-bearing assets other than cash and cash equivalents, the
Company’s income and operating cash flows are substantially independent of changes in market interest rates.
83

The Company’s interest-rate risk arises from cash and cash equivalent balances, borrowings and working capital financing
facilities. Deposits/borrowings at variable rates expose the Company to cash flow interest-rate risk. Deposits/borrowings
at fixed rates expose the Company to fair value interest-rate risk. The Company is actively seeking to manage its cash flow
interest-rate risks by holding some cash, cash equivalents and borrowings in fixed rate instruments and others in variable rate
instruments.
The financial instruments exposed to cash flow and fair value interest rate risk are as follows:
Financial assets
December 31, 2011
$
December 31, 2010
$
“Cash flow/fair value
interest rate risk”
Cash and cash equivalents 37,891,187 1,205,304 fair value interest rate risk
Cash and cash equivalents 30,955,254 232,371,517 cash flow interest rate risk
Cash restricted 365,281 309,926 fair value interest rate risk
Cash restricted 38,885,482 46,968,143 cash flow interest rate risk
Short term treasury bills 11,832,110 - fair value interest rate risk
Financial liabilities
OPIC secured loan 35,500,000 44,500,000 fair value interest rate risk
Mitsui unsecured loan 10,393,023 5,456,757 cash flow interest rate risk
BNP working capital facility 10,030,131 50,023,559 cash flow interest rate risk
Westpac working capital facility 6,450,372 1,230,767 cash flow interest rate risk
2.75% convertible notes 70,000,000 70,000,000 fair value interest rate risk
The following table summarizes the sensitivity of the cash flow interest-rate risk of financial instruments held at balance date,
following a movement to LIBOR, with all other variables held constant. Increase in LIBOR rates will result in a higher expense
for the Company.
Post-tax loss/(gain)
Impact on profit
$
December 31, 2011
$
Impact on equity
- excluding profit
impact
$
Year ended
Impact on profit
$
December 31, 2010
$
Impact on equity
- excluding profit
impact
$
LIBOR Increase by 1% 507,666 - 338,291 -
(iv) Product risk
The composition of the crude feedstock will vary the refinery output of products. The 2011 year to date output achieved
includes gasoline and distillates fuels (which includes diesel and jet fuels) 58% (Dec 2010 – 53%), and naphtha and low
sulphur waxy residue 37% (Dec 2010 – 42%). The product yields obtained will vary based on the type of crude feedstock
used.
Management endeavors to manage the product risk by actively reviewing the market for demand and supply, trying to
maximize the production of the higher margin products and also renegotiating the selling prices for the lower margin products.
(b) Liquidity risk
Liquidity risk is the risk that InterOil will not meet its financial obligations as they fall due. Prudent liquidity risk management
therefore implies that, under both normal and stressed conditions, the Company maintains:
•
•
•
sufficient cash and marketable securities;
access to, or availability of, funding through an adequate amount of committed credit facilities and
the ability to close-out any open market positions.
The Company manages liquidity risk by continuously monitoring forecast and actual cash flows; matching maturity profiles of
financial assets and liabilities; and by maintaining flexibility in funding including ensuring that surplus funds are generally only
invested in instruments that are tradable in highly liquid markets or that can be relinquished with minimal risk of loss.
84

(i) Financing arrangements
The Company had the following established undrawn borrowing facilities at the reporting date:
Facility
Total Facility
Undrawn Amount
December 31, 2011
$
OPIC secured loan 35,500,000 -
Mitsui unsecured loan 10,393,023 -
2.75% convertible notes 70,000,000 -
BNP Paribas working capital facility 1* 200,000,000 35,090,000
BNP Paribas working capital facility 2 60,000,000 49,969,869
Westpac working capital facility (PGK denominated) 37,320,000 30,869,628
BSP working capital facility (PGK denominated) 23,325,000 23,325,000
* Includes the temporary increase of $30.0 million that expires on January 31, 2012.
436,538,023 139,254,497
(ii) Maturities of financial liabilities
The tables below analyses the Company’s financial liabilities, net and gross settled derivative financial instruments into relevant
maturity groupings based on the remaining period at the reporting date to the contractual maturity date. The amounts
disclosed in the table are the contractual undiscounted cash flows.
Non-derivatives
Less than 1 year
Between 1 and 5
years
More than 5 years
"Total contractual
cash flow
Trade and other payables (note 16) 159,882,177 - - 159,882,177
Working capital facility (note 18) 16,480,503 - - 16,480,503
Secured and unsecured loans (note 20) 21,727,400 29,859,050 - 51,586,450
2.75% convertible notes (note 26) 1,925,000 75,614,583 - 77,539,583
Total non-derivatives 200,015,080 105,473,633 - 305,488,713
Derivatives
Derivative financial instruments (note 9) 11,457 - - 11,457
Total derivatives 11,457 - - 11,457
The ageing of trade and other payables are as follows:
Trade and other payables
200,026,537 105,473,633 - 305,500,170
Total
$
Payable ageing between
60 days
$
December 31, 2011 159,882,177 157,758,605 979,728 1,143,844
December 31, 2010 75,132,880 70,788,064 1,766,354 2,578,462
(c) Credit risk
Credit risk is the risk that a contracting entity will not complete its obligation under a financial instrument that will result in a
financial loss to the Company. The carrying amount of financial assets represents the maximum credit exposure.
The Company’s credit risk is limited to the carrying value of its financial assets. A significant amount of the Company’s export
sales are made to two customers which represented $260,468,514 (Dec 2010 - $211,864,290) or 24% (Dec 2010 – 26%)
of total sales in the year ended December 31, 2011. The Company’s domestic sales for the year ended December 31, 2011
were not dependent on a single customer or geographic region within PNG. The export sales to two customers is not
considered a key risk as there is a ready market for InterOil export products and the prices are quoted on active markets.
The receivables from these customers are current as at December 31, 2011. The Company actively manages credit risk by
routinely monitoring the credit ratings of the Company’s export customers and by monitoring the ageing of trade receivables
of the Company’s domestic customers. The credit terms provided to customers are revised if any changes are noted to
customer ratings or payment cycles.
85

Credit risk on cash, cash equivalents and short term treasury bills held directly by the Company are minimized as all cash
amounts, certificates of deposit and treasury bills are held with banks which have acceptable credit ratings.
The maximum exposure to credit risk at the reporting date was as follows:
Current
December 31,
2011
$
December 31,
2010
$
Cash and cash equivalents 68,846,441 233,576,821
Cash restricted 32,982,001 40,664,995
Short term treasury bills 11,832,110 -
Trade and other receivables 135,273,600 48,047,496
Commodity derivative contracts 595,440 -
Non-current
Cash restricted 6,268,762 6,613,074
The ageing of trade receivables at the reporting date was as follows (the ageing days relates to balances past due):
Net trade receivables
Total
$
Current
$
Receivable ageing
60 days
$
December 31, 2011 112,239,803 51,026,962 40,875,467 13,076,371 7,261,003
December 31, 2010 45,428,435 20,344,957 19,239,373 3,198,155 2,645,950
The impairment of trade receivables at the reporting date was as follows:
Total
$
Current
$
Overdue
(not impared)
$
Overdue
(impared)
$
December 31, 2011 113,761,948 51,026,961 61,212,842 1,522,145
December 31, 2010 47,934,378 20,344,957 25,083,478 2,505,943
Impairment is assessed by the Company on an individual customer basis, based on customer ratings and payment cycles of
the customers. An impairment provision is taken for all receivables where objective evidence of impairment exists. The
movement in impairment is also influenced by the translation rates used to convert these amounts from local currency to
USD.
Other receivables as at December 31, 2011 of $23,033,797 (Dec 2010 - $2,619,061) were not impaired.
The movement in impaired trade receivables for the year ended December 31, 2011 was as follows:
Trade receivables - Impairment provisions
December 31,
2011
$
Year ended
December 31,
2010
$
Opening balance 2,505,943 3,603,342
Foreign exchange impact on opening balance 582,623 82,779
Amounts written off during the year (1,078,455) (666,034)
Movement in provisions, net of reversals made (487,966) (514,144)
Closing balance 1,522,145 2,505,943
(d) Geographic risk
The operations of InterOil are concentrated in PNG.
(e) Financing facilities
As at December 31, 2011, the Company had drawn down against the following financing facilities:
86

•
•
•
•
•
BNP working capital facility (refer note 18)
Westpac working capital facility (refer note 18)
OPIC secured loan facility (refer note 20)
Mitsui unsecured loan facility (refer note 20)
2.75% convertible notes (refer note 26)
Repayment obligations in respect of the amount of the facilities utilized are as follows:
Due:
December 31,
2011
$
December 31,
2010
$
No later than one year 35,873,526 65,711,083
Later than one year but not later than two years 9,000,000 9,000,000
Later than two years but not later than three years 9,000,000 9,000,000
Later than three years but not later than four years 78,500,000 9,000,000
Later than four years but not later than five years - 78,500,000
Later than five years - -
(f) Effective interest rates and maturity profile
December 31, 2011
Financial assets
Floating
interest rate
$
1 year or
less
$
1-2
$
Fixed interest maturing between
2-3
$
132,373,526 171,211,083
Noninterest
bearing
$
Cash and cash equivalents 30,955,254 37,891,187 - - - - - - 68,846,441 0.23%
Cash restricted 38,885,482 365,281 - - - - - - 39,250,763 2.86%
Short term treasury bills - 11,832,110 - - - - - - 11,832,110 4.32%
Receivables - - - - - - - 135,273,600 135,273,600 -
Investments - - - - - - - 3,650,786 3,650,786 -
Other financial assets - - - - - - - 6,073,036 6,073,036 -
Financial liabilities
3-4
$
4-5
$
More
than
5
years
$
69,840,736 50,088,578 - - - - - 144,997,422 264,926,736
Payables - - - - - - - 159,882,177 159,882,177 -
Interest bearing liabilities 26,873,526 9,000,000 9,000,000 9,000,000 8,500,000 - - - 62,373,526 6.93%
Convertible notes liability - - - - 70,000,000 - - - 70,000,000 7.91%
Other financial liabilities - - - - - - - 11,457 11,457 -
26,873,526 9,000,000 9,000,000 9,000,000 78,500,000 - - 159,893,634 292,267,160
Total
$
Effective
interest
rate
%
December 31, 2010
Financial assets
Floating
interest rate
$
1 year or
less
$
1-2
$
Fixed interest maturing between
2-3
$
Noninterest
bearing
$
Cash and cash equivalents 232,371,517 1,205,304 - - - - - - 233,576,821 0.21%
Cash restricted 46,968,143 309,926 - - - - - - 47,278,069 2.89%
Receivables - - - - - - - 48,047,496 48,047,496 -
Other financial assets - - - - - - - 3,593,574 3,593,574 -
Financial liabilities
3-4
$
4-5
$
More
than
5
years
$
279,339,660 1,515,230 - - - - - 51,641,070 332,495,960
Payables - - - - - - - 76,087,954 76,087,954 -
Interest bearing liabilities 56,711,083 9,000,000 9,000,000 9,000,000 9,000,000 8,500,000 - - 101,211,083 6.80%
Convertible notes liability - - - - - 70,000,000 - - 70,000,000 7.91%
Other financial liabilities - - - - - - - 178,578 178,578 -
56,711,083 9,000,000 9,000,000 9,000,000 9,000,000 78,500,000 - 76,266,532 247,477,615
Total
$
Effective
interest
rate
%
87

