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ANNUAL<br />
REPORT<br />
2011<br />
NYSE: IOC
An Energy Development Company With Significant<br />
Exploration Potential<br />
About <strong>InterOil</strong> <strong>Corporation</strong><br />
<strong>InterOil</strong> <strong>Corporation</strong> is developing a vertically integrated energy business whose primary focus is Papua New Guinea<br />
and <strong>the</strong> surrounding region. <strong>InterOil</strong>’s assets consist of petroleum licenses covering about 3.9 million acres, an oil<br />
refinery, and retail and commercial distribution facilities, all located in Papua New Guinea. In addition, <strong>InterOil</strong> is a<br />
shareholder in a joint venture established <strong>to</strong> construct an LNG plant in Papua New Guinea. <strong>InterOil</strong>’s common shares<br />
trade on <strong>the</strong> NYSE in US dollars.<br />
www.interoil.com
Letter From The Chairman<br />
6<br />
Upstream<br />
8<br />
Midstream - Refining and Liquefaction<br />
13<br />
Table of Contents<br />
Downstream<br />
18<br />
The Environment and Community Relations<br />
21<br />
Management Discussion and Analysis<br />
24<br />
Operational Highlights<br />
29<br />
Management’s Report<br />
59<br />
Independent Audi<strong>to</strong>r’s Report<br />
60<br />
Consolidated Financial Statements<br />
62<br />
Glossary of Terms<br />
111<br />
Corporate Direc<strong>to</strong>ry<br />
114
Direc<strong>to</strong>rs and Executive Officers<br />
Front / Left <strong>to</strong> Right<br />
Ford Nicholson, Board Member Gaylen Byker, Board Member<br />
William J. Jasper lll, President and Chief Operating Officer Collin Visaggio, Chief Financial Officer<br />
Roger Lewis, Board Member<br />
Back / Left <strong>to</strong> Right<br />
Christian Vinson, Executive Vice President of Corporate Development and Government Affairs<br />
Phil E. Mulacek, Chairman, Direc<strong>to</strong>r and Chief Executive Officer Roger Grundy, Board Member<br />
Mark Laurie, General Counsel and Corporate Secretary Wayne Andrews, Vice President Capital Markets<br />
For more information, please see Page 114.
Global Operational Office Locations<br />
The Woodlands, Texas USA<br />
Singapore<br />
Port Moresby, Papua New Guinea<br />
Cairns, Australia
Letter From The Chairman<br />
To Our Shareholders<br />
Following up on several years of drilling success, 2011 was a year of progress in engineering and design as well as<br />
investment in critical LNG development infrastructure and exploration activities. These investments have positioned us <strong>to</strong><br />
continue <strong>to</strong> create value for shareholders in 2012. As our LNG project costs have become more clearly defined, our<br />
prospective LNG equity partners have a better view on <strong>the</strong> economics of <strong>the</strong> project. When <strong>the</strong> partnering process is<br />
<strong>complete</strong>d, we will move <strong>to</strong>ward satisfying our 2009 Project Agreement with <strong>the</strong> Papua New Guinea (PNG) Government. As<br />
<strong>the</strong> rewards come in<strong>to</strong> focus, we clearly see significant opportunity on <strong>the</strong> horizon.<br />
Our net profit for <strong>the</strong> year ended December 31, 2011 was $17.7 million. Our Corporate, Midstream Refining and Downstream<br />
operating segments delivered excellent results, generating a profit of $82.3 million for <strong>the</strong> year - which helped <strong>to</strong> fund<br />
investment in our developmental segments of Upstream and Midstream Liquefaction. Our year-end <strong>to</strong>tal assets exceeded $1<br />
billion for <strong>the</strong> first time, and our balance sheet retains considerable financial flexibility with a debt-<strong>to</strong>-capital ratio of 12%.<br />
During <strong>the</strong> year we have made progress on <strong>the</strong> engineering and design of our proposed LNG project in PNG. Our<br />
accomplishments for <strong>the</strong> year include preliminary Front End Engineering and Design (FEED) on <strong>the</strong> ga<strong>the</strong>ring system, which<br />
connects <strong>the</strong> production wells <strong>to</strong> <strong>the</strong> Condensate Stripping Plant (CSP). We have <strong>complete</strong>d FEED on <strong>the</strong> CSP, received bids,<br />
and are prepared <strong>to</strong> award <strong>the</strong> contract <strong>to</strong> <strong>the</strong> winning bidder. We have <strong>complete</strong>d FEED on <strong>the</strong> Pipeline and received bids<br />
on steel, coating and installation. We are advanced on <strong>the</strong> FEED for <strong>the</strong> marine facility and portions of <strong>the</strong> facility are out for<br />
tender. The only FEED remaining is a test of <strong>the</strong> soil where <strong>the</strong> liquefaction plants are proposed <strong>to</strong> be built, and this is now<br />
under way.<br />
Last year was also an active time for <strong>InterOil</strong>’s exploration team as we continued <strong>to</strong> conduct exploration operations and<br />
acquisition of seismic data in our licenses PPL236, PPL237, PPL238 and PRL15. Airborne gravity data and seismic data<br />
acquisition are <strong>the</strong> primary <strong>to</strong>ols utilized <strong>to</strong> expand basic exploration coverage, add leads <strong>to</strong> our portfolio, and create drillable<br />
prospects. The primary near-term directive of <strong>the</strong> exploration group is <strong>to</strong> create a mature prospect inven<strong>to</strong>ry for a continuous<br />
multi-well exploration program.<br />
In 2011 we <strong>complete</strong>d, or had in progress, 300.4 kilometers (187 miles) of seismic data acquisition. This seismic data<br />
improves <strong>the</strong> definition of known leads and prospects and identifies new near-field potential. The final processed gravity data<br />
acquired in late 2011 is now becoming available and initial assessment suggests a definition for closure of <strong>the</strong> Tricera<strong>to</strong>ps<br />
6
field. We spudded <strong>the</strong> Tricera<strong>to</strong>ps-2 well early in 2012 which represented <strong>the</strong> re-commencement of our exploration drilling<br />
program and we will soon be mobilizing our development drilling rig <strong>to</strong> <strong>the</strong> Elk and Antelope field area <strong>to</strong> commence fur<strong>the</strong>r<br />
appraisal and development work.<br />
In early 2012, <strong>the</strong> Tricera<strong>to</strong>ps-2 well has successfully drilled a very promising section of limes<strong>to</strong>ne reservoir and could be in a<br />
position <strong>to</strong> add material value <strong>to</strong> our shareholders in 2012. This will be <strong>the</strong> third consecutive structure drilled and developed<br />
by <strong>the</strong> company, proving our capacity <strong>to</strong> organically build a strong hydrocarbon resource base in PNG.<br />
In 2011, we determined that LNG market conditions were favorable <strong>to</strong> seek a “proven LNG opera<strong>to</strong>r.” With <strong>the</strong> help of our<br />
advisors, we are on schedule <strong>to</strong> find that LNG partner in order <strong>to</strong> satisfy <strong>the</strong> remaining requirements of our 2009 LNG Project<br />
Agreement commitment with <strong>the</strong> PNG Government. We are pleased with <strong>the</strong> level of interest among companies that fit <strong>the</strong><br />
profile required by <strong>the</strong> agreement and anticipate a positive conclusion <strong>to</strong> <strong>the</strong> selection process in <strong>the</strong> near future.<br />
Our objectives remain <strong>to</strong> derive value for our shareholders, <strong>to</strong> support safe and efficient operations for our employees, and <strong>to</strong><br />
be a good partner <strong>to</strong> those with whom we do business.<br />
Our annual update would not be <strong>complete</strong> without discussing our efforts <strong>to</strong> improve <strong>the</strong> lives of <strong>the</strong> people in <strong>the</strong> communities<br />
in which we conduct our business. <strong>InterOil</strong> has been active in promoting women’s health and education programs in <strong>the</strong><br />
Purari community, providing fresh water supply <strong>to</strong> a local village, and assisting a local school re-opening at Wabo. <strong>InterOil</strong><br />
also sponsored <strong>the</strong> training of direc<strong>to</strong>rs of a local company representing four Motu villages, and has sponsored higher<br />
education for deserving individuals in <strong>the</strong> communities where we operate.<br />
We are also proud <strong>to</strong> <strong>report</strong> that, with about 1,000 PNG citizens employed by <strong>InterOil</strong>, we have worked 10.6 million man<br />
hours without a lost time injury. Safety has always been a priority for <strong>InterOil</strong> and this remarkable achievement is a testament<br />
<strong>to</strong> <strong>the</strong> tireless dedication by all of our employees.<br />
We believe that <strong>the</strong>re is a vast amount of value within <strong>InterOil</strong> that will be realized as we fur<strong>the</strong>r execute our LNG partnering<br />
and development plans. We are very excited about <strong>the</strong> Company’s future and deeply appreciate our shareholders’ continued<br />
support. We look forward <strong>to</strong> <strong>report</strong>ing our progress and achievements <strong>to</strong> you in <strong>the</strong> months ahead.<br />
Sincerely,<br />
Phil E. Mulacek<br />
Chairman and Chief Executive Officer<br />
7
Upstream<br />
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<br />
acres, all of which were operated by us. PPLs 236, 237 and 238 and PRL 15 are located onshore in <strong>the</strong> Eastern Papuan<br />
Basin, northwest of Port Moresby.<br />
On November 30, 2010, we were granted PRL 15, covering a <strong>to</strong>tal of nine graticular blocks including and surrounding <strong>the</strong> Elk<br />
and Antelope fields and extracted from PPLs 237 and 238. This PRL unifies <strong>the</strong> Elk and Antelope fields in<strong>to</strong> a single license<br />
and separates <strong>the</strong> fields from our exploration acreage. The PRL has a separate minimum work program and expenditure<br />
commitment for <strong>the</strong> next five years.<br />
The following table summarizes our interests and on acreage currently held by <strong>InterOil</strong> as at December 31, 2011:<br />
License Numbers Basin Location Opera<strong>to</strong>r<br />
<strong>InterOil</strong> Registered<br />
License Interest<br />
Blocks Covered Acreage Gross Acreage Net<br />
PPL 236 Papuan Onshore <strong>InterOil</strong> 100.00% 53 1,112,464 1,112,464<br />
PPL 237 Papuan Onshore <strong>InterOil</strong> 100.00% 34 715,648 715,648<br />
PPL 238 Papuan Onshore <strong>InterOil</strong> 100.00% 94 1,978,565 1,978,565<br />
PRL 15 2 Papuan Onshore <strong>InterOil</strong> 100.00% 9 189,776 189,032<br />
Total 3,996,453 3,991,709<br />
1 See Petroleum License Details – Net Working Interest on PPL 236, PPL 237 and PPL 238<br />
1 An application <strong>to</strong> transfer 2.5% interest in PRL15 <strong>to</strong> Pac LNG pursuant <strong>to</strong> an agreement entered in<strong>to</strong> in 2009 was submitted <strong>to</strong> <strong>the</strong> PNG Department of<br />
Petroleum and Energy; and was approved in December 2011.<br />
Costs Incurred in Relation <strong>to</strong> Exploration and Development Activities<br />
The following table outlines costs incurred by <strong>InterOil</strong> during <strong>the</strong> year ended<br />
December 31, 2011 for acquisitions and capital expenditure associated with<br />
exploration and development activities.<br />
Nature of Cost<br />
Acquisition costs<br />
(Proved and Unproved):<br />
Exploration costs $18.4<br />
Amount<br />
(US $ Million)<br />
Development costs $107.6<br />
Additionally <strong>the</strong> following table summarizes <strong>the</strong> results of exploration and<br />
development activities on a gross and net basis (with net costs reflecting <strong>the</strong> cost <strong>to</strong><br />
Total $126.0<br />
us, not including <strong>the</strong> portion of costs met by IPI holders, PNGDV and/or Pac LNG), as fur<strong>the</strong>r broken down by well type,<br />
during <strong>the</strong> year ended December 31, 2011.<br />
Wells Development Exploration Total<br />
Gross<br />
(US $ Million)<br />
Net<br />
(US $ Million)<br />
Gross<br />
(US $ Million)<br />
Net<br />
(US $ Million)<br />
Gross<br />
(US $ Million)<br />
-<br />
Net<br />
(US $ Million)<br />
Gas $116.5 $107.6 $21.2 $18.4 $137.7 $126.0<br />
Oil - - - - - -<br />
Service - - - - - -<br />
Dry - - - - - -<br />
Total $116.5 $107.6 $21.2 $18.4 $137.7 $126.0<br />
During <strong>the</strong> year ended December 31, 2011, we have commenced <strong>the</strong> construction of certain infrastructure such as roads,<br />
wharves, warehouses and camps <strong>to</strong> support <strong>the</strong> proposed appraisal and development drilling in <strong>the</strong> Elk and Antelope gas<br />
fields. In addition, we also under<strong>to</strong>ok exploration activities in our three exploration licenses, PPL 236, PPL 237 and PPL 238.<br />
These exploration activities involved a regional airborne geophysical survey, various seismic surveys across a number of<br />
prospects and preparation for drilling of our next appraisal well, Tricera<strong>to</strong>ps 2, which was spudded in mid-January 2012. No<br />
wells were drilled during <strong>the</strong> year ended December 31, 2011. The preparation of <strong>the</strong> Tricera<strong>to</strong>ps 2 well site was <strong>complete</strong>d at<br />
<strong>the</strong> end of 2011 and <strong>the</strong> Tricera<strong>to</strong>ps 2 well was spudded on January 15, 2012. The Tricera<strong>to</strong>ps 2 well is an appraisal well <strong>to</strong><br />
test <strong>the</strong> presence of hydrocarbons and determine whe<strong>the</strong>r a potential reefal carbonate reservoir exists in <strong>the</strong> Tricera<strong>to</strong>ps field.<br />
Operated License Commitments, Terms, Expiry and Re-Application<br />
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<br />
term. The PPL license renewals require that we expend <strong>the</strong> amounts set out below and drill a <strong>to</strong>tal of 6 wells within those<br />
license areas during <strong>the</strong> renewed license term. The first 2 year term of <strong>the</strong> license anniversaries occurred in March 2011. On<br />
May 17, 2011, <strong>the</strong> State approved our request <strong>to</strong> extend all three licenses for <strong>the</strong> second two year term (years 3 and 4).<br />
In January 2011, we applied for a variation of license conditions on PPL 238 <strong>to</strong> defer <strong>the</strong> commitment <strong>to</strong> drill a well from first<br />
9
two year term <strong>to</strong> <strong>the</strong> second term which ends in March 2013. The State also approved this request on May 17, 2011.<br />
We have met all o<strong>the</strong>r commitments under our licenses as of December 31, 2011.<br />
Following are our applicable expenditure commitments for each PPL and PRL based on <strong>the</strong> approved renewals in March<br />
2009 and <strong>the</strong> PRL granted in November 2010:<br />
License License Issued for Second Term On Second Opera<strong>to</strong>r<br />
<strong>InterOil</strong> Registered<br />
License Interest<br />
Blocks Covered<br />