(g) Fair values
December 31, 2011 December 31, 2010
Carrying
Amount
$
Fair Value
$
Carrying
Amount
$
Fair Value
$
Fair value hierarchy
level
(as required)*
Method of measurement
Financial instruments
Financial assets
Loans and receivables
Cash and cash equivalents (note 6) 68,846,441 68,846,441 233,576,821 233,576,821 Amortized Cost
Cash restricted (note 9) 39,250,763 39,250,763 47,278,069 47,278,069 Amortized Cost
Short term treasury bills (note 8) 11,832,110 11,832,110 - - Amortized Cost
Receivables (note 10) 135,273,600 135,273,600 48,047,496 48,047,496 Amortized Cost
Available-for-sale
Investments (note 14) 3,650,786 3,650,786 - - Level 1 Fair Value - See (i) below
Held for trading
Derivative contracts (note 9) 583,983 583,983 (178,578) (178,578) Level 2 Fair Value - See (ii) below
Financial liabilities
Current liabilities:
Accounts payable and accrued liabilities (note 16) 159,882,177 159,882,177 76,087,954 76,087,954 Amortized Cost
Working capital facility (note 18) 16,480,503 16,480,503 51,254,326 51,254,326 Amortized Cost
"Current portion of secured and unsecured loans 34,813,222 38,879,426 43,589,278 47,696,040
(note 20)" 19,393,023 19,638,921 14,456,757 14,583,922
Non-current liabilities
Secured loan (note 20) 26,037,166 28,911,667 34,813,222 38,879,426
Amortized cost See (2)
below
Amortized cost See (iii)
below
Amortized cost See (iii)
below
2.75% Convertible notes liability (note 26) 55,637,630 55,637,630 52,425,489 52,425,489 Amortized Cost
* Where fair value of financial assets or liabilities is approximated by its carrying value, designation under the fair value hierarchy is not required.
The net fair value of cash and cash equivalents and non-interest bearing financial assets and financial liabilities of the
Company approximates their carrying amounts.
The carrying values (less impairment provision if provided) of trade receivables and payables are assumed to approximate
their fair values due to their short-term nature. The carrying value of financial liabilities approximates their fair values which, for
disclosure purposes, are estimated by discounting the future contractual cash flows at the current market interest rate that is
available to the Company for similar financial instruments.
Commodity derivative contracts’ and available-for-sale investments are the only items from the above table that are measured
at fair value on a recurring basis. All the remaining financial assets and financial liabilities are measured at a fair value on a
non-recurring basis and are maintained at historical amortized cost.
The fair value of financial assets and financial liabilities must be estimated for recognition and measurement or for disclosure
purposes. The Company has classified the fair value measurements using a fair value hierarchy that reflects the significance of
the inputs used in making the measurements. The fair value hierarchy shall have the following levels:
Level 1
Level 2
Level 3
quoted prices (unadjusted) in active markets for identical assets or liabilities
inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either
directly (i.e., as prices) or indirectly (i.e., derived from prices); and
inputs for the asset or liability that are not based on observable market data (unobservable inputs).
(i) Investments classified as being available-for-sale are fair valued by using quoted prices on Oslo stock exchange Axess.
(ii) Derivative contracts classified as being at fair value through profit and loss are fair valued by comparing the contracted rate
to the current market rate for a contract with the same remaining period to maturity. The fair value of the Company’s
derivative contracts are based on price indications provided to us by an external brokerage who enter into derivative
transactions with counter parties on the Company’s behalf.
88

(iii) The fair value of the secured loan is based on discounted cash flow analysis using a current market interest rate applicable
for the loan arrangement, being the current interest rate on a U.S. treasury note with the same approximate maturity profile
plus the OPIC spread (3%).
(h) Capital management
The finance department of the Company is responsible for capital management. This involves the use of operating and
development economic forecasting models which facilitates analysis of the Company’s financial position including cash flow
forecasts to determine the future capital management strategy. Capital management is undertaken to ensure a secure,
cost-effective and flexible supply of funds is available to meet the Company’s expenditure requirements and safeguard its
abilities to continue as a going concern.
The Company is actively managing the gearing levels and raising equity/debt as required for optimizing shareholder returns.
The Company is managing its gearing levels by maintaining the debt-to-capital ratio (debt/(shareholders’ equity + debt)) at
50% or less. The gearing levels were 12% in December 2011 (13% in December 2010). The optimum gearing levels for the
Company are overseen by the Board of Directors based on recommendations by Management. Recommendations are based
on operating cash flows, future cash needs for development, capital market conditions, economic conditions, and will be
reassessed as situations change.
On February 2, 2011, the Company and Liquid Niugini Gas Limited, the Company’s joint venture liquefied natural gas project
company with Pacific LNG Operations Ltd, signed a Project Funding and Construction Agreement (“PFCA”) and a
Shareholder Agreement with Energy World Corporation Ltd (“EWC”) governing the parameters in respect of the development,
construction, financing and operation of a planned three million tonne per annum land-based modular LNG plant in PNG. In
return for its commitment to fully fund the development and construction of the LNG plant, the agreements provide that EWC
will be entitled to a fee of 14.5% of the proceeds from the sale of LNG from the plant, less agreed deductions and financing
costs, and that EWC will also own a 14.5% interest in the operating company of the LNG plant. The PFCA and Shareholder
Agreement with EWC are conditional on reaching final investment decision to proceed with the LNG plant no later than March
31, 2012.
On April 11, 2011, the Company and Pac LNG executed a conditional framework agreement with FLEX LNG and Samsung
Heavy Industries related to the construction and operation of a two mtpa floating LNG processing vessel. The project is
intended to integrate with and augment proposed infrastructure to LNG from the onshore Elk and Antelope fields in the Gulf
Province of Papua New Guinea pursuant to arrangements with EWC and Mitsui. FLEX LNG will be responsible for the design,
engineering, construction and commissioning of the FLNG vessel. Construction of the FLNG vessel will be fully financed by
FLEX LNG and Samsung Heavy Industries. The framework agreements provided that the parties were to undertake project
specific FEED work and negotiate final binding agreements in time for a FID decision in mid-December 2011. Project specific
FEED work was carried out. However, as FID was reached by mid-December 2011, these framework agreements with FLEX
LNG and Samsung lapsed and were not extended. The Company is continuing to negotiate with FLEX LNG.
In September 2011, the Company retained financial advisors to help solicit and evaluate proposals from potential strategic
partners to, amongst other things, obtain an interest in, operate and help finance the development of the Gulf LNG Project.
The Company believes that it has sufficient funds for the Midstream Refinery and Downstream operations; however, existing
cash balances and ongoing cash generated from these operations will not be sufficient to facilitate further necessary
development of the Elk and Antelope fields, condensate stripping and liquefaction facilities. Therefore the Company must
extend or secure sufficient funding through renewed or additional borrowings, equity raising and or asset sales to enable
sufficient cash to be available to further its development plans. Management expects that the Company will be able to secure
the necessary financing through one, or a combination of, the aforementioned alternatives.
5. Segmented financial information
As stated in note 1, management has identified four major reporting segments - Upstream, Midstream, Downstream and
Corporate. Midstream consists of both Midstream Refining and Midstream Liquefaction. The Corporate segment includes
assets and liabilities that do not specifically relate to the other reporting segments. Results in this segment primarily include
management expenses. Consolidation adjustments relating to total assets relates to the elimination of intercompany loans
and investments in subsidiaries.
Notes to and forming part of the segment information
Segment information is prepared in conformity with the accounting policies of the entity. Segment revenues, expenses and
total assets are those that are directly attributable to a segment and the relevant portion that can be allocated to the segment
89

on a reasonable basis. Upstream, Midstream and Downstream include costs allocated from the Corporate activities based on
a fee for services provided. The eliminations relate to sales and operating revenues between segments recorded at transfer
prices based on current market prices and to unrealized intersegment profits in inventories. The majority of the Company’s
operations are located in Papua New Guinea, with the exception of the Corporate segment which also has operations in the
United States, Australia and Singapore.
Included in the Company’s revenues from external customers for the year ended December 31, 2011 is revenue from exports
to foreign countries of $273,827,525 (Dec 2010 - $227,932,775). The Midstream – Refining segment derives their revenue
from the sale of refined petroleum product to the domestic market in PNG and for export. The Downstream segment derives
their revenue from the sale of refined petroleum product to the domestic market in PNG on a wholesale and retail basis. The
Corporate segment derives their revenue from the shipping business which currently operates two vessels transporting
petroleum products for our Downstream segment and external customers, both within PNG and for export in the South
Pacific region.
Year ended December 31, 2011
Upstream
Midstream -
Refining
Midstream -
Liquefaction
Downstream
Corporate
Consolidation
adjustments
Revenues from external customers - 362,605,718 - 743,662,499 265,636 - 1,106,533,853
Intersegment revenues - 585,513,409 - 196,988 53,362,401 (639,072,798) -
Interest revenue 15,146 830,795 2 7,968 38,511,774 (38,009,561) 1,356,124
Other revenue 9,826,126 - - 1,255,434 (23,470) - 11,058,090
Total segment revenue 9,841,272 948,949,922 2 745,122,889 92,116,341 (677,082,359) 1,118,948,067
Cost of sales and operating expenses - 897,824,569 - 704,213,086 11,420,968 (592,526,701) 1,020,931,922
Administrative, professional and general expenses 5,122,087 18,939,165 14,121,189 15,780,247 47,371,224 (48,541,459) 52,792,453
Derivative (gain)/loss - (2,017,778) - - 11,457 - (2,006,321)
Foreign exchange loss/(gain) 2,152,675 (26,458,424) 13,127 229,042 (955,081) - (25,018,661)
Loss on Flex LNG investment - - - - 3,420,406 - 3,420,406
Exploration costs, excluding exploration
impairment
18,435,150 - - - - - 18,435,150
Depreciation and amortisation 3,254,672 11,253,854 25,632 4,026,422 1,706,037 (129,968) 20,136,649
Interest expense 30,012,655 9,664,482 1,307,901 4,346,081 6,011,916 (38,009,561) 13,333,474
Total segment expenses 58,977,239 909,205,868 15,467,849 728,594,878 68,986,927 (679,207,689) 1,102,025,072
Segment (loss)/profit before income taxes (49,135,967) 39,744,054 (15,467,847) 16,528,011 23,129,414 2,125,330 16,922,995
Income tax benefit/(expense) - 6,945,518 - (4,962,288) (1,247,563) - 735,667
Segment net (loss)/profit (49,135,967) 46,689,572 (15,467,847) 11,565,723 21,881,851 2,125,330 17,658,662
Segment assets 390,448,139 444,687,129 7,925,856 201,906,476 69,624,747 (62,202,814) 1,052,389,533
Unallocated:
Deferred tax (note 15) 35,965,273
Total assets per the balance sheet 1,088,354,806
Segment liabilities 79,730,935 139,105,842 8,759,273 85,110,349 74,025,870 (60,157,290) 326,574,979
Unallocated:
Deferred tax (note 15) 1,889,391
Total liabilities per the balance sheet 328,464,370
Capital expenditure (net of cash calls) 107,558,028 15,861,056 5,173,603 10,240,083 3,118,687 - 141,951,457
Total
90

Year ended December 31, 2010
Upstream
Midstream -
Refining
Midstream -
Liquefaction
Downstream
Corporate
Consolidation
adjustments
Revenues from external customers - 298,070,718 - 504,303,681 - - 802,374,399
Intersegment revenues - 379,343,999 - 483,134 32,563,686 (412,390,819) -
Interest revenue 14,757 58,229 643 23,490 24,334,629 (24,280,932) 150,816
Other revenue 3,290,721 107,714 - 1,048,251 23,362 - 4,470,048
Total segment revenue 3,305,478 677,580,660 643 505,858,556 56,921,677 (436,671,751) 806,995,263
Cost of sales and operating expenses - 605,602,656 - 470,771,827 - (374,817,833) 701,556,650
Administrative, professional and general expenses 13,746,219 11,939,500 7,022,644 15,975,882 40,291,485 (36,324,778) 52,650,952
Derivative loss/(gain) - 1,591,878 - - (526,690) - 1,065,188
Foreign exchange loss/(gain) 3,043,907 7,517,961 90,367 1,175,894 (1,051,306) - 10,776,823
Gain on sale of exploration assets (2,140,783) - - - - - (2,140,783)
Loss on extinguishment of IPI liability 30,568,710 - - - - - 30,568,710
Litigation settlement expense - - - - 12,000,000 - 12,000,000
Exploration costs, excluding exploration
impairment
16,981,929 - - - - - 16,981,929
Depreciation and amortisation 1,132,118 10,355,057 25,227 2,786,500 105,988 (129,968) 14,274,922
Interest expense 18,527,881 6,584,584 1,252,796 3,739,297 1,540,594 (24,280,932) 7,364,220
Total segment expenses 81,859,981 643,591,636 8,391,034 494,449,400 52,360,071 (435,553,511) 845,098,611
Segment (loss)/profit before income taxes (78,554,503) 33,989,024 (8,390,391) 11,409,156 4,561,606 (1,118,240) (38,103,348)
Income tax (expense)/benefit - (504,387) 35,905 (4,701,386) (1,239,855) - (6,409,723)
Segment net (loss)/profit (78,554,503) 33,484,637 (8,354,486) 6,707,770 3,321,751 (1,118,240) (44,513,071)
Segment assets 266,169,785 325,089,253 7,823,600 117,708,440 265,233,362 (34,759,579) 947,264,861
Unallocated:
Deferred tax (note 15) 28,477,690
Total assets per the balance sheet 975,742,551
Segment liabilities 81,193,873 109,332,954 11,561,364 35,055,512 66,139,037 (30,442,168) 272,840,572
Capital expenditure (net of cash calls) 82,811,176 6,972,505 1,876,736 7,623,024 3,661,267 - 102,944,708
6. Cash and cash equivalents
The components of cash and cash equivalents are as follows:
December 31, 2011
$
Total
December 31, 2010
$
Cash on deposit 45,970,047 233,576,821
Bank term deposits - Papua New Guinea kina deposits 22,876,394 -
68,846,441 233,576,821
91