Acreage Gross<br />
PPL 236 March 27, 2009 5 years $5.0 $10.0 $15.0 March 27, 2014<br />
PPL 237 March 27, 2009 5 years $14.0 $34.0 $48.0 March 27, 2014<br />
PPL 238 March 6, 2009 5 years $2.0 $30.0 $32.0 March 6, 2014<br />
PRL15 November 30, 2010 15 years $53.0 $20.0 $73.0 November 30, 2025<br />
1 Commitment <strong>to</strong>tal is for <strong>the</strong> first 5 years only<br />
Totals $74.0 $94.0 $168.0<br />
Petroleum License Deals<br />
Net Working Interests in Licenses<br />
Our licenses are located onshore in <strong>the</strong> eastern Papuan Basin,<br />
northwest of Port Moresby and are largely owned by us,<br />
subject <strong>to</strong> inves<strong>to</strong>r elections <strong>to</strong> earn a working interest in<br />
certain discoveries pursuant <strong>to</strong> <strong>the</strong> terms of our various indirect<br />
participation interest agreements. All properties are currently<br />
operated by us. The State has <strong>the</strong> right under relevant PNG<br />
legislation <strong>to</strong> acquire a 22.5% interest (which includes 2% on<br />
behalf of landowners) in any PDL, by contributing its share of<br />
exploration and development costs. Pac LNG holds a 2.5%<br />
working interest in gas and condensate in <strong>the</strong> Elk and Antelope<br />
Participant Working Interests * With State Participation<br />
<strong>InterOil</strong> 75.6114% 58.5988%<br />
IPI holders 15.1386% 11.7324%<br />
PNGDV 6.75% 5.2312%<br />
Pac LNG 2.50% 1.9375%<br />
State<br />
Entitlement<br />
Landowners<br />
Entitlement<br />
0.00% 20.50%<br />
fields (which fields are located on PRL 15) under an agreement entered in<strong>to</strong> in 2009. The table below sets forth <strong>the</strong> working<br />
interest position in <strong>the</strong> Elk and Antelope fields, currently under PRL 15, in <strong>the</strong> event that <strong>the</strong> State, Pac LNG and indirect<br />
participation interest holders all exercise <strong>the</strong>ir rights <strong>to</strong> acquire <strong>the</strong>ir allocated interests in <strong>the</strong> Elk and Antelope discoveries.<br />
Petroleum Prospecting License 236<br />
0.00% 2.00%<br />
Total 100.00% 100.00%<br />
1 These interests assume all existing potential partners as at December<br />
31, 2011 elect <strong>to</strong> participate.<br />
We have a 100% working interest in PPL 236, subject <strong>to</strong> potential participation<br />
and elections made by holders of indirect participation interests and <strong>the</strong> State.<br />
The license consists of 53 graticular blocks covering an area of 4,502 square<br />
kilometres or 1,112,464 acres.<br />
PPL 236<br />
The following are <strong>the</strong> work commitments for PPL 236 for <strong>the</strong> subsequent 2 year<br />
term, ending in March 2013:<br />
•<br />
•<br />
•<br />
A minimum expenditure of $ 9.85 million;<br />
Drill an exploration well at a location acceptable <strong>to</strong> <strong>the</strong> State; and<br />
Complete a thorough petroleum system and basin study in PPL 236 <strong>to</strong><br />
determine <strong>the</strong> likely controls on <strong>the</strong> distribution and reservoir quality of<br />
<strong>the</strong> onshore Late Oligocene <strong>to</strong> Late Miocene shallow marine reefal and<br />
shelfal carbonate depositional systems, likely controls on <strong>the</strong> source rock<br />
quality and maturity and tec<strong>to</strong>nostratigraphic influences on <strong>the</strong> timing of<br />
<strong>the</strong> generation and expulsion of hydrocarbons, <strong>the</strong>ir migration, charge<br />
and preservation.<br />
Petroleum Prospecting License 237<br />
We have a 100% working interest in PPL 237, subject <strong>to</strong> potential participation and elections made<br />
by holders of indirect participation interests and <strong>the</strong> State. The license consists of 34 graticular blocks<br />
10
covering an area of 3,238 square kilometers or 715,648 acres. On November 30, 2010, a <strong>to</strong>tal of four graticular blocks were<br />
excised from PPL 237 and incorporated in<strong>to</strong> PRL 15.<br />
The following are <strong>the</strong> work commitments for PPL 237 for <strong>the</strong> two year term ending in March 2013:<br />
•<br />
•<br />
•<br />
Minimum expenditure of $10.0 million;<br />
Acquire, process and interpret new seismic data focused on selecting a drilling location; and<br />
Complete a thorough petroleum system and basin study <strong>to</strong> determine <strong>the</strong> likely controls on <strong>the</strong> distribution and<br />
reservoir quality of <strong>the</strong> onshore Late Oligocene <strong>to</strong> Late Miocene shallow marine reefal and shelfal<br />
carbonate depositional systems, likely controls on <strong>the</strong> source rock<br />
quality and maturity and tec<strong>to</strong>nostratigraphic influences on <strong>the</strong> timing of <strong>the</strong> generation and expulsion of hydrocarbons,<br />
<strong>the</strong>ir migration, charge and preservation.<br />
Petroleum Prospecting License 238<br />
We have a 100% working interest in PPL 238,<br />
subject <strong>to</strong> potential participation and elections<br />
made by holders of indirect participation<br />
interests and <strong>the</strong> State. The license consists of<br />
94 graticular blocks covering an area of 7,922<br />
square kilometers or 1,978,565 acres. On<br />
November 30, 2010, a <strong>to</strong>tal of five graticular<br />
blocks, including <strong>the</strong> blocks in which <strong>the</strong> Elk-1<br />
and Elk-4A gas /condensate discovery wells<br />
were drilled, were excised from PPL 238 and<br />
incorporated in<strong>to</strong> PRL 15.<br />
PPL 237<br />
PPL 238<br />
Following are <strong>the</strong> work commitments for PPL<br />
238 for <strong>the</strong> two year term ending in March<br />
2013:<br />
• Minimum expenditure of $ 10.0 million<br />
• Acquire, process and interpret new seismic data focused on selecting a<br />
drilling location;<br />
PPL 15<br />
• Complete thorough petroleum system and basin study <strong>to</strong> determine <strong>the</strong><br />
likely controls on <strong>the</strong> distribution and reservoir quality of <strong>the</strong> onshore Late<br />
Oligocene <strong>to</strong> Late Miocene shallow marine reefal and shelfal carbonate depositional<br />
systems, likely controls on <strong>the</strong> source rock quality and maturity and tec<strong>to</strong>nostratigraphic<br />
influences on <strong>the</strong> timing of <strong>the</strong> generation and expulsion of hydrocarbons, <strong>the</strong>ir migration,<br />
charge and preservation; and<br />
• Drill a well at a location acceptable <strong>to</strong> <strong>the</strong> State.<br />
Petroleum Retention License 15<br />
Petroleum retention licenses may be granted <strong>to</strong> licensees of PPLs in which petroleum fields or parts of petroleum fields have<br />
been discovered <strong>to</strong> permit time for <strong>the</strong> licensee <strong>to</strong> develop <strong>the</strong> means for commercialization of <strong>the</strong> gas discoveries. In August<br />
2009, we applied for a PRL over <strong>the</strong> declared location and on November 30, 2010, PRL 15 was granted by <strong>the</strong> State and<br />
was excised from of PPL 237 and PPL 238.<br />
At <strong>the</strong> end of 2011, we still held a 97.50% registered interest in PRL 15. However, this is subject <strong>to</strong> elections <strong>to</strong> be made by<br />
<strong>the</strong> State’s nominee <strong>to</strong> acquire a 22.5% interest on behalf of <strong>the</strong> State and landowners, <strong>to</strong> elections by holders of certain<br />
indirect participation interests, as set out in <strong>the</strong> table on <strong>the</strong> preceding page.<br />
The initial period of a petroleum retention license is for five years and fur<strong>the</strong>r extensions of two, five year terms may be granted<br />
at <strong>the</strong> discretion of <strong>the</strong> State.<br />
The <strong>to</strong>tal commitment over <strong>the</strong> first five year term amounts <strong>to</strong> $73.0 million. Following are <strong>the</strong> work commitments for PRL15<br />
for <strong>the</strong> first two years of this term, ending in November 2012.<br />
•<br />
•<br />
Drill 2 wells in <strong>the</strong> Elk and Antelope fields;<br />
Acquire, process and interpret 100 kilometers of two dimensional seismic acquisition and <strong>complete</strong> geoscience<br />
studies;<br />
11
•<br />
•<br />
•<br />
Conduct social mapping and social and economic impact studies;<br />
Conduct commercial and marketing studies; and<br />
Conduct surface and subsurface engineering studies<br />
•<br />
•<br />
•<br />
Static and dynamic reservoir modeling<br />
Base case depletion plan<br />
Surface facilities<br />
Petroleum Development License (“PDL”)<br />
In order <strong>to</strong> progress <strong>the</strong> proposed development and commercialization of <strong>the</strong> Elk and Antelope fields, we are required <strong>to</strong> apply<br />
for and obtain a PDL from <strong>the</strong> State. Assuming that a PDL is issued, it will replace PRL 15 and include <strong>the</strong> Elk and Antelope<br />
gas fields and additional acreage required for facilities and pipelines. We have commenced preparation of an application for a<br />
PDL.<br />
The application for a PDL is made <strong>to</strong> <strong>the</strong> Department of Petroleum and Energy and must be accompanied by detailed<br />
proposals for <strong>the</strong> construction, establishment and operation of all facilities and services for and incidental <strong>to</strong> <strong>the</strong> recovery,<br />
processing, s<strong>to</strong>rage and transportation of gas from <strong>the</strong> PDL area. In addition, certain agreements and approvals from <strong>the</strong><br />
State will need <strong>to</strong> be in place prior <strong>to</strong> <strong>the</strong> grant of <strong>the</strong> PDL including a gas agreement defining <strong>the</strong> fiscal regime applicable <strong>to</strong><br />
<strong>the</strong> development and providing for <strong>the</strong> State’s equity participation in <strong>the</strong> fields amongst o<strong>the</strong>r things. Environmental approvals<br />
will be necessary and we will also be obliged <strong>to</strong> submit comprehensive social mapping and landowner identifications studies<br />
of those cus<strong>to</strong>mary landowners within <strong>the</strong> PDL area. Ministerial recognition of landowner groups is cus<strong>to</strong>marily based on such<br />
<strong>report</strong>s.<br />
Upon application, <strong>the</strong> State will undertake a comprehensive review of <strong>the</strong> development proposals and any o<strong>the</strong>r incidental<br />
agreement or approval required before granting <strong>the</strong> PDL application. Following its review, <strong>the</strong> State shall take steps <strong>to</strong><br />
conduct a ‘forum’ as set out under <strong>the</strong> Oil and Gas Act. The forum requires that <strong>the</strong> State co-ordinate a meeting for all<br />
affected stakeholders including <strong>the</strong> provincial, local level governments and cus<strong>to</strong>mary landowners with a view <strong>to</strong>wards<br />
establishing a regime for <strong>the</strong> distribution of royalties and o<strong>the</strong>r benefits that will arise from <strong>the</strong> commercialization of <strong>the</strong> fields.<br />
Once all formalities are <strong>complete</strong>d and <strong>the</strong> State is satisfied, <strong>the</strong> Minister for Petroleum may grant <strong>the</strong> PDL. Should <strong>the</strong> PDL<br />
be issued, <strong>the</strong> acreage would be held subject <strong>to</strong>; (i) periodic review provided for in PNG’s Oil & Gas Act, and (ii) <strong>to</strong> <strong>the</strong> license<br />
holders continuing <strong>to</strong> meet commitments associated with <strong>the</strong> license grant.<br />
Participation Agreements<br />
In May 2003, we entered in<strong>to</strong> an indirect participation agreement with PNGDV which was amended in May 2006. Under this<br />
amended agreement, PNGDV has a 6.75% interest in eight exploration wells. We have drilled six of <strong>the</strong>se exploration wells <strong>to</strong><br />
date. PNGDV also has <strong>the</strong> right <strong>to</strong> participate in <strong>the</strong> next 16 wells that follow <strong>the</strong> first eight mentioned above up <strong>to</strong> an interest<br />
of 5.75% at a cost of $112,500 for each 1% per well (with higher amounts <strong>to</strong> be paid if <strong>the</strong> depth exceeds 3,500 meters and<br />
<strong>the</strong> cost exceeds $8,500,000).<br />
In February 2005, we entered in<strong>to</strong> an agreement with IPI holders pursuant <strong>to</strong> which <strong>the</strong> IPI holders paid us an aggregate<br />
of $125.0 million and we agreed <strong>to</strong> drill eight exploration wells in Papua New Guinea on PPLs 236, 237 and 238. We have<br />
drilled four of <strong>the</strong> eight wells <strong>to</strong> date. Following various buybacks and conversions, IPI holders currently hold interests <strong>to</strong>taling<br />
15.1386% of each of <strong>the</strong>se existing and future wells, including those in <strong>the</strong> Elk and Antelope fields.<br />
In addition, PNGEI has <strong>the</strong> right <strong>to</strong> participate up <strong>to</strong> a 4.25% interest in 16 wells commencing from exploration wells<br />
numbered 9 <strong>to</strong> 24. As at <strong>the</strong> end of December 31, 2011, we have drilled 6 exploration wells since inception of our exploration<br />
program within PPL 236, 237 and 238. In order <strong>to</strong> participate, PNGEI would be required <strong>to</strong> contribute for each exploration<br />
well; $112,500 per 1% plus actual costs over $1.0 million charged pro rata for each 1%.<br />
Pac LNG holds a 2.5% direct working interest in gas and condensate in <strong>the</strong> Elk and Antelope fields under an agreement<br />
entered in<strong>to</strong> in 2009.<br />
If a PDL is granted, inves<strong>to</strong>rs in our participation interest programs set out above have <strong>the</strong> right <strong>to</strong> become registered direct<br />
working interest owners by having <strong>the</strong>ir interest registered on <strong>the</strong> PDL. In order <strong>to</strong> maintain <strong>the</strong>ir right <strong>to</strong> earn revenues from<br />
<strong>the</strong> field, <strong>the</strong> inves<strong>to</strong>rs are required <strong>to</strong> continue <strong>to</strong> fund <strong>the</strong>ir share of ongoing appraisal drilling and all subsequent work which<br />
may be required <strong>to</strong> bring <strong>the</strong> field in<strong>to</strong> production.<br />
12
Midstream<br />
Refining and Liquefaction
Refining<br />
Produces refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea for <strong>the</strong> domestic market<br />
and for export.<br />
Our refinery is located across <strong>the</strong> harbor from Port Moresby, <strong>the</strong> capital city of Papua New Guinea. Our refinery is currently <strong>the</strong><br />
sole refiner of hydrocarbons located in Papua New Guinea.<br />
Jet fuel, diesel and gasoline are <strong>the</strong> primary products that we produce for <strong>the</strong> domestic market. The refining process also<br />