In 2011, cash and cash equivalents earned an average interest rate of 0.23% per annum (2010 – 0.21%).
7. Supplemental cash flow information
Cash paid during the year
December 31, 2011
$
December 31, 2010
$
Interest 7,238,610 5,827,959
Income taxes 1,450,341 3,254,382
Interest received 1,008,407 143,315
Non-cash investing activities:
Fair value of Flex LNG option received 4,214,258 -
Increase in share capital from:
buyback of non-controlling interest 243,850 -
Non-cash financing activities:
Increase in share capital from:
the exercise of share options and vesting of restricted stock 5,598,009 8,454,758
buyback of IPI #3 investor rights - 50,687,368
litigation settlement settled in shares - 12,000,000
8. Short term treasury bills
During the quarter ended September 30, 2011, the Company purchased two treasury bills from the Bank of Papua New
Guinea totaling approximately $11,832,110 (PGK 25,363,312). Both of these treasury bills have a 182 day term and will
mature in January 2012. The first treasury bill for approximately $2,697,850 (PGK 5,783,112) has an interest rate of 4.4% and
the second treasury bill for approximately $9,134,260 (PGK 19,580,200) has an interest rate of 4.3%.
Based on the guidance under IAS 39 ‘Financial Instruments Recognition and Measurement’, these investments have been
classified as held-to-maturity financial assets and are therefore recorded at amortized cost using the effective interest method.
9. Financial instruments
(a) Cash and cash equivalents
With the exception of cash and cash equivalents, restricted cash and short term treasury bills, all financial assets are
non-interest bearing. In 2011, the Company earned nil interest (2010 – nil) on the cash on deposit which related to the
working capital facility. However, the cash deposit relating to the BNP working capital facility reduced the interest costs
relating to the facility usage in 2011 by 3.38% (2010 – 3.33%).
Cash restricted, which mainly relates to the working capital facility, is comprised of the following:
December 31, 2011
$
December 31, 2010
$
Cash deposit on working capital facility (0.0%) 32,982,001 40,664,995
Cash restricted - Current 32,982,001 40,664,995
Bank term deposits on Petroleum Prospecting Licenses (1.6%) 161,801 130,486
Cash deposit on office premises (5.3%) 203,480 179,440
Cash deposit on secured loan (0.1%) 5,903,481 6,303,148
Cash restricted - Non-current 6,268,762 6,613,074
39,250,763 47,278,069
Cash held as deposit on the BNP working capital facility supports the Company’s working capital facility with BNP
Paribas. The balance is based on 20% of the outstanding balance of the BNP working capital facility 1 (refer note 18) plus any
amounts that are fully cash secured. The cash deposit on this facility did not receive interest during the year as these deposit
amounts reduced the interest being charged by BNP on the facility utilization.
92

The cash held as deposit on secured loan is used to support the Company’s secured loan borrowings with the Overseas
Private Investment Corporation (“OPIC”) and relates to one half yearly installment of $4.5 million and the related interest that
will be payable with the next installment.
Bank term deposits on PPL’s are unavailable for use while PPL 236, 237 and 238 are being utilized by the Company.
(b) Commodity derivative contracts
InterOil uses derivative commodity instruments to manage its exposure to price volatility on a portion of its refined product and
crude inventories in accordance with risk management policy described in note 4.
At December 31, 2011, InterOil had a net receivable of $595,440 (Dec 2010 – payable of $178,578) relating to outstanding
derivative contracts for which hedge accounting was not applied or had been discontinued.
The Company had no outstanding hedge accounted derivative contracts as at December 31, 2011 and December 31, 2010.
As at December 31, 2011, the Company had the following open non-hedge accounted derivative contracts outstanding.
Derivative
Type
Notional Volumes
(bbls)
Expiry
Brent Swap Sell Brent 70,000 Q1 2012
Gasoil Crack
Swap
Gasoil Crack
Swap
Gasoil Crack
Swap
Sell Gasoil
Crack
Sell Gasoil
Crack
Sell Gasoil
Crack
195,000 Q1 2012
195,000 Q2 2012
195,000 Q3 2012
Derivative type
Cash flow hedge - Manages the export price risk of
naphtha
Cash flow hedge - Manages the sales price risk of gasoil
(diesel)
Cash flow hedge - Manages the sales price risk of gasoil
(diesel)
Cash flow hedge - Manages the sales price risk of gasoil
(diesel)
Fair Value
December 31, 2011
$
(63,681)
154,516
185,495
221,160
497,490
Add: Priced out non-hedge accounted contracts as at December 31, 2011 97,950
595,440
As at December 31, 2010, the Company had the following open non-hedge accounted derivative contracts outstanding.
Derivative
Naphtha
Swap
Type
Notional Volumes
(bbls)
Expiry
Sell Naphtha 54,000 Q1 2011
Brent Swap Buy Brent 54,000 Q1 2011
Naphtha/
Brent Swap
Sell Naphtha/ Buy
Brent
54,000 Q1 2011
Derivative type
Cash flow hedge - Manages the export price risk of
naphtha
Cash flow hedge - Manages the export price risk of
naphtha
Cash flow hedge - Manages the export price risk of
naphtha
Add: Priced out non-hedge accounted contracts as at December 31, 2010 -
Fair Value
December 31, 2010
$
(275,958)
179,118
(81,738)
(178,578)
(178,578)
A gain of $2,017,778 was recognized on the non-hedge accounted derivative contracts for the year ended December 31,
2011 (Dec 2010 – loss of $1,591,878). This gain is included in derivative gain/(loss) in the consolidated income statement.
(c) Currency derivative contracts
During the year ended December 31, 2010, the Company started to enter into AUD to USD foreign currency forward
contracts to minimize the foreign exchange risk in relation to the expenses to be incurred in AUD. As at December 31, 2011,
the Company had a net payable of $11,457 (Dec 2010 - $nil) in relation to outstanding non-hedge accounted currency
derivative contracts.
A loss of $11,457 was recognized on the non-hedge accounted currency derivative contracts for the year ended December
31, 2011 (Dec 2010 – gain of $526,690). This loss is included in derivative gain/(loss) in the consolidated income statement.
93

10. Trade and other receivables
December 31, 2011
$
December 31, 2010
$
Trade receivables 112,239,803 45,428,435
Other receivables 23,033,797 2,619,061
Total 135,273,600 48,047,496
InterOil has a discounting facility with BNP Paribas on specific monetary receivables under which the Company is able to sell,
on a revolving basis, trade receivables up to $60,000,000 (refer to note 18). As at December 31, 2011, $10,030,131 (Dec
2010 - $nil) in outstanding trade receivables had been sold with recourse under the facility. As the sale is with recourse, the
discounted trade receivables, if any, are retained on the balance sheet and included in the accounts receivable and the sale
proceeds are recognized in the working capital facility. The Company has retained the responsibility for administering and
collecting accounts receivable sold. The discounted trade receivables are usually settled within a month of their discounting
and there have not been any collection issues relating to these discounted trade receivables.
At December 31, 2011, $74,265,832 (Dec 2010 - $26,884,664) of the trade receivables secures the BNP Paribas working
capital facility disclosed in note 18. This balance includes $53,815,857 (Dec 2010 - $21,797,631) of intercompany
receivables which were eliminated on consolidation.
11. Inventories
December 31, 2011
$
December 31, 2010
$
Midstream - Refining (crude oil feedstock) 40,311,108 23,004,883
Midstream - Refining (refined petroleum product) 70,267,854 67,006,941
Midstream - Refining (parts inventory) 2,721,147 673,283
Downstream (refined petroleum product) 57,771,690 36,452,253
171,071,799 127,137,360
As at December 31, 2011, inventory had been written down to its net realizable value. The write down of $259,406 at
December 31, 2011 relating to refined petroleum products is included in ‘Changes in inventories of finished goods and work
in progress’ within the consolidated income statement. As at December 31, 2010 no net realizable value write down was
necessary. At December 31, 2011, $113,300,109 (Dec 2010 - $90,685,107) of the Midstream Refining inventory balance
secures the BNP Paribas working capital facility disclosed in note 18.
94

12. Plant and equipment
At January 1, 2010:
Refinery
Land and
Buildings
Plant and
Equipment
Motor Vehicles
Deferred
Project Costs
and Work in
Progress
Cost 242,397,179 15,932,657 31,842,143 3,224,542 8,615,638 302,012,159
Accumulated depreciation (51,718,661) (8,859,006) (20,323,035) (2,316,808) - (83,217,510)
Net book value 190,678,518 7,073,651 11,519,108 907,734 8,615,638 218,794,649
Year ended December 31, 2010:
Opening net book value 190,678,518 7,073,651 11,519,108 907,734 8,615,638 218,794,649
Additions 1,371,819 69,375 706,503 766,235 16,137,409 19,051,341
Disposals - (5,678) (13,248) (28,388) - (47,314)
Transfers from work in progress 2,832,316 1,780,516 3,812,781 541,703 (8,967,316) -
Reclassification to other asset categories (3,082,278) 2,982,970 141,614 (42,306) - -
Depreciation for the period (9,525,893) (947,248) (2,223,661) (446,279) - (13,143,081)
Exchange differences - 157,005 313,345 (42,460) 121,942 549,832
Closing net book value 182,274,482 11,110,591 14,256,442 1,656,239 15,907,673 225,205,427
At December 31, 2010:
Cost 243,519,036 20,042,453 36,563,947 4,046,294 15,907,673 320,079,403
Accumulated depreciation (61,244,554) (8,931,862) (22,307,505) (2,390,055) - (94,873,976)
Net book value 182,274,482 11,110,591 14,256,442 1,656,239 15,907,673 225,205,427
Year ended December 31, 2011:
Opening net book value 182,274,482 11,110,591 14,256,442 1,656,239 15,907,673 225,205,427
Additions 4,624,888 4,297,395 4,614,370 1,547,508 14,467,925 29,552,086
Disposals - (33,950) (395,961) (7,234) - (437,145)
Transfers from work in progress 570,847 671,101 7,396,780 34,892 (8,673,620) -
Reclassification to other asset categories - 6,493 (1,024,903) 1,018,410 - -
Depreciation for the period (10,703,288) (981,574) (4,132,887) (1,064,228) - (16,881,977)
Exchange differences - 1,713,531 2,918,193 650,839 3,322,994 8,605,557
Closing net book value 176,766,929 16,783,587 23,632,034 3,836,426 25,024,972 246,043,948
At December 31, 2011:
Cost 248,714,771 28,419,395 53,076,624 8,325,671 25,024,972 363,561,433
Accumulated depreciation (71,947,842) (11,635,808) (29,444,590) (4,489,245) - (117,517,485)
Net book value 176,766,929 16,783,587 23,632,034 3,836,426 25,024,972 246,043,948
13. Oil and gas properties
Costs of oil and gas properties which are not subject to depletion are as follows:
December 31, 2011
$
Totals
December 31, 2010
$
Drilling and construction equipment 79,367,759 28,653,929
Drilling consumables and spares 14,129,959 10,924,708
Petroleum Prospecting License drilling programs (Unproved) 269,355,048 215,716,101
Gross Capitalized Costs 362,852,766 255,294,738
Accumulated depletion and amortization
Unproved oil and gas properties - -
Proved oil and gas properties - -
Net Capitalized Costs 362,852,766 255,294,738
The majority of the costs capitalized under ‘Petroleum Prospective License drilling programs (Unproved)’ above relates to the
exploration and development expenditure on the Elk and Antelope fields. The development and monetization efforts of these
fields are ongoing, and include the condensate stripping and associated facilities, the gas gathering and associated common
facilities, and developing a liquefied natural gas plant and associated facilities in PNG.
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The majority of current year increase in the PPL drilling programs relates to the preparation and drilling activities on the
Triceratops field.
The following table discloses a breakdown of the exploration costs incurred for the periods ended:
Property Acquisition Costs
December 31, 2011
$
December 31, 2010
$
Unproved - -
Proved - -
Total acquisition costs - -
Exploration Costs - 207,054
Development Costs 116,493,004 96,325,176
Add: Amounts capitalized in relation to the appraisal program cash calls on IPI interest buyback
transactions
- 3,922,683
Add: Premium paid on IPI buyback transactions - 1,550,020
Less: Conveyance accounting offset against properties - (192,622)
Less: Costs allocated against cash calls (8,934,976) (19,001,135)
Total Costs capitalized 107,558,028 82,811,176
Charged to expense
Geophysical and other costs 18,435,150 16,981,929
Total charged to expense 18,435,150 16,981,929
Oil and Gas Property Additions (capitalized and expensed) 125,993,178 99,793,105
14. Investments
On April 11, 2011, the Company and Pacific LNG Operations Ltd. executed a framework agreement with Flex LNG Ltd
related to the construction and operation of a two million tonnes per annum floating liquefied natural gas processing
vessel. Under the framework agreement, an equity purchase option was issued to the Company and Pacific LNG Operations
Ltd. to acquire up to 11,315,080 common shares in Flex LNG Ltd at an average strike price of 4.5909 Norwegian Kroner. On
May 16, 2011, the Company and Pacific LNG Operations Ltd. exercised this option with the Company acquiring 8,938,913
common shares of Flex LNG Ltd at a cost of $7,461,407 and Pacific LNG Operations Ltd acquiring the remaining 2,376,167
common shares. Based on guidance under IAS 39, the Company recognized the financial asset, the Flex LNG Ltd options,
on the date of grant of those options to the Company, April 11, 2011. Considering the various classification options available
and managements intention to hold the options/shares after exercising for the medium term, the options were classified as a
derivative financial instrument at initial recognition and then reclassified as ‘available-for-sale’ when the options were exercised
and the common shares acquired.
Management used the Black Scholes pricing model to fair value the options at grant date and subsequently the
derivative through to the date of exercise. The option value on exercise date was $4,214,258 and the exercise price paid
was $7,461,407. The cumulative fair value of the options received of $4,214,258 was recognized in the consolidated income
statement under ‘Gain on Flex LNG options received’. Transaction costs of $17,350 were also incurred in relation to the
transaction and were allocated to the investment. Management has determined that recognition of this gain is appropriate as
there is no ongoing obligation or commitment that the Company needs to fulfill as a result of receiving these options. The total
amount recognized as the long term investment in relation to the Flex LNG shares in the balance sheet after the exercise of
the options was $11,693,015.
Based on guidance under IAS 39, changes in the fair value of the Flex LNG Ltd shares after initial recognition are to be
recognized in other comprehensive income within shareholders equity, except for impairment losses which can be evidenced
by a significant or prolonged decline in the fair value of an investment. The fair value at December 31, 2011 was $3,650,786
and was calculated using quoted prices on Oslo stock exchange Axess. As at December 31, 2011, the decrease in the value
of this investment from initial recognition was $8,042,229, with $407,565 of this amount being attributable to a reduction in
the Norwegian Kroner exchange rates and $7,634,664 being attributable to a reduction in the share price of the investment.
Based on the guidance on significant decline in fair value, Management has determined that the decrease in fair value
attributable to the reduction in share price ($7,634,664) needs to be recognized in the consolidated income statement and the
decrease in fair value attributable to the reduction in exchange rates ($407,565) needs to be recognized in OCI for the year
ended December 31, 2011. If the fair value of the investment increases in subsequent periods, this increase will be
recognized through OCI, rather than through profit and loss statements in accordance with the guidance under the standards
on reversal of prior impairment write offs relating to equity investments.
96