results in <strong>the</strong> production of two Naphtha grades and low sulfur waxy residue. To <strong>the</strong> extent that we do not convert <strong>the</strong><br />
Naphtha <strong>to</strong> gasoline, we export it <strong>to</strong> <strong>the</strong> local and Asian markets in two grades, light Naphtha and mixed Naphtha, which are<br />
predominately used as petrochemical feeds<strong>to</strong>ck. LSWR can be and is being sold as fuel for power generation domestically,<br />
local bunker fuel sales with <strong>the</strong> majority exported for use in o<strong>the</strong>r complex refineries as cracker feeds<strong>to</strong>ck or supply <strong>to</strong> o<strong>the</strong>r<br />
end users, including power genera<strong>to</strong>rs.<br />
Facilities and Major Subcontrac<strong>to</strong>rs<br />
Our refinery includes a jetty with two berths for loading and discharging vessels and a road<br />
tanker loading system (gantry). Our larger berth has deep water access of 56 feet (17 metres)<br />
and has been designed <strong>to</strong> accommodate crude and product tankers with capacity up <strong>to</strong><br />
130,000 dwt. Our smaller berth can accommodate ships with a capacity of up <strong>to</strong> 22,000 dwt.<br />
Our tank farm has <strong>the</strong> ability <strong>to</strong> s<strong>to</strong>re approximately 750,000 barrels of crude feeds<strong>to</strong>ck and<br />
approximately 1.1 million barrels of refined products. We have a reverse osmosis desalination<br />
unit that produces all of <strong>the</strong> water used by our refinery, camp and office facilities, power<br />
generation facilities that meet all of our electricity needs, and o<strong>the</strong>r site infrastructure and<br />
support facilities, including a labora<strong>to</strong>ry, a waste water treatment plant, staff accommodation<br />
and a fire station.<br />
Our refinery’s on-site labora<strong>to</strong>ry is accredited by National Association of Testing Authorities, Australia. The lab is staffed and<br />
operated by an internationally recognized independent inspection and testing company. All crude imports and finished<br />
products are tested and certified on-site <strong>to</strong> contractual specifications, while independent certification of quantities loaded and<br />
discharged at <strong>the</strong> refinery are also provided by <strong>the</strong> labora<strong>to</strong>ry.<br />
14
Crude Supply<br />
In December 2001, we entered in<strong>to</strong> an agreement with BP Singapore for <strong>the</strong> supply of crude<br />
feeds<strong>to</strong>ck <strong>to</strong> our refinery. Supply under <strong>the</strong> agreement commenced when our refinery began<br />
operations in June 2004 and continued for 5 years until June 2009. Since this time <strong>the</strong><br />
agreement has been renewed annually. BP Singapore is one of <strong>the</strong> largest marketers and<br />
shippers of crude oil in <strong>the</strong> Asia Pacific region. This contract provides us with a reliable<br />
mechanism <strong>to</strong> access and ship <strong>the</strong> majority of <strong>the</strong> regional crudes suitable for our refinery. We<br />
will continue <strong>to</strong> review this arrangement and o<strong>the</strong>r options for sources of feeds<strong>to</strong>ck supply<br />
for our refinery and have been successful in securing o<strong>the</strong>r crude supply agreements for<br />
specific regional crudes.<br />
Sales<br />
Papua New Guinea is our principal market for <strong>the</strong> products our refinery produces, o<strong>the</strong>r than<br />
Naphtha and LSWR. Under our 30 year agreement with <strong>the</strong> State, <strong>the</strong> State has agreed <strong>to</strong><br />
ensure that all domestic distribu<strong>to</strong>rs purchase <strong>the</strong>ir refined petroleum product needs from our<br />
refinery, (and from any o<strong>the</strong>r refinery which may be constructed in Papua New Guinea), at IPP.<br />
In general, <strong>the</strong> IPP is <strong>the</strong> price that would be paid in Papua New Guinea for a refined product<br />
that is being imported. In late 2007, <strong>the</strong> IPP was modified, most significantly by changing <strong>the</strong><br />
Singapore benchmark price from <strong>the</strong> ”Singapore Posted Prices” which was no longer being<br />
updated, <strong>to</strong> ”Mean of Platts Singapore” (”MOPS”) which is <strong>the</strong> current benchmark price for<br />
refined products in <strong>the</strong> region in which we operate. The Project Agreement governing our<br />
relationship with <strong>the</strong> State is yet <strong>to</strong> be formally amended <strong>to</strong> reflect <strong>the</strong> revised formula which has<br />
been in use for <strong>the</strong> last four years. (See “Material Contracts – Refinery Project Agreement”).<br />
The major export product from our refinery is <strong>the</strong> two grades of Naphtha. On January 1, 2010 a 12 month term agreement<br />
with Dalian Fujia Dahua Petrochemicals (“Dalian”), which operates a petrochemical plant in China, was entered in<strong>to</strong> providing<br />
for export sales of Naphtha. This contract has been renewed subsequently and <strong>the</strong> current term agreement with Dalian runs<br />
for an 18 month period from January 1, 2011 until June 30, 2012.<br />
Our refinery is fully certified <strong>to</strong> manufacture and market Jet A-1 fuel <strong>to</strong> international specifications and markets this product <strong>to</strong><br />
both domestic Papua New Guinea and overseas airlines.<br />
We were a net consumer of LPG until <strong>the</strong> conversion of <strong>the</strong> main process furnaces and commissioning of <strong>the</strong> Hyundai<br />
genera<strong>to</strong>rs which burn LSWR in 2006. With <strong>the</strong> installation of <strong>the</strong> LSWR firing genera<strong>to</strong>rs, heaters and boilers, plus improved<br />
facilities for recovering LPG from <strong>the</strong> reformer off-gas and increased percentages of sweet crudes containing LPG, we are<br />
now a net producer of LPG.<br />
Competition<br />
Due <strong>to</strong> <strong>the</strong>ir favorable properties, light sweet crudes from <strong>the</strong> Sou<strong>the</strong>ast Asian and Northwest Australian region are highly<br />
sought after by refiners for use as feeds<strong>to</strong>ck. Therefore, <strong>the</strong>re is significant competition <strong>to</strong> secure cargoes of <strong>the</strong>se crude<br />
types. Due <strong>to</strong> <strong>the</strong> limited supply of light sweet crudes and <strong>the</strong> strong competition, we are not always able <strong>to</strong> secure our first<br />
choice crudes for our refinery and are required <strong>to</strong> obtain alternate crudes that are available.<br />
We own <strong>the</strong> only refinery in Papua New Guinea. While not restricted under any agreement we have with <strong>the</strong> State, we do not<br />
envision any new entrants in<strong>to</strong> <strong>the</strong> refining business within Papua New Guinea under <strong>the</strong> current market conditions. However,<br />
domestic distribu<strong>to</strong>rs have not sourced all of <strong>the</strong>ir requirements from <strong>the</strong> refinery since 2009. Excess diesel, gasoline,<br />
Naphtha and LSWR that are exported are sold subject <strong>to</strong> prevailing commodity market conditions. Our geographical<br />
position and limited s<strong>to</strong>rage capacity inhibits our ability <strong>to</strong> compete with <strong>the</strong> regional refining center in Singapore for sales of<br />
large cargo sizes. However, <strong>the</strong>se same fac<strong>to</strong>rs may also provide competitive advantages if we expand our exports of refined<br />
products <strong>to</strong> <strong>the</strong> small and fragmented South Pacific markets.<br />
15
Cus<strong>to</strong>mers<br />
Domestically in Papua New Guinea we sell Jet A-1 fuel, diesel, gasoline and small parcels of LSWR <strong>to</strong> domestic distribu<strong>to</strong>rs.<br />
Our main domestic cus<strong>to</strong>mer is our downstream distribution business segment, however we also distribute fuel products <strong>to</strong><br />
Niugini Oil Company, Islands Petroleum and Exxon Mobil.<br />
Trading and Risk Management<br />
Our revenues are derived from <strong>the</strong> sale of refined petroleum products. Prices for refined products and crude feeds<strong>to</strong>ck are<br />
volatile and sometimes experience large fluctuations over short periods of time as a result of relatively small changes in<br />
supplies, wea<strong>the</strong>r conditions, economic conditions and government actions. Due <strong>to</strong> <strong>the</strong> nature of our business, <strong>the</strong>re is<br />
always a time difference between <strong>the</strong> purchase of a crude feeds<strong>to</strong>ck and its arrival at <strong>the</strong> refinery and <strong>the</strong> supply of finished<br />
products <strong>to</strong> cus<strong>to</strong>mers.<br />
Our refinery faces mainly two types of market risks:<br />
• Flat price (or timing) risk, which results from <strong>the</strong> time lag between crude purchases and product sales. Generally, we<br />
are required <strong>to</strong> purchase crude feeds<strong>to</strong>ck approximately one <strong>to</strong> two months in advance of processing, whereas <strong>the</strong><br />
domestic supply or export of finished products takes place after <strong>the</strong> crude feeds<strong>to</strong>ck is discharged and processed.<br />
This timing difference can lead <strong>to</strong> differences between <strong>the</strong> cost of our crude feeds<strong>to</strong>ck and <strong>the</strong> revenue from <strong>the</strong><br />
proceeds of <strong>the</strong> sale of products, due <strong>to</strong> <strong>the</strong> fluctuation in prices during <strong>the</strong> time period.<br />
• Crack spread (or margin) risk. Month <strong>to</strong> month changes of crack spreads, even when pricing of crude purchases and<br />
that of product sales fall in<strong>to</strong> <strong>the</strong> same month, can affect <strong>the</strong> profitability of our refinery.<br />
However, we can use various derivative instruments <strong>to</strong> assist us <strong>to</strong> reduce or hedge away <strong>the</strong> risks of changes in <strong>the</strong> relative<br />
prices of our crude feeds<strong>to</strong>ck and refined products. These derivatives, which can be used <strong>to</strong> manage our price risk, can<br />
effectively enable us <strong>to</strong> manage <strong>the</strong> refinery margin. At <strong>the</strong> same time, this means that if <strong>the</strong> difference between our sales price<br />
of <strong>the</strong> refined products and our acquisition price of crude feeds<strong>to</strong>ck expands or increases, <strong>the</strong>n <strong>the</strong> benefits are limited <strong>to</strong><br />
<strong>the</strong> margin range we have established.<br />
The derivative instruments which we generally use are over-<strong>the</strong>-counter swaps. Swap transactions are executed between<br />
<strong>the</strong> counterparties in <strong>the</strong> derivatives swaps market. It is commonplace among major refiners and trading companies in Asia<br />
Pacific <strong>to</strong> use derivative swaps as a <strong>to</strong>ol <strong>to</strong> hedge <strong>the</strong>ir price exposures and margins. Due <strong>to</strong> <strong>the</strong> wide usage of such<br />
derivative <strong>to</strong>ols in <strong>the</strong> Asia Pacific region, <strong>the</strong> swaps market generally provides sufficient liquidity for our hedging and risk<br />
management activities. The derivative swap instrument covers commodities or products such as jet, kerosene, diesel,<br />
Naphtha, and also crudes such as Dated Brent and Dubai. By using <strong>the</strong>se <strong>to</strong>ols, we actively engage in hedging activities <strong>to</strong><br />
manage margins.<br />
During 2011, we participated in a number of hedges <strong>to</strong> reduce our risks. To manage <strong>the</strong> flat price risks, we transferred crude<br />
purchases <strong>to</strong> <strong>the</strong> months of product sales by utilizing Dated Brent time spread; we also directly sold product swaps for <strong>the</strong><br />
months of product sales, such as selling MOPS naphtha swaps. To manage <strong>the</strong> crack spread risk, we sold crack spread<br />
swaps, such as MOPS naphtha vs. Dated Brent swaps and MOPS Gasoil 0.5% vs. Dated Brent swaps.<br />
Liquefaction<br />
We are developing, <strong>to</strong>ge<strong>the</strong>r with our partners, an LNG Project for <strong>the</strong> construction of liquefaction facilities now being<br />
designed <strong>to</strong> be built on <strong>the</strong> coast in <strong>the</strong> Gulf Province of PNG. The Gulf LNG Project is a staged project which we currently<br />
plan <strong>to</strong> build in 3 stages.<br />
Stage 1 - Start up production: Has an expected start up in 2015 of between 3 <strong>to</strong> 5 mtpa of LNG with a condensate<br />
stripping unit of 400 <strong>to</strong> 900 mmscf/d (subject <strong>to</strong> PNG approvals).<br />
Stage 2 – Expected Production: The LNG Project intends <strong>to</strong> target a <strong>to</strong>tal of 8 mtpa LNG production <strong>to</strong> follow, with a<br />
condensate stripping facility capacity of 1,350 mmscf/d capacity.<br />
Stage 3 – Potential Expansion Production: The potential final ramp up will be <strong>to</strong> 11 mtpa with condensate stripping<br />
facilities reaching 1,800 mmscf/d.<br />
16
We can provide no assurances that we will obtain <strong>the</strong> financing and approvals necessary <strong>to</strong> proceed with <strong>the</strong> LNG Project in<br />
this manner, or that we will have sufficient gas resources <strong>to</strong> support <strong>the</strong> potential expansion stage.<br />
O<strong>the</strong>r than <strong>the</strong> core liquefaction facilities, <strong>the</strong> infrastructure being contemplated includes wells, gas ga<strong>the</strong>ring pipelines,<br />
condensate stripping facilities, condensate s<strong>to</strong>rage, a condensate pipeline and export handling facilities, a dry gas pipeline<br />
from <strong>the</strong> Elk and Antelope fields and LNG s<strong>to</strong>rage and marine export terminal.<br />
Initial engineering design was undertaken in relation <strong>to</strong> <strong>the</strong> LNG Project and <strong>the</strong> regula<strong>to</strong>ry and taxation regime with <strong>the</strong> State<br />
was established with <strong>the</strong> execution on December 23, 2009 of <strong>the</strong> LNG Project Agreement. This agreement also provides for<br />
<strong>the</strong> participation by <strong>the</strong> State in <strong>the</strong> LNG Project, allowing it <strong>to</strong> take up <strong>to</strong> a 20.5% ownership stake. Affected landowners are<br />
able <strong>to</strong> take an additional 2% stake.<br />
During 2010, we and Pac LNG, decided <strong>to</strong> pursue <strong>the</strong> development of <strong>the</strong> LNG Project by exploring <strong>the</strong> use of a<br />
modular plant, able <strong>to</strong> be expanded incrementally from an initial position of 2 mtpa, and <strong>to</strong> explore locating this plant in <strong>the</strong><br />
Gulf Province ra<strong>the</strong>r than near our existing refinery outside of Port Moresby. Advantages perceived with this approach include<br />
<strong>the</strong> potential acceleration of first production and reduced operational risks.<br />
In line with this revised approach, certain initial conditional agreements have been entered in<strong>to</strong> with EWC for development of<br />
<strong>the</strong> LNG Project. Under <strong>the</strong> terms of <strong>the</strong>se agreements, <strong>the</strong> LNG Project is intended <strong>to</strong> be developed in two initial phases,<br />
with a 2 mtpa liquefaction module <strong>to</strong> be followed immediately by a 1 mtpa module expansion plant. In return for fully<br />
funding <strong>the</strong> construction of <strong>the</strong> liquefaction facilities, EWC is <strong>to</strong> be entitled <strong>to</strong> a fee of 14.5% of <strong>the</strong> proceeds from LNG<br />
revenue derived from <strong>the</strong>se facilities less agreed deductions, and subject <strong>to</strong> adjustments based on timing and execution for a<br />
15 year period. The agreements remain conditional and <strong>the</strong> parties may still elect not <strong>to</strong> proceed with <strong>the</strong> LNG Project on <strong>the</strong><br />
terms specified or at all.<br />
We are also exploring employment of a floating liquefaction vessel, <strong>to</strong> be constructed by FLEX LNG and Samsung Heavy<br />
Industries. The vessel would integrate with and augment <strong>the</strong> land-based modules proposed by EWC. FEED work, including<br />
work specific for <strong>the</strong> LNG Project has been carried out and commercial negotiations are being undertaken.<br />
Infrastructure required for <strong>the</strong> LNG Project includes a jetty and breakwater for <strong>the</strong> LNG loading facility with expansion<br />
potential, and approximately 70 miles (115 kilometers) of pipeline from <strong>the</strong> Elk and Antelope fields <strong>to</strong> <strong>the</strong> coast. The wells and<br />
processed natural gas pipeline from <strong>the</strong> CS Project <strong>to</strong> <strong>the</strong> coast in <strong>the</strong> Gulf Province will be <strong>the</strong> responsibility of <strong>the</strong> owners of<br />
<strong>the</strong> Elk and Antelope fields, including us and our upstream partners.<br />
Completion of <strong>the</strong> required LNG Project by us and our joint venture partners and related construction will take a number of<br />
years <strong>to</strong> <strong>complete</strong>. No assurances can be given that we will be able <strong>to</strong> construct <strong>the</strong> proposed LNG facilities or as <strong>to</strong> <strong>the</strong><br />
timing of such construction.<br />
At present, <strong>the</strong> LNG Project is being pursued by us in joint venture with Pac LNG. Our interests in <strong>the</strong> project are held through<br />
an incorporated joint venture entity, PNG LNG which in turn wholly owns those entities formed in Papua New Guinea <strong>to</strong><br />
pursue <strong>the</strong> LNG Project. We have equal voting rights in <strong>the</strong> entity but hold approximately 85% of <strong>the</strong> economic interest in it by<br />
means of <strong>the</strong> Class B shares we hold and under our shareholders agreement (see “Material Contracts – LNG Project<br />
Shareholders Agreement dated July 30, 2007”). It is intended that our interest will be reduced and Pac LNG’s and possibly<br />
o<strong>the</strong>r third party interest’s will increase as <strong>the</strong> LNG Project proceeds, and as Pac LNG and possibly o<strong>the</strong>rs make certain<br />
equalizing payments, whe<strong>the</strong>r in response <strong>to</strong> cash calls or as a result of sales of a strategic interest in <strong>the</strong> LNG Project.<br />
We are currently seeking an internationally recognized LNG operating and equity partner for <strong>the</strong> co-development of <strong>the</strong> LNG<br />
Project, which may include <strong>the</strong>ir acquisition of an interest in <strong>the</strong> Elk and Antelope fields.<br />
17
Downstream<br />
Wholesale and Retail Distribution
We have <strong>the</strong> largest wholesale and retail petroleum product distribution base in Papua New Guinea, after acquiring <strong>the</strong> fuel<br />
distribution assets of British Petroleum and Royal Dutch Shell several years ago. This business includes bulk s<strong>to</strong>rage,<br />
transportation distribution, aviation, wholesale and retail facilities for refined petroleum products. Our downstream business<br />
supplies petroleum products nationally in Papua New Guinea through a portfolio of retail service stations and commercial<br />
cus<strong>to</strong>mers.<br />
Sales<br />
The ICCC regulates <strong>the</strong> maximum prices and margins that may be charged by <strong>the</strong> wholesale and retail hydrocarbon<br />
distribution industry in Papua New Guinea. Margins were last reviewed by <strong>the</strong> ICCC in 2010 and will be fur<strong>the</strong>r reviewed in<br />
2014. We and our competi<strong>to</strong>rs may charge less than <strong>the</strong> maximum margin set by <strong>the</strong> ICCC in order <strong>to</strong> maintain<br />
competitiveness.<br />
Supply of Products<br />
Our retail and wholesale distribution business distributes diesel, jet fuel, avgas, gasoline,<br />
kerosene and fuel oil as well as branded commercial and industrial lubricants, such as engine<br />
and hydraulic oils. In general, all of <strong>the</strong> refined products sold pursuant <strong>to</strong> our wholesale and<br />
retail distribution business are purchased from our refinery. We import <strong>the</strong> commercial and<br />
industrial lubricants, avgas and fuel oil, which constitute a small percentage of our sales.<br />
We deliver refined products from our refinery <strong>to</strong> two tanker vessels we charter, which are<br />
operated by a separate corporate division. We do not own <strong>the</strong>se vessels but ra<strong>the</strong>r lease <strong>the</strong>m<br />
on a full time charter basis. We schedule all of our own movements and deliveries on our<br />
chartered vessels. Our inland depots are supplied by road tankers which are owned and operated by third party independent<br />
transport contrac<strong>to</strong>rs.<br />
Our terminal and depot network distributes refined petroleum products <strong>to</strong> retail service stations, aviation facilities and<br />
commercial cus<strong>to</strong>mers. We supply retail service stations and commercial cus<strong>to</strong>mers with petroleum products using trucks or,<br />
in <strong>the</strong> case of some commercial cus<strong>to</strong>mers, coastal ships. We do not own any of <strong>the</strong>se shipping or trucking distribution<br />
assets. We pass transportation costs through <strong>to</strong> our cus<strong>to</strong>mers.<br />
Retail Distribution<br />
We provide petroleum products <strong>to</strong> retail service stations, both operating under <strong>the</strong> <strong>InterOil</strong><br />
brand name and under independent brands. The service stations are ei<strong>the</strong>r owned by us,<br />
head leased <strong>to</strong> us with a sublease <strong>to</strong> company-approved opera<strong>to</strong>rs, or independently owned<br />
and operated. We supply products <strong>to</strong> each of <strong>the</strong>se service stations pursuant <strong>to</strong> distribution<br />
supply agreements. Under <strong>the</strong> cover of an equipment loan agreement, we also provide fuel<br />
pumps and related infrastructure <strong>to</strong> <strong>the</strong> opera<strong>to</strong>rs of many of <strong>the</strong>se retail service stations that<br />
are not owned or leased by us.<br />
Wholesale Distribution<br />
We supply petroleum products as a wholesaler <strong>to</strong> commercial clients and operate aviation refueling facilities throughout<br />
Papua New Guinea. We own and operate six large terminals and six depots that we use <strong>to</strong> supply product throughout Papua<br />
New Guinea. We enter in<strong>to</strong> commercial supply agreements with mining, agricultural, fishing, logging and similar commercial<br />
clients <strong>to</strong> supply <strong>the</strong>ir petroleum product needs. Pursuant <strong>to</strong> many of <strong>the</strong>se agreements, we supply and maintain company<br />
owned above-ground s<strong>to</strong>rage tanks and pumps that are used by <strong>the</strong>se cus<strong>to</strong>mers. More than two-thirds of <strong>the</strong> volume of<br />
petroleum products that we sold during 2011 was supplied <strong>to</strong> commercial cus<strong>to</strong>mers. Although <strong>the</strong> volume of sales <strong>to</strong><br />
commercial cus<strong>to</strong>mers is far larger than through our retail distribution network, <strong>the</strong>se product sales are at a lower margin due<br />
<strong>to</strong> <strong>the</strong> volume rebates offered <strong>to</strong> our larger cus<strong>to</strong>mers as a direct result of competition in this sec<strong>to</strong>r. Aviation cus<strong>to</strong>mers<br />
represented a significant proportion of our <strong>to</strong>tal business by volume.<br />
Competition<br />
Our main competi<strong>to</strong>r in <strong>the</strong> wholesale and retail distribution business in Papua New Guinea is ExxonMobil. We also compete<br />
with smaller local distribu<strong>to</strong>rs of petroleum products. With <strong>the</strong> decision of our competi<strong>to</strong>rs early in 2010 <strong>to</strong> partly import<br />
directly from overseas refineries and <strong>the</strong> consequent cessation of <strong>the</strong> joint industry shipping arrangements, it is difficult <strong>to</strong><br />
accurately gauge our market share. Our competi<strong>to</strong>rs source small quantities from our refinery from both <strong>the</strong> refinery gantry<br />
19
for <strong>the</strong> Port Moresby market and by tanker vessel for <strong>the</strong> markets outside Port Moresby. Our major competitive advantage is<br />
<strong>the</strong> large widespread distribution network we maintain with adequate s<strong>to</strong>rage capacity that services most areas of PNG. We<br />
also believe that our commitment <strong>to</strong> <strong>the</strong> distribution business in Papua New Guinea at a time when major-integrated oil and<br />
gas companies exited <strong>the</strong> Papua New Guinea fuel distribution market provides us with a competitive advantage. However,<br />
major-integrated oil and gas companies such as ExxonMobil have greater resources than we do and could if <strong>the</strong>y decided <strong>to</strong><br />
do so, expand much more rapidly in this market than we can.<br />
Major Cus<strong>to</strong>mers<br />
We sell approximately 15% of our refined petroleum products <strong>to</strong> a major mining project in<br />
Papua New Guinea pursuant <strong>to</strong> a wholesale distribution contract. These volumes were<br />
contracted with narrow margins in order <strong>to</strong> provide volumes for <strong>the</strong> Midstream Refinery<br />
operations and as such, <strong>the</strong> loss of this cus<strong>to</strong>mer, at least in <strong>the</strong> short term, would not<br />
adversely affect <strong>the</strong> profitability of our retail and wholesale distribution business. We entered<br />
in<strong>to</strong> an additional supply agreement with a major mine in January 2010 for a two plus two year<br />
period.<br />
During 2011, we sold approximately 10% of our refined petroleum products <strong>to</strong> Pacific Energy<br />
Aviation (PNG) Ltd for aviation refueling at Papua New Guinea’s international airport in Port Moresby.<br />
20
The Environment and Community Relations
Environmental Protection<br />
Our operations in Papua New Guinea are subject <strong>to</strong> an environmental law regime which includes laws concerning emissions<br />
of substances in<strong>to</strong>, and pollution and contamination of, <strong>the</strong> atmosphere, waters and land, production, use, handling, s<strong>to</strong>rage,<br />
transportation and disposal of waste, hazardous substances and dangerous goods, conservation of natural resources, <strong>the</strong><br />
protection of threatened and endangered flora and fauna and <strong>the</strong> health and safety of people.<br />
These environmental laws require that our sites be operated, maintained, abandoned and reclaimed <strong>to</strong> standards set out<br />
in <strong>the</strong> relevant legislation. The significant Papua New Guinea laws applicable <strong>to</strong> our operations include <strong>the</strong> Environment Act<br />
2000; <strong>the</strong> Oil and Gas Act 1998; <strong>the</strong> Dumping of Wastes at Sea Act (Ch. 369); <strong>the</strong> Conservation Areas Act (Ch.362); and <strong>the</strong><br />
International Trade (Flora and Fauna) Act (Ch.391).<br />
The Environment Act 2000 is <strong>the</strong> single most significant legislation affecting our operations. This regulates <strong>the</strong> environmental<br />
impact of development activities in order <strong>to</strong> promote sustainable development of <strong>the</strong> environment and <strong>the</strong> economic, social<br />
and physical well-being of people and imposes a duty <strong>to</strong> take all reasonable and practicable measures <strong>to</strong> prevent or minimize<br />
environmental harm. A breach of this Act can result in significant fines or penalties. Under <strong>the</strong> Compensation (Prohibition of<br />
Foreign Legal Proceedings) Act 1995, no legal proceedings for compensation claims arising from petroleum projects in Papua<br />
New Guinea may be taken up or pursued in any foreign court.<br />
Compliance with Papua New Guinea’s environmental legislation can require significant expenditures. The environmental<br />
legislation regime is complex and subject <strong>to</strong> different interpretations. Although no assurances can be made, we believe that,<br />
absent <strong>the</strong> occurrence of an extraordinary event, continued compliance with existing Papua New Guinea laws regulating <strong>the</strong><br />
release of materials in<strong>to</strong> <strong>the</strong> environment or o<strong>the</strong>rwise relating <strong>to</strong> <strong>the</strong> protection of <strong>the</strong> environment will not have a material<br />
effect upon our capital expenditures, earnings or competitive position with respect <strong>to</strong> our existing assets and operations, as<br />
has been <strong>the</strong> case during 2011. Future legislative action and regula<strong>to</strong>ry initiatives could result in changes <strong>to</strong> operating permits,<br />
additional remedial actions or increased capital expenditures and operating costs that cannot be assessed with certainty at<br />
this time.<br />
We have outstanding loans with OPIC, an agency of <strong>the</strong> United States Government supporting <strong>the</strong> development of our<br />
refinery. OPIC is required by statute <strong>to</strong> conduct an environmental assessment of every project proposed for financing and <strong>to</strong><br />
decline support for projects that, in OPIC’s judgment, would have an unreasonable or major adverse impact on <strong>the</strong><br />
environment, or on <strong>the</strong> health or safety of workers in <strong>the</strong> host country. For most industrial sec<strong>to</strong>rs, OPIC expects projects <strong>to</strong><br />
meet <strong>the</strong> more stringent of <strong>the</strong> World Bank or host-country environmental, health and safety standards. OPIC systematically<br />