15. Income taxes
(a) Income tax expense
The combined income tax expense in the consolidated income statements reflects an effective tax rate which differs from the
expected statutory rate (combined federal and provincial rates). Differences for the years ended were accounted for as
follows:
December 31, 2011
$
December 31, 2010
$
Profit/(loss) before income taxes and non controlling interest 16,922,995 (38,103,348)
Statutory income tax rate 31.50% 33.00%
Computed tax expense/(benefit) 5,330,743 (12,574,105)
Effect on income tax of:
Income/(losses) in foreign jurisdictions not assessable/(deductible) 3,236,314 2,073,636
Non-deductible stock compensation expense 897,703 317,671
Non-deductible pre-LNG Project Agreement costs 983,644 1,146,936
Non-deductible premium paid on buyback of IPI interest - 10,087,674
Non-taxable gain on sale of exploration assets - (706,458)
Effect of currency translation on tax base (3,236,709) 202,029
Tax rate differential in foreign jurisdictions (556,744) (726,664)
Over provision for income tax in prior years 588,333 1,501,234
Midstream - Refining tax exempt income as per Refinery Project Agreement - (8,423,607)
Tax losses for which no future tax benefit has been brought to account 8,718,157 16,299,899
Initial recognition of future tax assets/liabilities based on recoverability assessment (15,498,147) (973,368)
Other - net (1,198,961) (1,815,154)
(b) Deferred income tax
December 31, 2011
$
(735,667) 6,409,723
December 31, 2010
$
Deferred tax assets 35,965,273 28,477,690
Deferred tax liabilities (1,889,391) -
Deferred tax assets (net) 34,075,882 28,477,690
The gross movement on the deferred income tax account is as follows:
December 31, 2011
$
December 31, 2010
$
At January 1 28,477,690 30,319,163
Charge to the income statement 6,248,509 (2,511,656)
Exchange differences (650,317) 670,183
At December 31 34,075,882 28,477,690
The movement in deferred income tax assets and liabilities during the year, without taking into consideration the offsetting of
balances within the same tax jurisdiction, is as follows:
Deferred tax assets and liabilities Tax losses Other Tax depreciation
Unrealized foreign
exchange gains
At January 1, 2010 23,800,726 2,620,198 5,535,521 (1,637,282) 30,319,163
Charge to the income statement (21,663) (1,244,491) (1,168,649) (76,853) (2,511,656)
Exchange differences 547,561 181,093 (216,347) 157,876 670,183
At December 31, 2010 24,326,624 1,556,800 4,150,525 (1,556,259) 28,477,690
Charge to the income statement (3,691,894) 389,142 14,252,367 (4,701,106) 6,248,509
Exchange differences 4,136,543 262,241 (2,723,692) (2,325,408) (650,316)
At December 31, 2011 24,771,273 2,208,183 15,679,200 (8,582,774) 34,075,882
Total
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The deferred tax assets recorded in the consolidated balance sheet mainly relate to Midstream – Refining assets in PNG while
the deferred tax liabilities relate to Downstream assets in PNG. The amounts are non-current as at December 31, 2011.
In addition to the above, the Company has temporary differences and losses carried forward in relation to exploration
expenditure incurred in PNG of $221,468,770 at December 31, 2011. No deferred tax assets have been recognized for the
exploration expenditure pending final investment decision on projects for monetization of resources from the licenses held.
The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods
in which those temporary differences become deductible. Management considers the actual levels of past taxable income,
scheduled reversal of deferred tax liabilities, projected future taxable income, projected tax rates and tax planning strategies
in making this assessment. Management has determined that 100% of the deferred tax assets required in relation to the net
operating loss carry-forwards of the Midstream – Refining segment should be recognized during the year ended 2010. This
was based on the refinery generating consistent profits, and the view that any carry forward tax losses will be recouped in the
coming years.
The Refinery Project Agreement gave “pioneer” status to InterOil Limited (”IOL”). This status gave IOL a tax holiday beginning
upon the date of the commencement of commercial production, January 1, 2005 and ended December 31, 2010. In relation
to the refinery, tax losses incurred prior to January 1, 2005 were frozen during the tax holiday and became available for use
after the tax holiday ceased on December 31, 2010. Tax losses incurred during the tax holiday also became available for use
after December 31, 2010. Tax losses carried forward to offset against future earnings total PGK 176,872,859 ($82,512,063)
at December 31, 2011. All losses incurred by InterOil Limited have a twenty year carry forward period.
16. Trades and other payables
December 31, 2011
$
December 31, 2010
$
Trade payables - crude import 69,042,031 -
Trade payables - product import 10,470,860 5,241,216
Other accounts payable and accrued liabilities 53,541,263 47,999,907
Petromin cash calls received 15,435,000 15,435,000
Mitsui cash calls received 11,393,023 6,456,757
Total trade and other payables 159,882,177 75,132,880
(a) Petromin participation in Elk and Antelope fields
On October 30, 2008, Petromin PNG Holdings Limited (”Petromin”), a government entity mandated to invest in resource
projects on behalf of the State, entered into an agreement to take a 20.5% direct interest in the Elk and Antelope fields if and
once nominated by the State to take its legislative interest. Petromin contributed an initial deposit and agreed to conditionally
fund 20.5% of the costs of developing these fields. The State’s (and Petromin’s) right to take an interest arises upon issuance
of the Prospecting Development License (”PDL”), which has not yet occurred. The obligation to fund its portion of the costs of
developing the field, including sunk costs, also applies upon issuance of the PDL. As at December 31, 2011, $15,435,000 in
advance payments received from Petromin has been held under ‘Petromin cash calls received’ above. At the end of the 2011
year, the parties agreed that the Agreement’s intended operation had ended, and that it should terminate. Petromin remains
the State’s nominee to acquire the State’s interest under relevant Papua New Guinean legislation, once a PDL is granted.
InterOil has proposed that cash contributions made by Petromin to date to fund the development will be held and credited
against the State’s obligation to contribute its portion of sunk costs upon grant of the PDL.
(b) Mitsui & Co. participation in Condensate Stripping Plant
On April 15, 2010, the Company entered into a preliminary works joint venture and preliminary works financing agreement
with Mitsui relating to the CS Project. The proposed joint venture is to be entered into for equal shares between Mitsui and
InterOil. Mitsui will be responsible for arranging or providing financing for the capital costs of the plant. On August 4, 2010, the
JVOA for the CS Project was finalized. Refer to note 20 for further details in relation to this agreement.
The portion of funding that relates to Mitsui’s share of the project as at December 31, 2011, amounting to $11,393,023 is
held in current liabilities as the agreement requires repayment if FID is not reached. The portion of funding that relates to
InterOil’s share of the project, funded by Mitsui, is classified as an unsecured loan (refer to note 20).
17. Goodwill
(a) Acquisition of interest from Merrill Lynch
On February 27, 2009, InterOil LNG Holdings Inc. acquired half of Merrill Lynch’s interest in the LNG Joint Venture Company
98