moni<strong>to</strong>rs compliance with environmental representations and non-compliance may constitute a default under loan<br />
agreements.<br />
More stringent laws and regulations relating <strong>to</strong> climate change and greenhouse gases may be adopted in <strong>the</strong> future and could<br />
cause us <strong>to</strong> incur material expenses in complying with <strong>the</strong>m. Regula<strong>to</strong>ry initiatives could adversely affect <strong>the</strong> marketability of<br />
<strong>the</strong> refined products we produce and any oil and natural gas we may produce in <strong>the</strong> future. The impact of such future<br />
programs cannot be predicted.<br />
22
Environmental and Social Policies<br />
We have developed and implemented an environmental policy which acknowledges that <strong>the</strong> principles of sustainable<br />
development are integral <strong>to</strong> responsible resource management and will strive <strong>to</strong> minimize impacts on <strong>the</strong> physical<br />
environment. O<strong>the</strong>r environmental initiatives embrace <strong>the</strong> introduction of “Environmental Risk Analysis” for major projects in<br />
which hazards <strong>to</strong> <strong>the</strong> environment are identified, mitigating controls implemented and a “Hazard Register” developed <strong>to</strong><br />
moni<strong>to</strong>r any residual risks. We are also developing project specific “Environmental Management, Moni<strong>to</strong>ring & Reporting<br />
Plans”, in compliance with <strong>the</strong> PNG environmental legislation and in order <strong>to</strong> moni<strong>to</strong>r our ongoing compliance and<br />
performance, we have established corporate level controls in which all “near miss and real incidents” are <strong>report</strong>ed, and<br />
investigated.<br />
We have not adopted any specific social policies that are fundamental <strong>to</strong> our operations. However, we are committed <strong>to</strong><br />
working closely with <strong>the</strong> communities we operate in and <strong>to</strong> complying with all laws and governmental regulations applicable <strong>to</strong><br />
our activities, including maintaining a safe and healthy work environment and conducting our activities in full compliance with<br />
all applicable environmental laws.<br />
We have established a dedicated Community Relations department <strong>to</strong> oversee <strong>the</strong> management of community assistance<br />
programs and <strong>to</strong> manage land acquisition related compensation claims and payments. Our development philosophy is based<br />
on “bot<strong>to</strong>m-up planning” thus ensuring that all planning and development takes <strong>the</strong> local community in<strong>to</strong> account. In relation<br />
<strong>to</strong> our midstream refining business, <strong>the</strong> department has developed a long-term community development assistance program<br />
that benefits <strong>the</strong> villages in <strong>the</strong> vicinity of <strong>the</strong> refinery. In addition, we have a team of officers associated with our upstream<br />
business who operate in <strong>the</strong> field and perform a wide variety of tasks. These include land owner identification studies, social<br />
mapping management, local recruitment, liaising with landowners, recording compensation payments <strong>to</strong> land owners and<br />
assisting in <strong>the</strong> provision of health and medical services in <strong>the</strong> areas in which our exploration activities are conducted.<br />
Generally, <strong>the</strong> department works closely with government, landowners and <strong>the</strong> community in order <strong>to</strong> ensure that all our<br />
activities have a minimum environmental impact and <strong>to</strong> at least maintain, and generally improve, <strong>the</strong> quality of life of <strong>the</strong><br />
people inhabiting <strong>the</strong> areas in which we work.<br />
We are currently undertaking <strong>the</strong> work required under PNG’s Oil & Gas Act and Environment Act <strong>to</strong> support an application for<br />
a PDL for <strong>the</strong> Elk and Antelope gas fields and o<strong>the</strong>r related licenses which will be required for pipelines and processing<br />
facilities associated with our LNG Project. These studies cover social mapping, social economic impact statements, land<br />
investigations and o<strong>the</strong>r related base line studies. The environmental approval process is well advanced and we have<br />
engaged expert consultants <strong>to</strong> assist us with <strong>the</strong> preparation of a detailed environmental impact statement, a project<br />
environmental management plan, a fisheries assessment <strong>report</strong> and o<strong>the</strong>r baseline environmental studies. These studies are<br />
a pre-requisite <strong>to</strong> <strong>the</strong> grant of a PDL, allow us <strong>to</strong> advance <strong>the</strong> necessary planning <strong>to</strong> formulate our proposals as <strong>to</strong> <strong>the</strong> nature<br />
and distribution of project benefits, and will assist <strong>the</strong> State in convening a forum of all interested stakeholders at a landowner,<br />
local and provincial government level for <strong>the</strong> purpose of procuring a development agreement on benefit sharing.<br />
23
Management Discussion and Analysis
The following Management Discussion and Analysis (“MD&A”) should be read in conjunction with our audited annual<br />
consolidated financial statements and accompanying notes for <strong>the</strong> year ended December 31, 2011 and our annual<br />
information form (<strong>the</strong> “2011 Annual Information Form”) for <strong>the</strong> year ended December 31, 2011. The MD&A was<br />
prepared by management and provides a review of our performance in <strong>the</strong> year ended December 31, 2011, and of<br />
our financial condition and future prospects.<br />
Our financial statements and <strong>the</strong> financial information contained in this MD&A have been prepared in accordance with<br />
International Financial Reporting Standards (“IFRS”) as issued by <strong>the</strong> International Accounting Standards Board applicable <strong>to</strong><br />
<strong>the</strong> preparation of financial statements, including IFRS 1 – ‘First-time Adoption of International Financial Reporting Standards’,<br />
and are presented in United States dollars (“USD”) unless o<strong>the</strong>rwise specified. Our transition date <strong>to</strong> IFRS was January 1,<br />
2010. Financial information for 2010 included in this MD&A has been restated in accordance with IFRS. Financial information<br />
for 2009 included in this MD&A has been prepared in accordance with previous GAAP.<br />
References <strong>to</strong> “we,” “us,” “our,” “Company,” and “<strong>InterOil</strong>” refer <strong>to</strong> <strong>InterOil</strong> <strong>Corporation</strong> or <strong>InterOil</strong> <strong>Corporation</strong> and its<br />
subsidiaries as <strong>the</strong> context requires. Information presented in this MD&A is as at December 31, 2011 and for <strong>the</strong> quarter and<br />
year ended December 31, 2011, unless o<strong>the</strong>rwise specified. A listing of specific defined terms can be found in <strong>the</strong> “Glossary<br />
of Terms” section of this document.<br />
Forward-Looking Statements<br />
This MD&A contains “forward-looking statements” as defined in U.S. federal and Canadian securities laws. Such statements<br />
are generally identifiable by <strong>the</strong> terminology used such as “may,” “plans,” “believes,” “expects,” “anticipates,” “intends,”<br />
“estimates,” “forecasts,” “budgets,” “targets” or o<strong>the</strong>r similar wording suggesting future outcomes or statements regarding an<br />
outlook. We have based <strong>the</strong>se forward-looking statements on our current expectations and projections about future events.<br />
All statements, o<strong>the</strong>r than statements of his<strong>to</strong>rical fact, included in or incorporated by reference in this MD&A are<br />
forward-looking statements.<br />
Forward-looking statements include, without limitation, our business strategies and plans; plans for our exploration<br />
(including drilling plans) and o<strong>the</strong>r business activities and results <strong>the</strong>refrom; characteristics of our properties; entering in<strong>to</strong><br />
definitive agreements with our joint venture partners; <strong>the</strong> construction of proposed liquefaction facilities and condensate<br />
stripping facilities in Papua New Guinea; <strong>the</strong> development of such liquefaction and condensate stripping facilities; <strong>the</strong> timing<br />
and cost of such development; <strong>the</strong> commercialization and monetization of any resources; whe<strong>the</strong>r sufficient resources will be<br />
established; <strong>the</strong> likelihood of successful exploration for gas and gas condensate or o<strong>the</strong>r hydrocarbons; re-commissioning of<br />
our CRU; cash flows from operations; sources of capital and its sufficiency; operating costs; contingent liabilities;<br />
environmental matters; and plans and objectives for future operations; <strong>the</strong> timing, maturity and amount of future capital and<br />
o<strong>the</strong>r expenditures.<br />
Many risks and uncertainties may affect <strong>the</strong> matters addressed in <strong>the</strong>se forward-looking statements, including but not limited<br />
<strong>to</strong>:<br />
• our ability <strong>to</strong> finance <strong>the</strong> development of liquefaction<br />
and condensate stripping facilities;<br />
• our ability <strong>to</strong> negotiate definitive agreements<br />
following conditional agreements or heads of<br />
agreement relating <strong>to</strong> <strong>the</strong> development of liquefaction<br />
and condensate stripping facilities, or <strong>to</strong> o<strong>the</strong>rwise<br />
negotiate and secure arrangements with o<strong>the</strong>r entities<br />
for such development and <strong>the</strong> associated financing<br />
<strong>the</strong>reof;<br />
• <strong>the</strong> uncertainty associated with <strong>the</strong> availability, terms<br />
and deployment of capital;<br />
• our ability <strong>to</strong> construct and commission our<br />
liquefaction and condensate stripping facilities<br />
<strong>to</strong>ge<strong>the</strong>r with <strong>the</strong> construction of <strong>the</strong> common<br />
facilities and pipelines, on time and within budget;<br />
• our ability <strong>to</strong> obtain and maintain necessary permits,<br />
concessions, licenses and approvals from relevant<br />
PNG government authorities <strong>to</strong> develop our gas and<br />
condensate resources and <strong>to</strong> develop liquefaction<br />
and condensate stripping facilities within reasonable<br />
time periods and upon reasonable terms;<br />
• <strong>the</strong> inherent uncertainty of oil and gas exploration<br />
activities;<br />
• <strong>the</strong> availability of crude feeds<strong>to</strong>ck at economic rates;<br />
• <strong>the</strong> uncertainty associated with <strong>the</strong> regulated prices<br />
at which our products may be sold;<br />
• difficulties with <strong>the</strong> recruitment and retention of<br />
qualified personnel;<br />
• losses from our hedging activities;<br />
25
• fluctuations in currency exchange rates;<br />
• political, legal and economic risks in Papua New<br />
Guinea;<br />
• landowner claims and disruption;<br />
• compliance with and changes in Papua New Guinean<br />
laws and regulations, including environmental laws;<br />
• <strong>the</strong> inability of our refinery <strong>to</strong> operate at full capacity;<br />
• <strong>the</strong> impact of competition;<br />
• <strong>the</strong> adverse effects from importation of competing<br />
products contrary <strong>to</strong> our legal rights;<br />
• <strong>the</strong> margins for our products and adverse effects on<br />
<strong>the</strong> value of our refinery;<br />
• inherent limitations in all control systems, and<br />
misstatements due <strong>to</strong> errors that may occur and not<br />
be detected;<br />
• exposure <strong>to</strong> certain uninsured risks stemming from our<br />
operations;<br />
• contractual defaults;<br />
• interest rate risk;<br />
• wea<strong>the</strong>r conditions and unforeseen operating hazards;<br />
• general economic conditions, including any fur<strong>the</strong>r<br />
economic downturn, <strong>the</strong> availability of credit <strong>the</strong> European<br />
sovereign debt credit crisis and <strong>the</strong> downgrading of United<br />
States government debt;<br />
• <strong>the</strong> impact of our current debt on our ability <strong>to</strong> obtain<br />
fur<strong>the</strong>r financing;<br />
• risk of legal action against us and<br />
• law enforcement difficulties.<br />
Forward-looking statements and information are based on our current beliefs as well as assumptions made by, and<br />
information currently available <strong>to</strong>, us concerning anticipated financial conditions and performance, business prospects,<br />
strategies, regula<strong>to</strong>ry developments, <strong>the</strong> ability <strong>to</strong> attract joint venture partners, future hydrocarbon commodity prices, <strong>the</strong><br />
ability <strong>to</strong> secure adequate capital funding, <strong>the</strong> ability <strong>to</strong> obtain equipment in a timely manner <strong>to</strong> carry out development<br />
activities, <strong>the</strong> ability <strong>to</strong> market products successfully <strong>to</strong> current and new cus<strong>to</strong>mers, <strong>the</strong> effects from increasing competition,<br />
<strong>the</strong> ability <strong>to</strong> obtain financing on acceptable terms, and <strong>the</strong> ability <strong>to</strong> develop reserves and production through development<br />
and exploration activities. Although we consider <strong>the</strong>se assumptions <strong>to</strong> be reasonable based on information currently available<br />
<strong>to</strong> us, <strong>the</strong>y may prove <strong>to</strong> be incorrect.<br />
Although we believe that <strong>the</strong> assumptions underlying our forward-looking statements are reasonable, any of <strong>the</strong> assumptions<br />
could be inaccurate, and, <strong>the</strong>refore, we cannot assure you that <strong>the</strong> forward-looking statements will eventuate. In light of <strong>the</strong><br />
significant uncertainties inherent in our forward-looking statements, <strong>the</strong> inclusion of such information should not be regarded<br />
as a representation by us or any o<strong>the</strong>r person that our objectives and plans will be achieved. Some of <strong>the</strong>se and o<strong>the</strong>r risks<br />
and uncertainties that could cause actual results <strong>to</strong> differ materially from such forward-looking statements are more fully<br />
described under <strong>the</strong> heading “Risk Fac<strong>to</strong>rs” in our 2011 Annual Information Form.<br />
Fur<strong>the</strong>rmore, <strong>the</strong> forward-looking information contained in this MD&A is made as of <strong>the</strong> date hereof, unless o<strong>the</strong>rwise<br />