for $11,250,000. As part of the acquisition, InterOil LNG Holdings Inc. was transferred 548,806 ‘B’ Class shares held by
Merrill Lynch. The amount recognized as goodwill of $5,761,940 represents the amount of purchase consideration paid to
Merrill Lynch over and above the fair value of the identifiable net assets acquired.
(b) Acquisition of interest from Pacific LNG
During September 2009, InterOil also acquired a further 2.5% of Pacific LNG’s economic interest in the joint venture LNG
Project from Pacific LNG as part of the Elk and Antelope interest acquisition. The fair value of 2.5% of Pacific LNG’s
economic interest in the joint venture LNG Project was valued at $864,377 based on the previous transaction with Merrill
Lynch that was completed in February 2009, being the most appropriate guide to the fair value of the interest acquired. This
fair value has been recognized as goodwill on acquisition of the LNG interest in the Balance Sheet.
(c) Impairment tests for goodwill
Management reviews the business performance based on operating segments and goodwill is monitored by the management
at the operating segment level. The goodwill recognized at December 31, 2011 is allocated to the Midstream – Liquefaction
segment.
The recoverable amount of the Midstream – Liquefaction segment has been determined based on fair value less costs to sell
calculations. These calculations use cash flow projections covering a twenty-year period and the key assumptions used in the
calculations include an oil price of $90/bbl and an annual inflation rate of 2%.
18. Working capital facilities
Amounts drawn down
December 31, 2011
$
December 31, 2010
$
BNP Paribas working capital facility - midstream 10,030,131 50,023,559
Westpac working capital facility - downstream 6,450,372 1,230,767
Total working capital facility 16,480,503 51,254,326
(a) BNP Paribas working capital facility
InterOil has a syndicated working capital credit facility led by BNP Paribas (Singapore branch) with a maximum availability of
$230,000,000 (increased temporarily to $260,000,000 in November 2011, and reverting back to $230,000,000 on
January 31, 2012). The total facility is split into Facility 1 and Facility 2 as per the agreement with BNP Paribas. Facility 1
is for $170,000,000 (increased temporarily to $200,000,000) and finances purchases of hydrocarbons via the issuance of
documentary letters of credit and or standby letters of credit, short term advances, advances on merchandise, freight loans,
and includes a sublimit of Euro 18,000,000 or USD equivalent for hedging transactions via BNP Paribas Commodity Indexed
Transaction Group or other acceptable counter parties.
Facility 2 is for $60,000,000 partly cash-secured short term advances and for discounting of any monetary receivables
acceptable to BNP Paribas in order to reduce Facility 1 balances. The facility is secured by sales contracts, purchase
contracts, certain cash accounts associated with the refinery, all crude and refined products of the refinery and trade
receivables.
The total facility is renewable annually and during the prior year renewal process, the facility was renewed until January
31, 2012 with an increase in Facility 1 limit by an additional $30,000,000 to $160,000,000, and a maximum availability of
$220,000,000 for the combined facility. In June 2011, there was an additional increase in Facility 1 limit by $10,000,000 to
$170,000,000, and a maximum availability of $230,000,000 for the combined facility. In November 2011, the limit of Facility
1 was further increased temporarily by $30,000,000 to $200,000,000, and a maximum availability of $260,000,000 for the
combined facility. The combined facility reverted back to a maximum availability of $230,000,000 at the end of January 2012.
As part of the current year renewal process, the facility was renewed in February 2012 with an increase in Facility 1 limit by an
additional $10,000,000 to $180,000,000, and a maximum availability of $240,000,000 for the combined facility until January
31, 2013.
The facility bears interest at LIBOR + 3.5% on the short term advances. During the year the weighted average interest rate
was 2.96% (2010 – 2.69%) after considering the reduction in interest due to the deposit amounts maintained which reduces
the interest being charged on the facility utilization (refer section ‘Cash and cash equivalents’ under note 9).
The following table outlines the facility and the amount available for use at year end:
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December 31, 2011
$
December 31, 2010
$
Working capital credit facility 260,000,000 190,000,000
Less amounts included in the working capital facility liability:
Short term advances/facilities drawn down - (50,023,559)
Discounted receivables (10,030,131) -
Less: other amounts outstanding under the facility:
(10,030,131) (50,023,559)
Letters of credit outstanding (164,910,000) (93,710,000)
Working capital credit facility available for use 85,059,869 46,266,441
At December 31, 2011, the company had six letters of credit outstanding totaling $164,910,000. The first letter of credit for
$42,720,000 was for a crude cargo and was drawn down on January 3, 2012. The second letter of credit for $73,470,000
was for a crude cargo and was drawn down on January 3, 2012. The third letter of credit for $5,800,000 was for a diesel and
jet cargo and was drawn down on January 9, 2012. The fourth letter of credit for $5,020,000 was for a gasoline cargo and
was drawn down on January 11, 2012. The fifth letter of credit for $7,800,000 was for a diesel cargo and was drawn down
on January 17, 2012. The sixth letter of credit for $30,100,000 was for a crude cargo and was drawn down on January 18,
2012.
The cash deposit on working capital facility, as separately disclosed in note 9, included restricted cash of $32,982,001 (2010
- $40,664,995) which is being maintained as a security margin for the facility. In addition, inventory of $113,300,109 (2010
- $90,685,107) and trade receivables of $74,265,832 (2010 – $26,884,664) also secured the facility. The trade receivable
balance securing the facility includes $53,815,857 (2010 - $21,797,631) of inter-company receivables which were eliminated
on consolidation.
(b) Westpac and Bank South Pacific working capital facility
The Company has an approximately $60,645,000 (PGK 130,000,000) revolving working capital facility for its Downstream
operations in PNG from BSP and Westpac. Westpac facility limit is approximately $37,320,000 (PGK 80,000,000) and the
initial BSP facility limit is approximately $23,325,000 (PGK 50,000,000). The Westpac facility is for an initial term of three years
and was renewed in November 2011 through to November 2014. The Westpac facility was further increased, subsequent to
year end in February 2012, by $4,665,000 (PGK 10,000,000) bringing the Westpac facility to $41,985,000 (PGK 90,000,000)
and the combined facility to $65,310,000 (PGK 140,000,000). In addition, a secured loan of $15,000,000 was provided as
part of this increased facility which is repayable in equal installments over 3.5 years with an interest rate of LIBOR + 4.4% per
annum. The BSP facility is renewable annually and was renewed in August 2011 through to August 2012. As at December
31, 2011, $6,450,372 (PGK 13,827,164) of this combined facility has been utilized, and $54,194,628 (PGK 116,172,836) of
this facility remains available for use. During the year the weighted average interest rate was 9.6%. These facilities are secured
by a fixed and floating charge over the assets of Downstream operations.
19. Related parties
(a) Petroleum Independent and Exploration Corporation (“P.I.E”)
P.I.E is controlled by Phil Mulacek, an officer and director of InterOil and acted as a sponsor of the Company’s oil refinery
project until late June 2011. Articles of association of SPI InterOil LDC (“SPI”) provide for the business and affairs of the entity
to be managed by a general manager appointed by the shareholders of SPI. SPI does not have a Board of Directors, instead
P.I.E has been appointed as the general manager of SPI. Under the laws of the Commonwealth of The Bahamas, the general
manager exercises all powers which would typically be exercised by a Board of Directors, being those which are not required
by laws or by SPI’s constituting documents to be exercised by the members (shareholders) of SPI. InterOil is the majority
shareholder of SPI and therefore has the power to appoint the general manager.
During the year ended December 31, 2011, $nil (Dec 2010 - $150,000) was expensed for the sponsor’s management fees in
relation to legal, accounting and reporting costs. Of these costs, $nil (Dec 2010 - $112,500) were included in accrued
liabilities at December 31, 2011.
In November of 2011, the Company elected to exchange the 5,000 shares held in SP InterOil LDC by PIE for 5,000 shares in
InterOil Corporation. The sponsor agreements were terminated with PIE on exchange of the share holding interest in SPI LDC.
Subsequent to year end, SPI LDC has been renamed South Pacific Refining Limited.
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(b) Breckland Limited
This entity is controlled by Roger Grundy, a director of InterOil, and provides technical and advisory services to the Company
on normal commercial terms. Amounts paid or payable to Breckland for technical services during the year amounted to $nil
(Dec 2010 - $21,923).
(c) Key management compensation
Key management includes directors (executive and non-executive) and executive officers. The compensation paid or payable
to key management for services is shown below:
December 31, 2011
$
December 31, 2010
$
Salaries and other short-term employee benefits 3,985,427 2,653,219
Post-employment benefits 94,732 83,277
Share-based payments 9,341,730 6,328,176
Total 13,421,889 9,064,672
(d) Joint ventures
The Company’s interests in PNG LNG Inc. is governed by a Shareholders’ Agreement signed on July 30, 2007 between the
Joint Ventures’. Guidance under IAS 31 – ‘Interest in Joint Ventures’ is followed and the entity has been proportionately
consolidated in InterOil’s consolidated financial statements. The consolidated results of InterOil’s proportionate shareholding in
the LNG Project has been disclosed separately within the segment notes under Midstream - Liquefaction, refer to note 5.
20. Secured and unsecured loans
December 31, 2011
$
December 31, 2010
$
Secured loan (OPIC) - current portion 9,000,000 9,000,000
Unsecured loan (Mitsui) 10,393,023 5,456,757
Total current portion of loans 19,393,023 14,456,757
Secured loan (OPIC) - non current portion 26,500,000 35,500,000
Secured loan (OPIC) - deferred financing costs (462,834) (686,778)
Total non current secured loan 26,037,166 34,813,222
Total secured and unsecured loans 45,430,189 49,269,979
(a) OPIC Secured Loan
On June 12, 2001, the Company entered into a loan agreement with OPIC to secure a project financing facility of
$85,000,000. The loan agreement stipulates half yearly principal payments of $4,500,000, due in June and December of
each year, with the final repayment to be made in December 31, 2015. On June 20, 2011, the loan agreement was amended
to release certain sponsor support collateral related to the loan agreement and to terminate various other sponsor support
arrangements. OPIC released the common stock which was pledged by PIE Group LLC, and a parent guarantee originally
provided by InterOil Corporation in 2001 will continue for the remaining life of the loan. The loan is secured over the assets of
the refinery project which had a carrying value of $200,632,040 at December 31, 2011 (2010 - $196,024,838).
The interest rate on the loan is equal to the treasury cost applicable to each promissory note (at the date of draw down)
outstanding plus the OPIC spread (3.00%). During 2011 the weighted average interest rate was 6.93% (2010 – 6.80%) and
the total interest expense included in long term borrowing costs was $2,901,250 (2010 - $3,461,800).
As at December 31, 2011, two installment payments amounting to $4,500,000 each which will be due for payment on June
30, 2012 and December 31, 2012 have been classified into the current portion of the liability. The agreement contains certain
financial covenants which include the maintenance of minimum levels of tangible net worth and limitations on the incurrence
of additional indebtedness for the refining operations. A deposit is also required to be maintained to cover the next
installment and interest payment. As of December 31, 2011, the company was in compliance with all applicable covenants.
Deferred financing costs relating to the OPIC loan of $462,834 (2010 - $686,778) are being amortized over the period until
December 2014 and has been offset against the long term liability and are being amortized using the effective interest
method.
Bank covenants under the above facility currently restrict the payment of dividends by the Company’s subsidiaries E.P. InterOil
Limited and InterOil Limited.
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(b) Mitsui Unsecured Loan
On April 15, 2010, the Company entered into preliminary joint venture and financing agreements with Mitsui relating to the
CS Project. The proposed joint venture is to be entered into for equal shares between Mitsui and InterOil. On August 4, 2010,
the JVOA for the CS Project was finalized. The amount financed by Mitsui for InterOil’s proportion of cash calls is treated as
an unsecured loan with interest being accrued daily at LIBOR plus a margin of 6.00%. The portion of funding that relates to
Mitsui’s share of the project is held in current liabilities. In the event that a positive FID is not reached or made, InterOil will be
required to refund Mitsui’s share of capital expenditure incurred and the unsecured loan within a specified period.
21. Indirect participation interests
December 31, 2011
$
December 31, 2010
$
Indirect participation interest (PNGDV) - current portion 540,002 540,002
Total current indirect participation interest 540,002 540,002
Indirect participation interest (PNGDV) - non current portion 844,490 844,490
Indirect participation interest ("IPI") 33,290,350 33,289,897
Total non current indirect participation interest 34,134,840 34,134,387
Total indirect participation interest 34,674,842 34,674,389
(a) Indirect participation interest (“IPI”)
The IPI balance relates to $125,000,000 received by InterOil subject to the terms of the agreement dated February 25, 2005
between the Company and a number of investors. In exchange InterOil had provided the investors with a 25% interest in an
eight well drilling program to be conducted in InterOil’s PPL 236, 237 and 238.
Under the IPI agreement, InterOil is responsible for drilling eight exploration wells, four of which will be in PPL 238, one in PPL
236, and one in PPL 237. The location of the other two wells is yet to be determined. The investors will be able to approve
the location of the final two wells to be drilled. In the instance that InterOil proposes appraisal or completion of an exploration
or development well, the investors will be asked to contribute to the completion work in proportion to their IPI percentage and
InterOil will bear the remaining cost.
InterOil has made cash calls for the completion, appraisal and development programs performed on the exploration or
development wells that form part of the IPI Agreement. These cash calls are shown as a liability when received and reduced
as amounts are spent on the extended well programs. Should an investor choose not to participate in the completion works
of an exploration well, the investor will forfeit certain rights to the well in question as well as their right to convert into common
shares. InterOil has drilled four exploration wells under the IPI agreement as at December 31, 2011.
The funds of $125,000,000 were partly accounted for as a non-financial liability and partly as a conversion option. The
non-financial liability was initially valued at $105,000,000, being the estimated expenditures to complete the eight well drilling
program, and the residual value of $20,000,000 has been allocated to the conversion option presented under Shareholder’s
equity. InterOil paid financing fees and transaction costs of $8,138,741 related to the indirect participation interest on behalf of
the indirect participation interest investors in 2005. These fees have been allocated against the non-financial liability,
reducing the liability to $96,861,259. InterOil will maintain the liability at its initial value until conveyance is triggered on the
lapse of the conversion option available to the investors, or they elect to participate in the PDL for a successful well. InterOil
will account for the exploration costs relating to the eight well program under the successful efforts accounting policy adopted
by the Company. All geological and geophysical costs relating to the exploration program will be expensed as incurred and all
drilling costs will be capitalized and assessed for recovery at each period.
When an investor elects to participate in a PDL or when the investor forfeits the conversion option, conveyance accounting
will be applied. This entails determination of proceeds for the interests conveyed and the cost of that interest as represented
in the ‘Oil and gas properties’ in the balance sheet. The difference between proceeds on conveyance and capitalized costs to
the interests conveyed will be recognized as gain or loss in the income statement.
Under the agreement, all or part of the 25% initial indirect participation interest could have been converted to a maximum of
3,333,334 common shares in the company, at a price of $37.50 per share, between June 15, 2006 and the later of
December 15, 2006, or 90 days after the completion of the eighth well. Any partial conversion of an indirect participation
interest into common shares will result in a corresponding decrease in the investors’ interest in the eight well drilling program.
As at December 31, 2011, the balance of the indirect participation interest that may be converted into shares is a maximum
of 340,480 common shares (Dec 2010 – 340,480). Should the option to convert to shares not be exercised, the indirect
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participation interest in the eight well drilling program will be maintained and distributions from success in these wells will be
paid in accordance with the agreement. From the date of the agreement up to December 31, 2011, the following transactions
have occurred:
(i) Increase in InterOil’s direct interest in the IPI program by 9.8614% due to the following:
• Conversion of IPI interests: Certain IPI investors representing a 3.575% interest in the IPI agreement have exercised
their right to convert their interest into common shares resulting in issuance of 476,667 InterOil common shares.
These conversions reduced the initial IPI liability balance by $13,851,160 and the initial conversion option balance by
$2,860,000.
• Buyback of IPI interests by the Company: Certain IPI investors representing a 6.2864% interest in the IPI agreement
have sold their interest to the Company. Detailed disclosure of this transaction is provided in the section
‘Extinguishment of IPI liability’ below.
On April 15, 2010 one IPI investor representing 0.4% interest in the IPI agreement waived the conversion right to
convert their IPI percentage into 53,333 shares. On July 19, 2010, the Company bought back this 0.4% interest in the
IPI Agreement from the investor for 208,281 common shares of the Company. The Company has not applied
conveyance accounting on this portion of the IPI agreement, but has accounted for the buyback under the
‘Extinguishment of IPI liability’ model in the quarter ended September 30, 2010.
As at December 31, 2011, InterOil’s direct interest in exploration licenses is 75.6114%, assuming that all remaining indirect
participation interest investors take up their working interest rights in such licenses, and excluding the 20.5% interest that the
State is able to take up under relevant legislation.
(ii) Waiver of conversion rights resulting in conveyance accounting
• Certain IPI investors representing a 12.585% interest in the IPI agreement have waived their right to convert their IPI
percentage into 1,678,000 common shares. As a result, conveyance was triggered on this portion of the IPI
agreement, which reduced the IPI liability by $25,363,405.
• During December 2010, the Company bought a combined 1.05% interest in the IPI Agreement from two investors, out
of which 0.05% related to interests that had already been waived by the investor in the prior year, hence conveyance
accounting was followed for this interest and any premium paid was capitalized to Oil and Gas properties. This 0.05%
was bought for $1,881,959 which was settled through the issue of 25,805 InterOil common shares. The excess of this
consideration over the book value of the IPI liability and the appraisal costs previously cash called from this investor
was $1,550,020 and has been capitalized to Oil and Gas properties.
• As at December 31, 2011, IPI investors with a combined 2.5536% interest in the IPI agreement still have the
conversion rights outstanding resulting in a maximum of 340,480 common shares being issued if all these IPI investors
choose to exercise their conversion options.
(iii) Extinguishment of IPI liability
During September 2009, the Company bought a combined 4.3364% interest in the IPI Agreement from two investors for
$56,479,615 which was settled in two tranches of InterOil common shares. The first tranche of common shares was for 35%
of the total consideration and was issued on September 15, 2009. The second tranche of shares for the remaining 65% of
the total consideration was issued on December 15, 2009 based on a ten day VWAP immediately prior to the date of issue.
As part of this transaction a total number of 1,236,666 shares were issued.
During December 2009, the Company bought a further combined 0.5% interest in the IPI Agreement from two investors for
$6,500,546 which was settled in two tranches of InterOil common shares. The first tranche of common shares was for 35%
of the total consideration and was issued on December 1, 2009. The second tranche of shares for the remaining 65% of the
total consideration was issued on December 15, 2009 based on a ten day VWAP immediately prior to the date of issue. As
part of this transaction a total number of 108,044 shares were issued.
During July 2010, the Company bought a further 0.4% interest in the IPI Agreement from an investor for $10,830,612 which
was settled in InterOil common shares. As part of this transaction a total number of 208,281 shares were issued.
During December 2010, the Company bought a further 1.0% interest in the IPI Agreement from one investor for $37,974,797
which was settled in InterOil common shares. As part of this transaction a total number of 520,702 shares were issued.
Management has adopted the extinguishment liability model. Under this model the consideration paid is allocated to the
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various components involved in the exchange transactions. These components include:
• cash calls made from the IPI investors in relation to the completion, appraisal and development program undertaken in
Elk and Antelope fields as part of the IPI agreement. These cash call amounts were previously offset against the
capitalized oil and gas properties, and have been reinstated in the oil and gas properties asset to their full historical cost
basis for those programs following this exchange transaction.
• fair value of the conversion options extinguished as part of the exchange transactions.
• IPI liability extinguished as part of the exchange transactions whereby the difference between the fair value of the
shares issued and the book value of the IPI liability post allocation to the other components mentioned above has been
recorded as an expense in the statement of operations.
The following table discloses a breakdown of the loss on extinguishment of IPI liability for the periods ended:
Loss on extinguishment of IPI liability
December 31, 2011
$
Year ended
December 31, 2010
$
Consideration paid for exchange transactions - 48,805,409
less amounts capitalized in relation to the appraisal program cash calls - (3,784,466)
less book value of IPI liability extinguished - (5,424,231)
less book value of conversion options extinguished - (1,120,000)
less difference between book value and fair value of conversion options extinguished taken to
contributed surplus
(b) Indirect participation interest – PNGDV
- (7,908,002)
- 30,568,710
As at December 31, 2011, the balance of the PNG Drilling Ventures Limited (“PNGDV”) indirect participation interest in the
Company’s phase one exploration program within the area governed by PPL 236, 237 and 238 is $1,384,492 (Dec 2010 -
$1,384,492). This balance is based on the initial liability recognized in 2006 of $3,588,560 relating to its obligation to drill the
four exploration wells on behalf of the investors, being reduced by amounts already incurred in fulfilling the obligation. PNGDV
has a 6.75% interest in the four exploration wells starting with Elk-1 (with an additional two exploration wells to be drilled after
Elk-4/A). PNGDV also has the right to participate in the 16 wells that follow the first four mentioned above up to an interest of
5.75% at a cost of $112,500 per 1% per well (with higher amounts to be paid if the depth exceed 3,500 meters and the cost
exceeds $8,500,000).
(c) PNG Energy Investors
PNG Energy Investors (“PNGEI”), an indirect participation interest investor who converted all of its interest to common shares
in fiscal year 2004, has the right to participate up to a 4.25% interest in 16 wells commencing from exploration wells
numbered 9 to 24. As at the end of December 31, 2011 we have drilled 6 exploration wells since inception of the Company’s
exploration program within PPL 236, 237 and 238 in PNG. In order to participate, PNGEI would be required to contribute for
each exploration well, a) $112,500 per percentage point or b) where the well is planned to be drilled beyond 2,000 meters,
$112,500 per percentage point plus actual cost over $1,000,000 charged pro-rata per percentage point.
22. Deferred gain on contributions to LNG Project
On July 30, 2007, a Shareholders’ Agreement was signed between InterOil LNG Holdings Inc., Pacific LNG Operations Ltd.,
Merrill Lynch Commodities (Europe) Limited and PNG LNG Inc.. As part of the Shareholders’ Agreement, five ‘A’ Class shares
were issued by PNG LNG Inc. with full voting rights with each share controlling one board position. Two ‘A’ Class shares were
owned by InterOil LNG Holdings Inc., two by Merrill Lynch Commodities (Europe) Limited, and one by Pacific LNG Operations
Ltd. All key operational matters require ‘Unanimous’ or ‘Super-majority’ Board resolution which confirms that none of the joint
ventures are in a position to exercise unilateral control over the joint venture.
On February 27, 2009, InterOil LNG Holdings Inc. and Pacific LNG Operations Ltd, acquired Merrill Lynch’s interest in the
Joint Venture Company. InterOil issued 499,834 common shares valued at $11,250,000 for its share of the settlement. After
the completion of this transaction, Merrill Lynch did not retain any ownership or other interest in the PNG LNG project. The
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two ‘A’ Class shares held by Merrill Lynch have been transferred to InterOil LNG Holdings Inc. and Pacific LNG Operations
Ltd respectively. A further 172 ‘A’ Class shares have been issued to InterOil LNG Holdings Inc. and 173 ‘A’ Class shares have
been issued to Pacific LNG Operations Ltd bringing the ‘A’ Class shareholding of both remaining joint venture partners to 175
‘A’ Class shares each, giving equal voting rights and board positions in the joint venture.
As part of the Shareholders’ Agreement on July 30, 2007, InterOil was also provided with ‘B’ Class shares in the Joint
Venture Company with a fair value of $100,000,000 in recognition of its contribution to the LNG Project at the time of
signing the Shareholders’ Agreement. The main items contributed by InterOil into the Joint Venture Company were
infrastructure developed by InterOil near the proposed LNG site at Napa Napa, stakeholder relations within Papua New
Guinea, general supply agreements secured with landowners for supply of gas, advanced stage of project development, etc.
Fair value was determined based on the agreement between the independent joint venture partners.
The other Joint Venture partner is being issued ‘B’ Class shares as it contributes cash into the Joint Venture Company by way
of cash calls.
During September 2009, as part of acquisition by Pacific LNG of a 2.5% direct working interest in the Elk and Antelope fields,
Pacific LNG transferred to InterOil 2.5% of Pacific LNG’s unexercised economic interest in the joint venture LNG Project.
Based on this transaction, as at December 31, 2010, InterOil and Pacific LNG hold 52.5% and 47.5% economic interest
respectively in the LNG project, subject to the exercise of all their rights to the ‘B’ Class shares on payment of cash calls.
To date InterOil has a recognized deferred gain on its contributions to the Joint Venture based on the share of other joint
venture partners in the project. As InterOil’s shareholding within the Joint Venture Company as at December 31, 2011 is
84.582% (Dec 2010 – 86.66%), the gain on contribution of non cash assets to the project by InterOil relating to other joint
venture partners’ shareholding (15.418% - amounting to $15,113,190) has been recognized by InterOil in its balance sheet as
a deferred gain. This deferred gain may increase/decrease as the other Joint Venture partners decrease/increase their
shareholding in the project.
This amount has been recorded as a reduction of deferred LNG project costs of $9,302,415 at December 31, 2011 (Dec 31,
2010 - $4,126,415), which has reduced the LNG project costs to nil at December 31, 2011, with the remaining balance of
$5,810,775 (Dec 31, 2010 - $8,949,857) being recorded as a deferred gain. Any deferred gain will be recognized in the
consolidated income statement when/if the risks and rewards have considered to be passed. The intangible assets of the
Joint Venture Company, contributed by InterOil, have been eliminated on proportionate consolidation of the joint venture
balances.
23. Asset retirement obligations
The Company plans to dismantle the refinery and restore the site when the refinery is decommissioned. During the quarter
ended June 30, 2011, Management received the final results of an independent assessment of the potential asset retirement
obligations of the refinery at the time of decommissioning and a provision of $4,100,735 was recognized for the present value
of the estimated expenditure required to complete this obligation. The fair value of the best estimate was derived based on
discounting the obligation to the current period end using a discount rate of 7.78%. These costs have been capitalized as
part of the cost of the refinery and are depreciated over the life of the asset. The provision will be accreted over the
remaining useful life of the refinery to bring the provision to the estimated expenditure required at the time of
decommissioning. The accretion expense for the year ended December 31, 2011 was $159,356 (Dec 2010 - $nil).
24. Non controlling interest
The non controlling interest as at December 31, 2010 related to Petroleum Independent and Exploration Corporation’s (“PIE
Corp.”) 0.01% minority shareholding in SPI InterOil LDC. InterOil had entered into an agreement with PIE Corp. under which
the remaining 5,000 shares of SPI InterOil LDC held by PIE Corp. may be exchanged, at InterOil’s election, for Common
Shares on a one-for-one basis. On September 30, 2011, the Company elected to exchange the 5,000 shares of SPI InterOil
LDC held by PIE Corp. with the issue of 5,000 Common Shares of InterOil Corporation. The 5,000 Common Shares issued by
InterOil Corporation were valued at $243,850. The Company now holds 100% of the equity share capital of SPI InterOil LDC.
The carrying amount of the non-controlling interest in the Company on the date of acquisition was $26,300. The Company
derecognized non-controlling interests of $26,300 and recorded a decrease in equity attributable to owners of the Company
of $217,550. The effect of changes in the ownership interest of SPI InterOil LDC on the equity attributable to
owners of the Company during the year is summarized as follows:
105