specified and, except as required by applicable law, we will not update publicly or <strong>to</strong> revise any of this forward-looking<br />
information. The forward-looking information contained in this <strong>report</strong> is expressly qualified by this cautionary statement.<br />
Oil and Gas Disclosures<br />
We are required <strong>to</strong> comply with Canadian Securities Administra<strong>to</strong>rs’ National Instrument 51-101 Standards for Disclosure<br />
of Oil and Gas Activities (“NI 51-101”), which prescribes disclosure of oil and gas reserves and resources. GLJ Petroleum<br />
Consultants Ltd., an independent qualified reserve evalua<strong>to</strong>r based in Calgary, Canada, has evaluated our resources data as<br />
at December 31, 2011 in accordance with NI 51-101, which evaluation is summarized in our 2011 Annual Information Form<br />
available at www.sedar.com. We do not have any production or reserves, including proved reserves, as defined under NI<br />
51-101 or as per <strong>the</strong> guidelines set by <strong>the</strong> United States Securities and Exchange Commission (“SEC”), as at December 31,<br />
2011.<br />
The SEC permits oil and gas companies, in <strong>the</strong>ir filings with <strong>the</strong> SEC, <strong>to</strong> disclose only proved, possible and probable reserves<br />
that a company has demonstrated by actual production or conclusive formation tests <strong>to</strong> be economically and legally<br />
producible under existing economic and operating conditions. We include in this MD&A information that <strong>the</strong> SEC’s guidelines<br />
generally prohibit U.S registrants from including in filings with <strong>the</strong> SEC.<br />
26
All calculations converting natural gas <strong>to</strong> crude oil equivalent have been made using a ratio of six thousand cubic feet of<br />
natural gas <strong>to</strong> one barrel of crude equivalent. Barrels of oil equivalent may be misleading, particularly if used in isolation. A<br />
barrel of oil equivalent conversion ratio of six thousand cubic feet of natural gas <strong>to</strong> one barrel of crude oil equivalent is based<br />
on an energy equivalency conversion method primarily applicable at <strong>the</strong> burner tip and does not represent a value equivalency<br />
at <strong>the</strong> wellhead.<br />
Resources<br />
We currently have no production or reserves as defined in NI 51-101 or under <strong>the</strong> definitions established by <strong>the</strong> United States<br />
Securities and Exchange Commission.<br />
The Elk and Antelope gas and gas condensate fields (see “Description of Our Business”), located in Papua New Guinea and<br />
contained within PRL 15, are reservoired in a composite trap comprising structural and stratigraphic elements consisting of<br />
a Late Oligocene <strong>to</strong> Late Miocene limes<strong>to</strong>ne and carbonate. The Elk field overlies <strong>the</strong> nor<strong>the</strong>rn end of <strong>the</strong> Antelope field and<br />
comprises a tec<strong>to</strong>nic wedge, or over thrust, of highly fractured deep water limes<strong>to</strong>ne and has been penetrated by <strong>the</strong> Elk-1<br />
and Elk-2 wells. The Antelope field has been penetrated by <strong>the</strong> Antelope-1 and Antelope-2 wells and <strong>the</strong> reservoir consists of<br />
a dominantly shallow water reef/platform complex with a dolomite cap with well developed secondary porosity and<br />
permeability.<br />
An evaluation of <strong>the</strong> resources of gas and condensate for <strong>the</strong> Elk and Antelope fields has been <strong>complete</strong>d by GLJ Petroleum<br />
Consultants Ltd. (“GLJ”), an independent qualified reserves evalua<strong>to</strong>r, as of December 31, 2011, and was prepared in<br />
accordance with <strong>the</strong> definitions and guidelines in <strong>the</strong> COGE Handbook and NI 51-101. All resources estimated for <strong>the</strong> Elk and<br />
Antelope fields are classified as contingent resources – economic status undetermined as follows:<br />
Gross Contingent Resources Estimate for Gas and Condensate*<br />
As at December 31, 2011<br />
Case<br />
Low Best High<br />
Initial Recoverable Sales Gas (tcf) 6.47 8.59 10.44<br />
Initial Recoverable Condensate (mmbbls) 105.3 128.9 151.4<br />
Initial Recoverable (mmboe) 1,183.6 1,560.4 1, 891.1<br />
* These estimates represent 100% of <strong>the</strong> Elk and Antelope fields. <strong>InterOil</strong> currently has a 97.5% working interest in <strong>the</strong> Elk and Antelope fields.<br />
Contingent Resource Estimate for Gas and Condensate – Net <strong>to</strong> <strong>InterOil</strong>*<br />
As at December 31, 2011<br />
Case<br />
Low Best High<br />
Initial Recoverable Sales Gas (tcf) 3.79 5.03 6.12<br />
Initial Recoverable Condensate (mmbbls) 61.7 75.5 88.7<br />
Initial Recoverable (mmboe) 693.6 914.4 1,108.1<br />
* These estimates are based upon <strong>InterOil</strong> holding a 58.5988% working interest in <strong>the</strong> Elk and Antelope fields, which assumes that: (i) <strong>the</strong> State and landowners<br />
elect <strong>to</strong> participate in <strong>the</strong> Elk and Antelope fields <strong>to</strong> <strong>the</strong> full extent provided under applicable PNG oil and gas legislation after a PDL has been granted in relation<br />
<strong>to</strong> <strong>the</strong> Elk/Antelope field and (ii) all elections are made <strong>to</strong> participate in <strong>the</strong> Field by all inves<strong>to</strong>rs pursuant <strong>to</strong> relevant indirect participation interest agreements with<br />
<strong>InterOil</strong>, including <strong>to</strong> participate fully and directly in <strong>the</strong> PDL.<br />
Contingent resources are those quantities of natural gas and condensate estimated, as of a given date, <strong>to</strong> be potentially<br />
recoverable from known accumulations using established technology or technology under development, but which are not<br />
currently considered <strong>to</strong> be commercially recoverable due <strong>to</strong> one or more contingencies. The economic status of <strong>the</strong><br />
resources is undetermined and <strong>the</strong>re is no certainty that it will be commercially viable <strong>to</strong> produce any portion of<br />
<strong>the</strong> resources. The following contingencies must be met before <strong>the</strong> resources can be classified as reserves:<br />
• Sanctioning of <strong>the</strong> facilities required <strong>to</strong> process and<br />
transport marketable natural gas <strong>to</strong> market.<br />
• Determination of economic viability.<br />
• Confirmation of a market for <strong>the</strong> marketable natural<br />
gas and condensate.<br />
27
Although a final project has not yet been sanctioned, pre-FEED studies are ongoing for <strong>the</strong> LNG Project and FEED studies<br />
conducted for <strong>the</strong> CS Project as options for potential monetization of <strong>the</strong> gas and condensate.<br />
The “low” estimate is considered <strong>to</strong> be a conservative estimate of <strong>the</strong> quantity that will actually be recovered. It is likely that<br />
<strong>the</strong> actual remaining quantities recovered will exceed <strong>the</strong> low estimate. With <strong>the</strong> probabilistic methods used, <strong>the</strong>re should be<br />
at least a 90 percent probability (P90) that <strong>the</strong> quantities actually recovered will equal or exceed <strong>the</strong> low estimate. The “best”<br />
estimate is considered <strong>to</strong> be <strong>the</strong> best estimate of <strong>the</strong> quantity that will actually be recovered. It is equally likely that <strong>the</strong><br />
actual remaining quantities recovered will be greater or less than <strong>the</strong> best estimate. With <strong>the</strong> probabilistic methods used, <strong>the</strong>re<br />
should be at least a 50 percent probability (P50) that <strong>the</strong> quantities actually recovered will equal or exceed <strong>the</strong> best estimate.<br />
The “high” estimate is considered <strong>to</strong> be an optimistic estimate of <strong>the</strong> quantity that will actually be recovered. It is unlikely that<br />
<strong>the</strong> actual remaining quantities recovered will exceed <strong>the</strong> high estimate. With <strong>the</strong> probabilistic methods used, <strong>the</strong>re should be<br />
at least a 10 percent probability (P10) that <strong>the</strong> quantities actually recovered will equal or exceed <strong>the</strong> high estimate.<br />
The accuracy of resource estimates are in part a function of <strong>the</strong> quality and quantity of <strong>the</strong> available data and of engineering<br />
and geological interpretation and judgment. O<strong>the</strong>r fac<strong>to</strong>rs in <strong>the</strong> classification as a resource include a requirement for more<br />
delineation wells, detailed design estimates and near term development plans. The size of <strong>the</strong> resource estimate could be<br />
positively impacted, potentially in a material amount, if additional delineation wells determined that <strong>the</strong> aerial extent, reservoir<br />
quality and/or <strong>the</strong> thickness of <strong>the</strong> reservoir is larger than what is currently estimated based on <strong>the</strong> interpretation of <strong>the</strong><br />
seismic and well data. The size of <strong>the</strong> resource estimate could be negatively impacted, potentially in a material amount, if<br />
additional delineation wells determined that <strong>the</strong> aerial extent, reservoir quality and/or <strong>the</strong> thickness of <strong>the</strong> reservoir are less<br />
than what is currently estimated based on <strong>the</strong> interpretation of <strong>the</strong> seismic and well data.<br />
Introduction<br />
We are developing a fully integrated energy company operating in Papua New Guinea and <strong>the</strong> surrounding Southwest Pacific<br />
region. Our operations are organized in<strong>to</strong> four major segments:<br />
Segments<br />
Upstream<br />
Midstream<br />
Downstream<br />
Corporate<br />
Operations<br />
Exploration and Production – Explores, appraises and develops crude oil and natural gas structures in Papua<br />
New Guinea. Currently developing infrastructure for <strong>the</strong> Elk and Antelope fields which includes condensate<br />
stripping and associated facilities, and <strong>the</strong> gas ga<strong>the</strong>ring and associated facilities, in connection with<br />
commercializing gas discoveries. This segment also manages our construction business which services <strong>the</strong><br />
development projects underway in Papua New Guinea.<br />
Refining – Produces refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea for <strong>the</strong><br />
domestic market and for export.<br />
Liquefaction – The LNG Project. Developing liquefaction and associated facilities in Papua New Guinea for <strong>the</strong><br />
export of LNG.<br />
Wholesale and Retail Distribution - Markets and distributes refined products domestically in Papua New<br />
Guinea on a wholesale and retail basis.<br />
Provides support <strong>to</strong> <strong>the</strong> o<strong>the</strong>r business segments by engaging in business development and improvement<br />
activities and providing general and administrative services and management, undertakes financing and<br />
treasury activities, and is responsible for government and inves<strong>to</strong>r relations. General and administrative and<br />
integrated costs are recovered from business segments on an equitable basis. This segment also manages our<br />
shipping business which currently operates two vessels transporting petroleum products for our<br />
Downstream segment and external cus<strong>to</strong>mers, both within PNG and for export in <strong>the</strong> South Pacific region. Our<br />
corporate segment results also include consolidation adjustments.<br />
Business Strategy<br />
Our strategy is <strong>to</strong> develop a vertically integrated energy company in Papua New Guinea and <strong>the</strong> surrounding region, focusing<br />
on niche market opportunities which provide financial rewards for our shareholders, while being environmentally responsible,<br />
providing a quality working environment and contributing positively <strong>to</strong> <strong>the</strong> communities in which we operate. A significant<br />
current element of that strategy is <strong>to</strong> develop gas liquefaction and condensate stripping facilities in Papua New Guinea and <strong>to</strong><br />
establish gas and gas condensate reserves. <strong>InterOil</strong> plans <strong>to</strong> achieve this strategy by:<br />
•<br />
•<br />
•<br />
Developing our position as a prudent and responsible<br />
business opera<strong>to</strong>r;<br />
Maximizing <strong>the</strong> value of our exploration assets;<br />
Monetizing our discovered resources;<br />
• Enhancing our existing refining and distribution<br />
businesses; and<br />
• Positioning for long term success.<br />
Fur<strong>the</strong>r details of our business strategy can be found under <strong>the</strong> heading “Business Strategy” in our 2011 Annual<br />
Information Form available at www.sedar.com.<br />
28
Operational Highlights<br />
A summary of <strong>the</strong> key operational matters and events for <strong>the</strong> year, for each of <strong>the</strong> segments is as follows:<br />
Upstream<br />
• The PPL 236 phase 1 explora<strong>to</strong>ry seismic data acquisition program, which included 70 kilometers with six dip lines<br />
transecting <strong>the</strong> Whale, Tuna, Barracuda, Wahoo, Mako and Shark prospects, was <strong>complete</strong>d during <strong>the</strong> first quarter<br />
of 2011. Processing and interpretation of this first phase of seismic data has been <strong>complete</strong>d, and <strong>the</strong> Wahoo/Mako<br />
leads (PPL 236) and <strong>the</strong> Tuna lead (PPL 236 and PPL 238) have been selected for follow up. Subsequently <strong>the</strong><br />
Kwalaha seismic data acquisition program was activated consisting of 56 kilometres and seven dip lines. Work<br />
commenced on September 16, 2011 and was <strong>complete</strong>d on December 20, 2011. The objective of <strong>the</strong> survey was <strong>to</strong><br />
fur<strong>the</strong>r delineate <strong>the</strong> Wahoo and Mako prospects and identify potential drilling locations. Processing and<br />
interpretation of <strong>the</strong> data is ongoing. A third phase of seismic data acquisition, which consists of two dip orientated<br />
lines <strong>to</strong>taling 21 kilometres in length over <strong>the</strong> Tuna prospect, commenced on December 22, 2011. Line preparation is<br />
currently in progress.<br />
• The PPL 237 phase 3 Tricera<strong>to</strong>ps seismic acquisition program, which included four lines for a <strong>to</strong>tal of 50 kilometres,<br />
was acquired between April and August 2011. This program increased our <strong>to</strong>tal seismic data acquisition over <strong>the</strong> area<br />
<strong>to</strong> 140 kilometers in eleven lines. The objective of <strong>the</strong> program was <strong>to</strong> investigate <strong>the</strong> structure, seismic character, and<br />
<strong>the</strong> aerial closure of <strong>the</strong> Tricera<strong>to</strong>ps field. Following <strong>the</strong> interpretation of <strong>the</strong> new seismic data, a review of <strong>the</strong> field was<br />