December 31, 2011
$
December 31, 2010
$
Carrying amount of non-controlling interests acquired 26,300 -
Consideration paid to non-controlling interests (243,850) -
Excess of consideration paid recognised in Company's equity (217,550) -
25. Share capital and reserves
The authorized share capital of the Company consists of an unlimited number of common shares with no par value. Each
common share entitles the holder to one vote.
(a) Common shares - Changes to issued share capital were as follows:
Number of shares $
January 1, 2010 43,545,654 613,361,363
Shares issued on exercise of options under Stock Incentive Plan 479,733 19,310,657
Shares issued on vesting of restricted stock units under Stock Incentive Plan 20,700 1,418,985
Shares issued on buyback of IPI#3 Interest 754,788 50,687,368
Shares issued on litigation settlement 199,677 12,000,000
Shares issued on public offering 2,800,000 198,872,679
December 31, 2010 47,800,552 895,651,052
Shares issued on exercise of options under Stock Incentive Plan 265,440 7,087,574
Shares issued on vesting of restricted stock units under Stock Incentive Plan 50,079 2,999,138
Shares issued on buyback of non-controlling interest 5,000 243,850
December 31, 2011 48,121,071 905,981,614
Settlement of litigation - The Company’s Chief Executive Officer, Phil Mulacek, and his controlled entities Petroleum
Independent & Exploration Corporation and P.I.E. Group, LLC, together with the Company and certain of its subsidiaries,
were defendants in Todd Peters, et. al. v. Phil Mulacek et. al.; Cause No. 05-040-03592-CV; in the 284th District Court of
Montgomery County, Texas. The plaintiffs are members of a partnership that bought a modular oil refinery that was
subsequently, through a series of transactions, sold to a subsidiary of the Company. We entered into an agreement in August
2010 to settle and release all claims against us and our subsidiaries. Pursuant to the agreed settlement, which was approved
by the Court in September, we issued 199,677 common shares to the plaintiffs during October, valued at $12 million based
on a volume weighted average price calculated over the ten trading days prior to execution of the settlement agreement.
(b) Nature and purpose of reserves
• Foreign currency translation reserve: Exchange differences arising on translation of the foreign controlled entity
are recognized in other comprehensive income and accumulated in a separate reserve within equity. The cumulative
amount is reclassified to profit or loss when the net investment is disposed of.
• Available-for-sale financial assets: Changes in the fair value and exchange differences arising on translation of
investments, such as equities classified as available-for-sale financial assets, are recognized in other comprehensive
income and accumulated in a separate reserve within equity. Amounts are reclassified to profit or loss when the
associated assets are sold or impaired.
• Conversion options: This reserve is used to recognize the value of the conversion option included in the agreement
with IPI investors (refer to note 21). This balance will reduce when IPI investors sell their interest back to the Company.
• Contributed surplus: The contributed surplus reserve is used to recognize the fair market value of employee stock
options and restricted stock units that have not been forfeited or been exercised.
26. 2.75% convertible notes
On November 10, 2010, the Company completed the issue of $70,000,000 unsecured 2.75% convertible notes with a
maturity of five years. The note holders have the right to convert their note into common shares at any time at a conversion
rate of 10.4575 common shares per $1,000 principal amount of notes (which results in an effective initial conversion price of
approximately $95.625 per share). The Company has the right to redeem the notes if the daily closing sale price of the
common shares has been at least 125% of the conversion price then in effect for at least 15 trading days during any 20
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consecutive trading day period. Accrued interest on these notes is to be paid semi-annually in arrears, in May and November
of each year, commencing May 2011.
The liability component on initial recognition after adjusting for the underwriting placement fee and transaction costs
amounted to $51,992,857 and the equity component amounted to $14,298,036. The liability component will be accreted
over the five year maturity period to bring the liability back to the carrying value. The accretion expense relating to the note
liability for the year ended December 31, 2011 was $3,212,141 (Dec 2010 - $432,632). In addition to the accretion,
interest at 2.75% per annum has been expensed for the year ended December 31, 2011 amounting to $1,925,000 (Dec
2010 - $278,056). The interest payable up to November 2011 was paid in cash.
27. Stock compensation
(a) Stock options
Options are issued at no less than market price to directors, certain employees and to a limited number of contractor
personnel. Options are exercisable for common shares on a 1:1 basis. Individuals are granted options which only vest if
certain performance standards are met, with the vesting of the majority of options issued only being reliant on the individual
remaining employed with the Company for a certain time period, while the vesting of some options granted are reliant on
various performance conditions. Options vest at various dates in accordance with the applicable individual option
agreements, vesting generally between one to four years after the date of grant, have an exercise period of three to five years
after the date of grant, and are subject to the option plan rules. Upon resignation or retirement, vested options must generally
be exercised within 90 days or before expiry of the options if this occurs earlier.
Stock options outstanding Number of options Weighted average
exercise price $
December 31, 2011 December 31, 2010
Number of options
Weighted average
exercise price $
Outstanding at beginning of period 1,688,267 27.31 1,838,500 22.07
Granted 110,000 59.89 330,000 54.02
Exercised (265,440) (16.91) (479,733) (25.59)
Forfeited (45,000) (47.33) - -
Expired - - (500) (28.68)
Outstanding at end of period 1,487,827 30.97 1,688,267 27.31
At December 31, 2011, in addition to the options outstanding as per the above table, there were an additional 1,176,531
(2010 – 1,315,617) common shares reserved for issuance under the Company’s 2009 stock incentive plan as approved on
June 19, 2009.
Range of exercise
prices $
Options issued and outstanding
Number of options
Weighted average exercise
price $
Weighted average
remaining term (years)
Options exercisable
Number of options
Weighted average exercise
price $
8.01 to 12.00 503,160 9.80 1.90 403,160 9.80
12.01 to 24.00 135,000 16.90 1.78 95,000 17.37
24.01 to 31.00 100,500 27.74 1.44 100,500 27.74
31.01 to 41.00 234,167 35.46 1.20 180,833 35.94
41.01 to 51.00 75,000 44.86 1.48 75,000 44.86
51.01 to 61.00 380,000 53.08 3.72 - -
61.01 to 71.00 30,000 66.58 3.63 15,000 66.58
71.01 to 81.00 30,000 74.82 4.23 - -
1,487,827 30.97 2.70 869,493 22.14
Aggregate intrinsic value of the 1,487,827 options issued and outstanding as at December 31, 2011 is $27,993,610.
Aggregate intrinsic value of 869,493 options exercisable as at December 31, 2011 is $12,123,867.
The weighted-average grant-date fair value of options granted during 2011 was $37.46 (2010 - $32.26). The total intrinsic
value of options exercised during the year ended December 31, 2011 was $2,598,871 (2010 - $7,035,772). Cash received
from option exercise under all share-based payment arrangements for the year ended December 31, 2011 was $4,488,703
(2010 - $12,274,885).
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The weighted-average share price at the date of exercise of options exercised during the year ended December 31, 2011 was
$61.54 (2010 - $68.32).
The fair value of the 110,000 (2010 – 330,000) options granted subsequent to January 1, 2011 has been estimated at
the date of grant in the amount of $4,121,016 (2010 - $10,645,501) using a Black-Scholes pricing model. An amount of
$9,839,824 (2010 - $7,628,017) has been recognized as compensation expense for the year ended December 31, 2011.
The current year compensation expense of $9,839,824 (2010 - $7,628,017) was adjusted against contributed surplus under
equity and $2,598,871 (2010 - $7,035,773) was transferred to share capital on exercise of options, leaving a net impact of
$7,240,953 (2010 - $592,244) on contributed surplus.
The assumptions contained in the Black Scholes pricing model are as follows:
Year Period Risk free interest rate (%) Dividend yield Volatility (%) Weighted average expected life for options
2011 Apr 1 to Dec 31 0.4 - 78 5.0
2011 Jan 1 to Mar 31 1.2 - 79 5.0
2010 Jul 1 to Dec 31 0.8 - 87 5.0
2010 Jan 1 to Jun 30 1.2 - 87 5.0
(b) Restricted stock
Restricted stock may be issued to directors, certain employees and to a limited number of contractor personnel under the
Company’s 2009 stock incentive plan. Restricted stock vests at various dates in accordance with the applicable restricted
stock agreement, vesting generally between one to three years after the date of grant.
Restricted stock units outstanding
Number of
restricted stock
units
December 31, 2011
$
Weighted Average
Grant Date
Fair Value per
restricted stock
unit $
Number of
restricted stock
units
December 31, 2010
$
Weighted Average
Grant Date
Fair Value per
restricted stock
unit $
Outstanding at beginning of period 124,192 56.99 41,400 68.55
Granted 97,069 67.06 107,483 54.73
Exercised (50,079) (59.89) (20,700) (68.55)
Forfeited (18,992) (64.34) (3,991) (56.13)
Total 152,190 61.54 124,192 56.99
An amount of $4,881,563 (2010 - $4,175,983) has been recognized as compensation expense for the year ended
December 31, 2011. The current year compensation expense of $4,881,563 (2010 - $4,175,983) was adjusted against
contributed surplus under equity and $2,999,138 (2010 - $1,418,985) was transferred to share capital on vesting of stock
units, leaving a net impact of $1,882,425 (2010 - $2,756,998) on contributed surplus.
28. Earnings/(Loss) per share
Conversion options, convertible notes, stock options and restricted stock units totaling 2,712,522 common shares at prices
ranging from $9.80 to $95.63 were outstanding as at December 31, 2011 and some of these were included in the
computation of the diluted earnings per share for the year ended December 31, 2011. The dilutive instruments outstanding at
December 31, 2010 were not included in the computation of the diluted loss per share in respective periods because they
caused the loss per share to be anti-dilutive.
Potential dilutive instruments outstanding Number of shares December 31, 2011 Number of shares December 31, 2010
Employee stock options 1,487,827 1,688,267
Employee Restricted Stock 152,190 124,192
IPI Indirect Participation interest - conversion options 340,480 340,480
2.75% Convertible notes 732,025 732,025
Others - 5,000
Total stock options/shares outstanding 2,712,522 2,889,964
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The income available to the common shareholders and the income available to the dilutive holders, used in the calculation of
the numerator in the EPS calculation for the year ended December 31, 2011 and 2010 is the net profit/loss as per
Consolidated Income Statement. This is due to the fact that the inclusion of convertible securities in the calculation would
result in the EPS being anti-dilutive.
The reconciliation between the ‘Basic’ and ‘Basic and Diluted’ shares, used in the calculation of the denominator in the EPS
calculation is as follows:
December 31, 2011
$
Year ended
December 31, 2010
$
Basic 47,977,478 44,329,670
Employee options 803,507 -
Employee restricted stock 88,985 -
Indirect participation interest 340,480 -
Other 3,740 -
Diluted 49,214,190 44,329,670
29. Commitments and contingencies
(a) Exploration and debt commitments
Payments due by period contractual obligations are as follows:
Petroleum prospecting and retention
licenses (a)
Less than
Total Less than 1 year 1-2 years 2-3 years 3-4 years 4-5 years More than 5 years
'000 '000 '000 '000 '000 '000 '000
134,900 44,400 36,350 44,050 9,900 200 -
Secured and unsecured loans (b) 51,586 21,727 10,749 10,131 8,979 - -
Convertible notes obligations 77,540 1,925 1,925 1,925 71,765 - -
Indirect participation interest - PNGDV
(note 21)
1,384 540 844 - - - -
265,410 68,592 49,868 56,106 90,644 200 -
(a) The amount pertaining to the petroleum prospecting and retention licenses represents the amount InterOil has committed as a condition on renewal of
these licenses. Company is committed to spend a further $61.9 million as a condition of renewal of our petroleum prospecting licenses up to 2014. Of this
$61.9 million commitment, as at December 31, 2011, 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 the Company to spend a further $73.0 million on the development of the Elk and Antelope fields by the end of 2014.
(b) The effective interest rate on this loan for the year ended December 31, 2011 was 6.93%.
(b) Operating lease commitments – Company as lessee
The Company leases various retail service station premises, commercial office properties, residential apartments, motor
vessels and office equipment under non-cancellable operating lease agreements. The remaining lease terms are between 1
and 30 years, and the majority of lease agreements are renewable at the end of the lease period at market rate.
The future aggregate minimum lease payments under non-cancellable operating leases are as follows:
December 31, 2011
$
December 31, 2010
$
Not later than 1 year 6,983,149 6,257,276
Later than 1 year and not later than 5 years 6,560,263 8,558,043
Later than 5 years 2,957,605 458,071
Total 16,501,017 15,273,390
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(c) Contingencies
From time to time the Company is involved in various claims and litigation arising in the course of its business. While the
outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s
favor, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened
proceedings or any amount which it may be required to pay by reason thereof would have a material adverse impact on its
financial position, results of operations or liquidity.
Audit by PNG Customs
During the second half of 2011, the PNG Customs Service commenced an audit of our petroleum product imports into Papua
New Guinea for the years 2007 to 2010. The Company received a letter in November 2011 from the then Commissioner of
Customs setting out certain findings from the audit. This letter included comments alleging that payment of import GST was
required and had not been made on imports of certain refined products. As well as requiring payment of GST, the letter noted
that administrative penalties were able to be levied by Customs in the range of 50% to 200% of the assessed amounts as per
the Customs Act. The Company has since met with the Customs Service and provided it with supporting documentation to
demonstrate that the GST amounts claimed in their letter have all been paid. Management has included a provision in these
financial statements based on their best estimate in relation to this matter and is working closely with the authority to provide
all requested information in order to finalize the audit.
110