<strong>complete</strong>d and <strong>the</strong> conclusion reached that both <strong>the</strong> Bwata-1 and Tricera<strong>to</strong>ps-1 wells lay in <strong>the</strong> same zone, <strong>the</strong> same<br />
pool and <strong>the</strong> same field. Subsequently, <strong>the</strong> field was renamed <strong>the</strong> Tricera<strong>to</strong>ps field. Following <strong>the</strong> mapping of <strong>the</strong><br />
seismic <strong>the</strong>re has also been a review and increase in what we believe is <strong>the</strong> prospective size of <strong>the</strong> Tricera<strong>to</strong>ps field.<br />
This potential increase is due <strong>to</strong> increased size of <strong>the</strong> closure and <strong>the</strong> identification of several potential shallow marine<br />
reefal carbonate build ups.<br />
• The preparation of <strong>the</strong> Tricera<strong>to</strong>ps 2 well site was <strong>complete</strong>d at <strong>the</strong> end of 2011 and <strong>the</strong> Tricera<strong>to</strong>ps 2 well was<br />
spudded on January 15, 2012. The Tricera<strong>to</strong>ps 2 well is an appraisal well <strong>to</strong> test <strong>the</strong> presence of hydrocarbons and<br />
determine whe<strong>the</strong>r a potential reefal carbonate reservoir exists in <strong>the</strong> Tricera<strong>to</strong>ps field.<br />
• During 2011, we contracted for airborne magnetic, gravity and gamma ray prospecting over PPL 236, PPL 237 and<br />
PPL 238. Five acquisition blocks were acquired for a <strong>to</strong>tal of 14,288 line kilometers of airborne data. Data processing<br />
over this airborne data is currently undergoing final quality control assessment.<br />
• During 2011, <strong>the</strong> FEED work was carried out on Condensate Stripping Project. The FEED phase generated<br />
deliverables <strong>to</strong> technically and commercially define <strong>the</strong> project and prepare it for execution (detailed engineering,<br />
procurement, construction, fabrication, commissioning, and hand-over <strong>to</strong> operations) and proposals were solicited<br />
from potential Engineering, Procurement and Construction (“EPC”) contrac<strong>to</strong>rs. We are continuing <strong>the</strong> planning and<br />
preparation efforts for Condensate Stripping Project execution which includes preparing a detailed project execution<br />
plan, execution schedule and risk assessment work. At <strong>the</strong> end of 2011, agreement was reached with Mitsui <strong>to</strong> extend<br />
<strong>the</strong> target date for FID on <strong>the</strong> CSP Project until March 31, 2012, which has been extended from <strong>the</strong> previously<br />
disclosed targeted date of December 31, 2011 <strong>to</strong> be realigned with <strong>the</strong> targeted FID dates for our LNG Project.<br />
• In June 2011, our Board of Direc<strong>to</strong>rs approved capital expenditures on certain critical steel infrastructure ahead of FID<br />
on our LNG Project in order <strong>to</strong> help preserve <strong>the</strong> proposed schedule and take advantage of advantageous steel<br />
pricing. Total expenditure of up <strong>to</strong> $100.0 million was authorized for condensate and processed gas line pipe, and<br />
o<strong>the</strong>r required items with long lead times.<br />
• At <strong>the</strong> end of 2011, we agreed with Petromin that <strong>the</strong> Investment Agreement we entered in<strong>to</strong> in 2008 was no longer<br />
valid or intended <strong>to</strong> operate and should terminate. The agreement provided for Petromin <strong>to</strong> take a direct interest in <strong>the</strong><br />
Elk and Antelope fields and fund 20.5% of <strong>the</strong> costs of <strong>the</strong>ir development, if certain conditions were met. Petromin<br />
remains <strong>the</strong> State’s nominee <strong>to</strong> acquire this interest under relevant Papua New Guinean’s legislation, once a PDL is<br />
granted. We have proposed <strong>to</strong> Petromin that cash contributions made by Petromin under <strong>the</strong> Agreement <strong>to</strong> fund<br />
development, amounting <strong>to</strong> approximately $15.4 million, be held and credited against <strong>the</strong> State’s obligation <strong>to</strong> refund<br />
its portion of such costs upon grant of <strong>the</strong> PDL.<br />
Midstream – Refining<br />
• Total refinery throughput for <strong>the</strong> year ended December 31, 2011, was 24,856 barrels per operating day, compared with<br />
29
24,682 barrels per operating day during 2010.<br />
• Capacity utilization of <strong>the</strong> refinery for 2011, based on 36,500 barrels per day operating capacity, was 54% compared<br />
with 53% in 2010. During <strong>the</strong> years ended December 31, 2011 and 2010, our refinery was shut down for 82 days and<br />
81 days respectively.<br />
• The catalytic reformer unit (“CRU”), which allows <strong>the</strong> refinery <strong>to</strong> produce reformate for gasoline, remained shut down<br />
through <strong>the</strong> year due <strong>to</strong> technical operating issues. As a result, we were required <strong>to</strong> import unleaded gasoline <strong>to</strong> satisfy<br />
PNG’s domestic needs. It is anticipated that <strong>the</strong> CRU will be re-commissioned and returned <strong>to</strong> service during 2012,<br />
upon <strong>the</strong> successful conclusion of major maintenance and catalyst regeneration.<br />
• During <strong>the</strong> year, a decommissioning provision of $4.1 million relating <strong>to</strong> <strong>the</strong> future retirement obligations associated with<br />
<strong>the</strong> refinery was initially recognized. This decommissioning provision represents <strong>the</strong> net present value of <strong>the</strong> estimated<br />
costs of future dismantlement, site res<strong>to</strong>ration and abandonment of properties based upon regulations and economic<br />
circumstances. This provision balance as at December 31, 2011 was $4.6 million.<br />
• In June 2011, OPIC signed agreements agreeing <strong>to</strong> release all of <strong>the</strong> sponsor support collateral and requirements for<br />
<strong>the</strong> loan granted <strong>to</strong> us in 2001 in recognition of our financial and operational maturity.<br />
• On May 23, 2011, <strong>the</strong> BNP Paribas working capital facility agreement was amended <strong>to</strong> allow a $10.0 million increase<br />
in <strong>the</strong> facility limit. Total facility limit s<strong>to</strong>od at $230.0 million subsequent <strong>to</strong> its amendment. In November 2011, our<br />
Midstream working capital facility with BNP Paribas was increased temporarily by $30.0 million <strong>to</strong> $260.0 million till<br />
January 31, 2012, and reverting back <strong>to</strong> $230.0 million on that date. Subsequent <strong>to</strong> <strong>the</strong> year end, <strong>the</strong> facility has been<br />
extended and fur<strong>the</strong>r amended in February 2012 with <strong>the</strong> allowance of a fur<strong>the</strong>r $10.0 million increase in <strong>the</strong> facility limit<br />
<strong>to</strong> $240.0 million until January 31, 2013.<br />
Midstream – Liquefaction<br />
• On February 2, 2011, we signed a Project Funding and Construction Agreement and Shareholder Agreement with<br />
Energy World <strong>Corporation</strong> Limited (“EWC”) governing <strong>the</strong> parameters in respect of <strong>the</strong> development, construction,<br />
financing and operation of <strong>the</strong> planned 3 mtpa land based modular LNG plant in <strong>the</strong> Gulf Province of Papua New<br />
Guinea. The agreements with EWC, as amended, contemplate <strong>the</strong> negotiation of fur<strong>the</strong>r definitive agreements and are<br />
conditional on reaching FID <strong>to</strong> proceed with <strong>the</strong> LNG plant no later than March 31, 2012.<br />
• On April 11, 2011, we and Pac LNG entered in<strong>to</strong> certain conditional framework agreements with FLEX LNG and<br />
Samsung Heavy Industries for <strong>the</strong> proposed construction of a 1.8 mtpa or 2 mtpa fixed-floating liquefied natural gas<br />
vessel. The framework agreements provided that <strong>the</strong> parties were <strong>to</strong> undertake project specific FEED work and<br />
negotiate final binding agreements in time for a FID decision in mid-December 2011. Project specific FEED work was<br />
carried out. However, as FID was not reached by mid-December 2011, <strong>the</strong>se framework agreements with FLEX LNG<br />
and Samsung lapsed and were not extended. We are continuing <strong>to</strong> negotiate with FLEX LNG. Under <strong>the</strong> framework<br />
agreement we entered in<strong>to</strong> with FLEX LNG, an equity purchase option was granted <strong>to</strong> us <strong>to</strong> acquire common shares<br />
in FLEX LNG at an average strike price of 4.5909 Norwegian Kroner. On May 16, 2011, this option was exercised, with<br />
our acquisition of 8,938,913 common shares of FLEX LNG at a cost of $7.5 million.<br />
• During <strong>the</strong> year, site-specific engineering for <strong>the</strong> land based modular LNG and fixed-floating LNG facilities were<br />
undertaken along with o<strong>the</strong>r pre-investment in <strong>the</strong> LNG Project <strong>to</strong> lower bidder risks and <strong>to</strong> secure our LNG Project<br />
timeline and costs.<br />
• On August 1, 2011, Rt. Hon Sir Rabbie Namaliu, former Prime Minister and former Petroleum and Energy Minister of<br />
Papua New Guinea, joined us <strong>to</strong> chair our PNG Advisory Board. The PNG Advisory Board is a management group<br />
formed <strong>to</strong> assist us in discussions with government departments in developing <strong>the</strong> LNG Project.<br />
• On August 3, 2011, we signed a Heads of Agreement with Noble Clean Fuels Limited, a wholly owned subsidiary of<br />
Noble Group Limited, for <strong>the</strong> supply of one mtpa of LNG per annum from <strong>the</strong> LNG Project for a ten year period<br />
beginning in 2014. Definitive, binding agreements are currently being negotiated.<br />
• The PNG government’s Minister for Petroleum and Energy and <strong>the</strong> Secretary of his department issued certain press<br />
releases and correspondence during 2011 asserting that our development of <strong>the</strong> LNG Project may not, were it <strong>to</strong><br />
continue without amendment <strong>to</strong> its current form, be in compliance with <strong>the</strong> terms of <strong>the</strong> LNG Project Agreement signed<br />
with <strong>the</strong> State in December 2009, and would not be approved by <strong>the</strong> State. We have provided appropriate assurances<br />
<strong>to</strong> <strong>the</strong> PNG government in relation <strong>to</strong> <strong>the</strong> development of this Project and are continuing <strong>to</strong> work with <strong>the</strong> PNG<br />
30
government and its relevant departments in relation <strong>to</strong> our development plans for <strong>the</strong> Elk and Antelope fields and <strong>the</strong><br />
LNG Project. Additionally, <strong>the</strong> constitution of <strong>the</strong> PNG government became a matter of dispute during 2011 and<br />
remains so. National elections are due <strong>to</strong> take place in mid-2012.<br />
• In September 2011, we retained Morgan Stanley & Co.LLC, Macquarie Capital (USA) Inc. and UBS AG as joint financial<br />
advisors <strong>to</strong> assist us with soliciting and evaluating proposals from potential strategic partners. We anticipate that <strong>the</strong>se<br />
proposals will relate <strong>to</strong> obtaining an internationally recognized LNG operating and equity partner for development of <strong>the</strong><br />
LNG Project’s gas liquefaction and associated facilities in <strong>the</strong> Gulf Province of Papua New Guinea, and may include a<br />
sale of an interest in <strong>the</strong> Elk and Antelope fields, and in our o<strong>the</strong>r exploration tenements in Papua New Guinea. No<br />
assurances can be given that we will be able <strong>to</strong> attract strategic partners on terms acceptable <strong>to</strong> us, how such an<br />
agreement will affect our current LNG Project plans or whe<strong>the</strong>r such a partner will be acceptable <strong>to</strong> <strong>the</strong> PNG<br />
government.<br />
• On November 25, 2011, a Heads of Agreement was signed with Gunvor Singapore Pte. Ltd. for <strong>the</strong> supply of one<br />
mtpa of LNG from <strong>the</strong> LNG Project in Papua New Guinea. Definitive binding agreements are currently being<br />
negotiated.<br />
• On December 2, 2011, a fur<strong>the</strong>r Heads of Agreement was signed with ENN Energy Trading Company Ltd of China, for<br />
<strong>the</strong> supply of one <strong>to</strong> one and one half mtpa of LNG from <strong>the</strong> LNG Project. The Heads of Agreement, while not binding,<br />
provides exclusivity on <strong>the</strong> LNG volumes, during negotiation of <strong>the</strong> definitive agreement, and set out <strong>the</strong> basis upon<br />
which <strong>the</strong> parties intend <strong>to</strong> negotiate and document terms for <strong>the</strong> purchase and sale of LNG, for a period of 15 years,<br />
commencing in 2015.<br />
Downstream<br />
• In 2011, we signed supply agreements with several key contrac<strong>to</strong>rs and sub-contrac<strong>to</strong>rs associated with <strong>the</strong> Exxon<br />
Mobil LNG project, Papua New Guinea’s largest resource project <strong>to</strong> date. In addition, we re-signed all existing major<br />
cus<strong>to</strong>mers in <strong>the</strong> agricultural, commercial and aviation sec<strong>to</strong>rs <strong>to</strong> fur<strong>the</strong>r three year term supply agreements.<br />
• Year on year, sales volumes for 2011 were 678.0 million liters and were up by 51.5 million liters, or 8.2%, on <strong>the</strong> 2010<br />
volumes of 626.5 million liters.<br />
• Our retail business accounted for approximately 13% of our <strong>to</strong>tal downstream sales in 2011. Investments were made in<br />
2010 and 2011 in new electronic systems for both pumps and <strong>the</strong> forecourt control units <strong>to</strong> support <strong>the</strong> fur<strong>the</strong>r<br />
development of this business.<br />
• On December 8, 2011, <strong>the</strong> ICCC advised that margins for wholesale will increase in line with <strong>the</strong> ICCC mandated<br />
formula for a five year period. A CPI increase of 7% is reflected in <strong>the</strong>se revised margins. These increases apply <strong>to</strong><br />
unleaded gasoline, diesel and kerosene and are effective for <strong>the</strong> fiscal year ending December 31, 2012.<br />
• Subsequent <strong>to</strong> year end in February 2012, Westpac working capital facility was increased by $4.7 million (PGK 10.0<br />
million) bringing <strong>the</strong> <strong>to</strong>tal Downstream working capital facility <strong>to</strong> $65.3 million (PGK 140.0 million). In addition, a<br />
secured loan of $15.0 million was provided by Westpac which is repayable in equal installments over 3.5 years with an<br />
interest rate of LIBOR + 4.4% per annum.<br />
Corporate<br />
• The shipping business, which operates two vessels transporting petroleum products for us and external cus<strong>to</strong>mers<br />
both within PNG and for export in <strong>the</strong> South Pacific region, was transferred from our Downstream business segment <strong>to</strong><br />