Glossary of Terms
“2011 Annual Information Form” means the Annual Information Form for the year ended December 31, 2011.
“2011 MD&A” means the Management’s Discussion and Analysis for the year ended December 31, 2011.
“AUD” means Australian dollars.
“API” means the American Petroleum Institute.
“Barrel, Bbl” (petroleum) Unit volume measurement used for petroleum and its products.
“BNP Paribas” means BNP Paribas Capital (Singapore) Limited.
“Board” means the board of directors of InterOil.
“BP” means BP Singapore Pte Limited.
“BSP” means Bank of South Pacific Limited.
“CDU” means crude distillation unit.
“CGR” means condensate to gas ratio.
“COGE Handbook” refers to the Canadian Oil and Gas Evaluation Handbook.
“Condensate” A component of natural gas which is a liquid at surface conditions.
“Convertible notes” means the 2.75% convertible senior notes of InterOil due November 15, 2015.
“Crack spread” The simultaneous purchase or sale of crude against the sale or purchase of refined petroleum products. These spread differentials which
represent refining margins are normally quoted in dollars per barrel by converting the product prices into dollars per barrel and subtracting the crude price.
“CRU” means catalytic reformer unit.
“Crude oil” A mixture consisting mainly of pentanes and heavier hydrocarbons that exists in the liquid phase in reservoirs and remains liquid at atmospheric
pressure and temperature. Crude oil may contain small amounts of sulfur and other non hydrocarbons but does not include liquids obtained from the
processing of natural gas.
“CSP Joint Venture” or “CSP JV” means the Joint Venture Operating Agreement (“JVOA”) entered into for the proposed condensate stripping facilities with
Mitsui or the joint venture formed to develop and operate the proposed condensate stripping facilities as the context requires.
“Condensate Stripping Project” means the proposed condensate stripping facilities, including gathering and condensate pipeline, condensate storage and
associated facilities being progressed in joint venture with Mitsui.
“DST” refers to a drill stem test and is a procedure for isolating and testing the surrounding geological formation through the drill pipe.
“EBITDA” EBITDA represents net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation
and amortization expense. EBITDA is a non-GAAP measure used to analyze operating performance. See “Non-GAAP Measures and Reconciliation”.
“EPC Contractor” means an engineering, procurement and construction contractor.
“ERP” means Enterprise Resource Planning System.
“EWC” means Energy World Corporation Limited., a company organized under the laws of Australia.
“Farm out” A contractual agreement with an owner who holds a working interest in an oil and gas lease to assign all or part of that interest to another party
in exchange for the other party’s fulfillment of contractually specified conditions. Farm out agreements often stipulate that a party must drill a well to a certain
depth, at a specified location, within a certain time frame; furthermore, typically, the well must be completed as a commercial producer to earn an assignment
of the working interest. The assignor of the interest usually reserves a specified overriding royalty interest, with the option to convert the overriding royalty
interest to a specified working interest upon payout of drilling and production expenses.
“FEED” means front end engineering and design.
“Feedstock” means raw material used in a refinery or other processing plant.
“FID” means final investment decision. Such a decision is ordinarily the point at which a decision is made to proceed with a project and it becomes
unconditional. However, in some instances the decision may be qualified by certain conditions, including being subject to necessary approvals by the State.
“FLEX LNG” means FLEX LNG Limited, a British Virgin Islands Company listed on the Oslo Stock Exchange.
111

“GAAP” means Canadian generally accepted accounting principles.
“Gas” means a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs but are gaseous at atmospheric
conditions. Natural gas may contain sulfur or other non-hydrocarbon compounds.
“GLJ” means GLJ Petroleum Consultants Limited, an independent qualified reserves evaluator.
“GLJ 2010 Report” means the report dated March 7, 2011 with an effective date of December 31, 2010 setting forth certain information regarding contingent
resources of InterOil’s interests in the Elk and Antelope fields in PNG.
“GLJ 2011 Report” means the report dated February 28, 2012 with an effective date of December 31, 2011 setting forth certain information regarding
contingent resources of InterOil’s interests in the Elk and Antelope fields in PNG.
“Gross reserves” refers to InterOil’s working interest reserves before the deduction of royalties and before including any royalty interests.
“Gross wells” refers to the total number of wells in which we have an interest.
“ICCC” means Papua New Guinea’s competition authority, the Independent Consumer and Competition Commission.
“IFRS” means International Financial Reporting Standards as issued by the International Accounting Standards Board.
“IPI Agreement” means the Amended and Restated Indirect Participation Agreement dated February 25, 2005, as amended.
“IPI holders” means investors holding IPWIs in certain exploration wells required to be drilled pursuant to the IPI Agreement.
“IPF” refers to InterOil power fuel, InterOil’s marketing name for low sulfur waxy residue or LSWR.
“IPP” means import parity price. For each refined product produced and sold locally in Papua New Guinea, IPP is calculated under agreement with the State
by adding the costs that would typically be incurred to import such product to an average posted price for such product in Singapore as reported by Platts.
The costs added to the reported Platts price include freight costs, insurance costs, landing charges, losses incurred in the transportation of refined products,
demurrage and taxes.
“IPWI” means indirect participation working interest.
“LIBOR” means daily reference rate based on the interest rates at which banks borrow unsecured funds from banks in the London wholesale money market.
“LNG” means liquefied natural gas. Natural gas may be converted to a liquid state by pressure and severe cooling for transportation purposes, and then
returned to a gaseous state to be used as fuel. LNG, which is predominantly artificially liquefied methane, is not to be confused with NGLs, natural gas
liquids, which are heavier fractions that occur naturally as liquids.
“LNGL” means Liquid Niugini Gas Limited, a wholly owned subsidiary of PNG LNG formed in Papua New Guinea to contract with the State and pursue the
LNG Project, including construction of the proposed liquefaction facilities.
“LNG Project” means the development by us of liquefaction facilities in the Gulf Province of Papua New Guinea described as our Midstream Liquefaction
business segment and being undertaken as a joint venture with Pac LNG and with other potential partners, including the State.
“LNG Project Agreement” means the LNG Project Agreement between the State and LNGL dated December 23, 2009.
“LSWR” means low sulfur waxy residue.
“Mark-to-market” refers to the accounting standards of assigning a value to a position held in a financial instrument based on the current fair market price for
the instrument or similar instruments.
“Mitsui” refers to Mitsui & Co., Ltd., a company organized under the laws of Japan and/or certain of its wholly-owned subsidiaries (as the context requires).
“Mtpa” means million tonnes per annum.
“Naphtha” That portion of the distillate obtained from the refinement of petroleum which is an intermediate between the lighter gasoline and the heavier
benzene. It is a feedstock destined either for the petrochemical industry or for gasoline production by reforming or isomerisation within a refinery.
“Natural gas” means a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s
surface, often in association with petroleum. The principal constituent is methane.
“NGL” means natural gas liquids, consisting of any one or more of propane, butane and condensate.
“Net wells” refers to the aggregate of the numbers obtained by multiplying each gross well by our percentage working interest in that well.
“NI 51-101” refers to National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities adopted by the Canadian Securities Administrators.
“NI 52-110” refers to National Instrument 52-110 - Audit Committees adopted by the Canadian Securities Administrators.
“OPIC” means Overseas Private Investment Corporation, an agency of the United States Government.
112

“Pac LNG” means Pacific LNG Operations Ltd., a company incorporated in the Bahamas and affiliated with Clarion Finanz A.G. This company is our joint
venture partner in the LNG Project (holding equal voting shares in PNG LNG), holds a 2.5% direct interest in the Elk and Antelope fields, is an IPI holder and a
shareholder in PNGDV.
“PDL” means Petroleum Development License. The right granted by the State to develop a field for commercial production.
“Petromin” means Petromin PNG Holdings Limited, a company incorporated in Papua New Guinea by the State.
“PGK” means the Kina, currency of Papua New Guinea.
“PNGDV” means PNG Drilling Ventures Limited, an entity with which we entered into an indirect participation agreement in May 2003, as amended.
“PNG LNG” means PNG LNG, Inc., a joint venture company established in 2007 to hold the interests of certain joint venturers in the venture to construct the
proposed liquefaction facilities. Shareholders are InterOil LNG Holdings Inc., a wholly-owned subsidiary of InterOil, and Pac LNG.
“PPL” means Petroleum Prospecting License. The tenement given by the State to explore for oil and gas.
“PRL” means Petroleum Retention License. The tenement given by the State to allow the license holder to evaluate the commercial and technical options for
the potential development of an oil and/or gas field.
“Prospective Resources” are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by
application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective
Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development
and may be sub classified based on project maturity.
“Samsung Heavy Industries” means Samsung Heavy Industries Co., Ltd., a corporation incorporated and existing under the laws of the Republic of Korea.
“SGD” means Singapore Dollars.
“Shut-in” refers to wells that are capable of producing oil or natural gas which are not producing due to lack of available transportation facilities, available
markets or other reasons.
“State” or “PNG” means the Independent State of Papua New Guinea.
“Sweet/sour crude” Sweetness describes the degree of a given crude’s sulfur content. Sour crudes are high in sulfur, sweet crudes are low.
“USD” means United States Dollars.
“Westpac” means Westpac Bank PNG Limited.
“Working interest” means the percentage of undivided interest held by InterOil in an oil and natural gas property.
“YBCA” means the Business Corporations Act (Yukon Territory).
Conversion
The following table sets forth certain standard conversions between Standard Imperial Units and the International System of
Units (metric units).
To Convert From
mcf
cubic metres
bbls
cubic metres
feet
metres
miles
kilometers
acres
hectares
To
cubic metres
cubic feet
cubic metres
bbls
metres
feet
kilometers
miles
hectares
acres
Multiply By
28.317
35.315
0.159
6.289
0.305
3.281
1.609
0.621
0.405
2.471
113

Corporate Directory
Directors and Executive Officers
The following table provides information with respect to all of our directors and executive officers:
Name, Location Position with InterOil Date of Appointment
Phil E. Mulacek
Texas, USA
Christian Vinson
Port Moresby, PNG
Gaylen Byker
Michigan, USA
Roger Grundy
Derbyshire, UK
Roger F. Lewis
Western Australia, Australia
Ford Nicholson
British Columbia, Canada
William Jasper III
Texas, USA
Collin Visaggio
Western Australia, Australia
Mark Laurie
South Australia, Australia
Notes
Chairman, Director and Chief Executive Officer May 29, 1997
Vice President Corporate Development and
Government Affairs, Director
May 29, 1997
Director (1) May 29, 1997
Director (2) May 29, 1997
Director (3) November 26, 2008
Director (4) June 22, 2010
President and Chief Operating Officer September 18, 2006
Chief Financial Officer October 26, 2006
General Counsel and Corporate Secretary June 12, 2007
1 Gaylen Byker acts is the Company’s Lead Independent Director and acts as Chairman of each of the Board’s Nominating and
Governance Committee and Compensation Committee and has held such positions throughout 2011. He is a member of the Audit
Committee and of the Reserves Committee. He acts as deputy Chairman of the Board and chairs a number of its meetings.
2 Roger Grundy was Chairman of the Reserves Committee throughout 2011.
3 Roger Lewis was Chairman of the Audit Committee, and a member of the Nominating and Governance Committee and Compensation
Committee throughout 2011.
4 Ford Nicholson was a member of the Audit Committee and Reserves Committee throughout 2011.
5 Certain information has been furnished by our directors and executive officers. Such information includes information as to our common
shares in the Company beneficially owned, controlled or directed, directly or indirectly, by them, their places of residence and principal
occupations, both present and historical, interests in material transactions and potential conflicts of interest.
Operational Office Locations
Cairns, Australia
Level 3, Cairns Square
42 - 52 Abbott street
Cairns Queensland 4870 Australia
Telephone: +61 (7) 4046 4600
Facsimile: +61 (7) 4031 4565
Port Moresby, Papua New Guinea
InterOil Limited
InterOil Refinery
Post Office Box 1971
Port Moresby, NCD
Telephone: +(675) 309-9100
Facsimile: +(675) 309-9188
Houston, Texas USA
25025 I-45 North, Suite 420
The Woodlands, Texas 77380
Telephone: +1 (281) 292-1800
Facsimile: +1 (281) 292-0888
Singapore
InterOil Singapore Pte Ltd
7 Temasek Boulevard
#28-01 Suntec Tower One
Singapore 038987
Telephone: +65 6507 0222
Facsimile: +65 6884 9562
114

Stock Exchanges
United States of America
NYSE Euronext
11 Wall Street
New York, New York 10005
www.nyse.com
Trading symbol: IOC
Papua New Guinea
Port Moresby Stock Exchange Limited
Defens Haus, 4th Floor
Port Moresby NCD
Papua New Guinea
Telephone: +1 (675) 320-1980
www.pomsox.com.pg
Trading symbol: IOC
Auditors
PricewaterhouseCoopers
2 Southbank Boulevard
Southbank, VIC 3006
DX 77 Melbourne, Australia
Telephone +61 (3) 8603 1000
Facsimile +61 (3) 8603 1999
Transfer Agent and Share Registrars
Main Agent
Computershare Investor Services Inc.
100 University Avenue, 9th Floor
Toronto, Ontario
Canada M5J 2YI
Telephone: (800) 564-6253
Facsimile: (888) 453-0330
E-mail: service@computershare.com
Website: www.computershare.com
Co-Transfer Agent (USA)
Computershare Trust Company N.A.
350 Indiana Street
Golden, Colorado 80401 USA
Telephone: (800) 962-4284
International: (514) 982-7555
Legal
Canada
Bennett Jones LLP
45 Bankers Hall East
855 2nd Street SW
Calgary, Alberta T2P 4K7
Telephone: +1 (403) 298-3100
Australia Papua New Guinea
Gadens Lawyers
77 Castlereagh Street
Sydney NSW 2000 Australia
Telephone: +1 (61) 2 9931 4999
United States of America
Haynes and Boone LLP
Attorneys and Counselors
901 Main Street Suite 3100
Dallas, Texas 75202 USA
Telephone: +1 (214) 651-5000
Bankers
Canada
Canadian Imperial Bank of Commerce
Commerce Court
Toronto ON M5L 1A2 Canada
Telephone: +1 (416) 980-2211
United States of America
Wells Fargo Bank TX N.A.
1500 Broadway
Lubbock, Texas 79401 USA
Telephone: +1 (806) 767-7418
Australia Papua New Guinea
Australian and New Zealand Bank
Defens Haus, 3rd Floor
Port Moresby NCD
Papua New Guinea
Telephone: +1 (675) 322-3333
Investor Relations
Wayne W. Andrews
Vice President of Capital Markets
The Woodlands, Texas
Email: wayne.andrews@interoil.com
Meg LaSalle
Investor Relations Coordinator
The Woodlands, Texas
Email: meg.lasalle@interoil.com
Global Agency of Record
Content Media Group Limited
The Woodlands, Texas
www.contentmedia.cc
Where Applicable: Photography by Greg Davis (www.gregdavisphotography.com)
115

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