Corporate during <strong>the</strong> year.<br />
31
Selected Annual Financial Information and Highlights<br />
Consolidated – Operating results Year ended December 31,<br />
($ thousands, except per share data) 2011 2010 2009<br />
Sales and operating revenues 1,106,534 802,374 688,479<br />
Interest revenue 1,356 151 351<br />
O<strong>the</strong>r non-allocated revenue 11,058 4,470 4,228<br />
Total revenue 1,118,948 806,995 693,058<br />
Cost of sales and operating expenses (1,020,932) (701,557) (601,983)<br />
Office and administration and o<strong>the</strong>r expenses (52,793) (52,650) (44,894)<br />
Derivative gain/(loss) 2,006 (1,065) 1,009<br />
Exploration costs (18,435) (16,982) (209)<br />
Gain on sale of oil and gas properties assets - 2,141 7,364<br />
Loss on extinguishment of IPI liability - (30,569) (31,710)<br />
Litigation settlement expense - (12,000) -<br />
Loss on Flex LNG Investment (3,420) - -<br />
Foreign exchange gain/(loss) 25,019 (10,777) (3,305)<br />
EBITDA (1) 50,393 (16,464) 19,330<br />
Depreciation and amortization (20,137) (14,275) (14,322)<br />
Interest expense (13,333) (7,364) (9,993)<br />
Profit/(loss) before income taxes 16,923 (38,103) (4,985)<br />
Income tax benefit/(expense) 736 (6,410) 11,076<br />
Net profit/(loss) 17,659 (44,513) 6,091<br />
Net profit/(loss) per share (dollars) (basic) 0.37 (1.00) 0.15<br />
Net profit/(loss) per share (dollars) (diluted) 0.36 (1.00) 0.15<br />
Total assets 1,088,355 975,743 631,754<br />
Total liabilities 328,464 272,841 189,764<br />
Total long-term liabilities 128,072 130,323 96,225<br />
Gross margin (2) 85,602 100,817 86,496<br />
Cash flows generated from/(used in) operating activities (3) 62,670 (13,561) 44,500<br />
•<br />
•<br />
•<br />
•<br />
EBITDA, is a non-GAAP measure and is reconciled <strong>to</strong> IFRS in <strong>the</strong> section <strong>to</strong> this document entitled “Non-GAAP Measures and Reconciliation”.<br />
Gross margin is a non-GAAP measure and is “sales and operating revenues” less ”cost of sales and operating expenses” and is reconciled <strong>to</strong> IFRS in <strong>the</strong><br />
section <strong>to</strong> this document entitled ”Non-GAAP Measures and Reconciliation”.<br />
Refer <strong>to</strong> “Liquidity and Capital Resources – Summary of Cash Flows” for detailed cash flow analysis.<br />
The 2009 selected financial information was prepared in accordance with <strong>the</strong> Company’s former GAAP, and has not been restated in accordance with<br />
IFRS.<br />
Analysis of Financial Condition Comparing Years Ended December 31, 2011, 2010 and 2009<br />
During <strong>the</strong> year ended December 31, 2011, our debt-<strong>to</strong>-capital ratio (being debt/[shareholders’ equity + debt]) was 12%<br />
(13% as at December 31, 2010 and 11% as at December 31, 2009), well below our targeted maximum gearing level of 50%.<br />
Gearing targets are based on a number of fac<strong>to</strong>rs including operating cash flows, future cash needs for development, capital<br />
market conditions, economic conditions, and are assessed regularly.<br />
Our current ratio (being current assets/current liabilities), which measures our ability <strong>to</strong> meet short term obligations, was 2.1<br />
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<br />
ratio (or acid test ratio, (being [current assets less inven<strong>to</strong>ries]/current liabilities)) which is a more conservative measure of our<br />
ability <strong>to</strong> meet short term obligations, was 1.3 times as at December 31, 2011 (2.3 times as at December 31, 2010 and 1.5<br />
times as at December 31, 2009). These ratios satisfy our internal targets <strong>to</strong> be above 1.5 times for <strong>the</strong> current ratio and 1.0<br />
times for <strong>the</strong> quick ratio.<br />
As at December 31, 2011, our <strong>to</strong>tal assets amounted <strong>to</strong> $1,088.4 million, compared with $975.7 million as at December 31,<br />
2010 and $631.8 million as at December 31, 2009. The increase of $112.7 million or 11.5% from December 31, 2010 was<br />
primarily due <strong>to</strong> increases in <strong>the</strong> value of our oil and gas properties of $107.6 million associated with <strong>the</strong> appraisal and of<br />
<strong>the</strong> Elk and Antelope fields, preparation for drilling <strong>the</strong> Tricera<strong>to</strong>ps 2 well, and continued development of <strong>the</strong> LNG Project; an<br />
increase in inven<strong>to</strong>ry balances and trade receivable balances of $43.9 million and $87.2 million respectively due <strong>to</strong> higher<br />
32
working capital needs on higher average crude prices during <strong>the</strong> current period; a net $20.8 million increase in plant and<br />
equipment (after depreciation) from capitalization of refinery asset retirement obligations, tank upgrades, camp and office<br />
building works, and new business system implementation costs; $7.5 million increase in deferred tax benefits mainly due <strong>to</strong><br />
<strong>the</strong> temporary difference arising on foreign exchange translation of non-monetary assets of <strong>the</strong> refinery operation; and $3.7<br />
million for our investment in shares in FLEX LNG. These increases were offset by net decreases in our cash, cash equivalents,<br />
cash restricted, and short term treasury bills of $160.9 million, due primarily <strong>to</strong> expenditure on development of our oil and gas<br />
properties. The increase in <strong>to</strong>tal assets of $344.0 million or 54.4% from December 31, 2009 <strong>to</strong> December 31, 2010 was due<br />
primarily <strong>to</strong> a $187.1 million increase in cash and cash equivalents following <strong>the</strong> concurrent common share and convertible<br />
notes offerings, increases in our oil and gas properties of $82.8 million associated with <strong>the</strong> appraisal and development of <strong>the</strong><br />
Elk and Antelope fields and fur<strong>the</strong>ring of <strong>the</strong> Condensate Stripping Project and LNG Project, and an increase in inven<strong>to</strong>ry<br />
balances of $57.0 million at our refinery due <strong>to</strong> <strong>the</strong> timing of shipments.<br />
As at December 31, 2011, our <strong>to</strong>tal liabilities amounted <strong>to</strong> $328.5 million, compared with $272.8 million at December 31,<br />
2010 and $189.8 million as at December 31, 2009. The increase of $55.7 million or 20.4% from December 31, 2010 was<br />
primarily due <strong>to</strong> an increase in accounts payable and accrued liabilities of $84.7 million, offset in part by a reduction of $34.8<br />
million in <strong>the</strong> working capital facility which is mainly a function of timing of crude purchases for <strong>the</strong> refining operation. The<br />
increase in liability of $83.0 million or 43.7% as at December 31, 2010 from December 31, 2009 was primarily due <strong>to</strong> <strong>the</strong><br />
recognition of a $52.4 million liability relating <strong>to</strong> <strong>the</strong> fair value of <strong>the</strong> debt component of <strong>the</strong> unsecured 2.75% convertible notes<br />
issuance in November 2010 and an increase in <strong>the</strong> working capital facility balance of $26.6 million.<br />
Analysis of Consolidated Financial Results Comparing Years and Quarters Ended December 31, 2011, 2010 and 2009<br />
Annual Comparative<br />
Net profit for <strong>the</strong> year ended December 31, 2011 was $17.7 million compared with a net loss of $44.5 million for <strong>the</strong> same<br />
period in 2010, an improvement of $62.2 million. The operating segments of Corporate, Midstream Refining and Downstream<br />
collectively returned a net profit for <strong>the</strong> year of $82.3 million. The development segments of Upstream and Midstream<br />
Liquefaction yielded a net loss of $64.6 million.<br />
The main items contributing <strong>to</strong>wards <strong>the</strong> loss in 2010 were unusual, one time charges including a loss on extinguishment of<br />
IPI liability of $30.6 million and a $12.0 million expense relating <strong>to</strong> settlement of certain long-standing litigation.<br />
Total revenues for <strong>the</strong> year ended December 31, 2011 were $1,118.9 million compared with $807.0 million and $693.1 million<br />
respectively for <strong>the</strong> same periods in 2010 and 2009. This increase in <strong>the</strong> year ended 2011 compared <strong>to</strong> <strong>the</strong> same period in<br />
2010 was due <strong>to</strong> <strong>the</strong> higher crude price environment in <strong>the</strong> 2011 year and an increase in domestic volumes of product sold<br />
for higher margin products. The <strong>to</strong>tal volume of all products sold by us was 7.5 million barrels for fiscal year 2011, compared<br />
with 7.2 million barrels in 2010 and 6.5 million barrels in 2009.<br />
EBITDA for <strong>the</strong> year ended December 31, 2011 was $50.4 million, an increase of $66.9 million over negative EBITDA of $16.5<br />
million for <strong>the</strong> same period in 2010, mainly due <strong>to</strong> <strong>the</strong> unusual, one time charges in 2011 as detailed above. The current year<br />
also had an improvement in our net foreign exchange gain/loss for <strong>the</strong> year of $35.8 million compared <strong>to</strong> <strong>the</strong> prior period as a<br />
result of rising Papua New Guinea Kina (“PGK”) against USD.<br />
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).<br />
The reduction in <strong>the</strong> loss in 2011 by $29.4 million from 2010 was mainly due <strong>to</strong> one-time events in <strong>the</strong> prior year of $30.6<br />
million loss on extinguishment of IPI liability and $2.1 million gain on sale of oil and gas properties. During 2011, <strong>the</strong>re has<br />
been an increase of $11.5 million on intercompany interest charges due <strong>to</strong> higher loan balances from <strong>the</strong> parent entity<br />
(Corporate segment) <strong>to</strong> fund <strong>the</strong> exploration activities. This increase has been offset by a $8.6 million reduction in office and<br />
administration expenses as more expenses have been capitalized (mainly relating <strong>to</strong> rig expenditure associated with mud<br />
corrosion caused during <strong>the</strong> drilling of Antelope 2 well, and expenditure associated with rig standby on Tricera<strong>to</strong>ps 2 well<br />
drilling due <strong>to</strong> delays in finalization of <strong>the</strong> location of <strong>the</strong> well and wea<strong>the</strong>r associated delays), and a $6.5 million increase in<br />
o<strong>the</strong>r revenue driven by higher recovery of construction and related equipments on <strong>the</strong>ir better utilization during <strong>the</strong> period on<br />
LNG Project related civil works and related infrastructure development. The increase in <strong>the</strong> loss in 2010 by $39.1 million from<br />
2009 was mainly due <strong>to</strong> a $16.8 million increase in exploration costs relating <strong>to</strong> <strong>the</strong> Tricera<strong>to</strong>ps field and Wolverine seismic,<br />
$9.2 million higher intercompany interest charges, and a $5.2 million reduction in <strong>the</strong> gain on sale of exploration assets in<br />
2010 compared <strong>to</strong> 2009 as <strong>the</strong> prior year included conveyance accounting on <strong>the</strong> IPI agreement for conversion rights waived<br />
by certain IPI inves<strong>to</strong>rs.<br />
The Midstream Refining segment generated a net profit of $46.7 million in 2011 (2010 - $33.5 million, 2009 - $41.8 million)<br />
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<br />
33
improvement <strong>to</strong> income tax expense arising primarily from <strong>the</strong> temporary differences due <strong>to</strong> translation of <strong>the</strong> non-monetary<br />
assets held by <strong>the</strong> Refinery using period end rates, and a $3.6 million increase in derivative gains. These increases have been<br />
partly offset by lower gross margins (a decrease of $27.1 million from 2010) due primarily <strong>to</strong> lower crack spreads, and a $3.1<br />
million increase in interest expense charged on higher loan balances from <strong>the</strong> parent entity. The net profit in 2010 decreased<br />
from 2009 mainly on account of <strong>the</strong> initial recognition of $14.3 million of deferred tax assets in 2010.<br />
The Midstream Liquefaction segment had a net loss of $15.5 million during <strong>the</strong> 2011 year (2010 – loss of $8.4 million, 2009<br />
– loss of $8.4 million) resulting from higher management expenses and share compensation costs related <strong>to</strong> <strong>the</strong> LNG Project<br />
development which are not capitalized. As <strong>the</strong> LNG Project Agreement was signed by <strong>the</strong> Government of Papua New Guinea<br />
in December 2009, all direct project related costs since that date have been capitalized <strong>to</strong> <strong>the</strong> project ra<strong>the</strong>r than expensed.<br />
The Downstream segment generated a net profit of $11.6 million in 2011 (2010 – profit of $6.7 million, 2009 – profit of $8.5<br />
million). The increased profit was mainly due <strong>to</strong> a $5.6 million improvement in gross margins due <strong>to</strong> an increase in domestic<br />
volumes resulting from various development projects being undertaken in Papua New Guinea, <strong>the</strong> positive impact from <strong>the</strong><br />
revised pricing formula that came in<strong>to</strong> effect in late 2010 following <strong>the</strong> ICCC’s review of wholesale, distribution and retail<br />
margins set by <strong>the</strong> PNG State for <strong>the</strong> petroleum industry, and <strong>the</strong> impact of <strong>the</strong> increasing price environment during <strong>the</strong> period<br />
leading <strong>to</strong> higher margins on inven<strong>to</strong>ries sold. This improvement in gross margins has been partly offset by a $1.2 million<br />
increase in depreciation and amortization on capital purchases related primarily <strong>to</strong> office refurbishment and upgrade<br />
projects across various terminals and depots. The decreased profit in 2010 compared <strong>to</strong> 2009 was mainly due <strong>to</strong> a $3.0<br />
million increase in office and administration expenses, a $2.0 million increase in foreign exchange loss and a $1.7 million<br />
increase in income tax expense offset in part by a $4.6 million improvement in gross margin.<br />
The Corporate segment generated a net profit of $21.9 million (2010 – profit of $3.3 million, 2009 – loss of $4.3 million). The<br />
2010 results included a $12.0 million settlement expense <strong>to</strong> finalize certain long-standing litigation, and a $14.2 million<br />
increase in interest charges <strong>to</strong> o<strong>the</strong>r business segments on increased loan balances. These expenses have been partly offset<br />
by a $4.5 million increase in interest expense due <strong>to</strong> <strong>the</strong> 2.75% convertible notes issued on November 10, 2010 and a $3.4<br />
million impairment loss on our investment in shares in Flex LNG held by us as part of <strong>the</strong> framework agreements entered in<strong>to</strong><br />
with FLEX LNG and Samsung Heavy Industries in April 2011.<br />
Quarterly Comparative<br />
The net profit for <strong>the</strong> quarter ended December 31, 2011 was $13.2 million compared with a loss of $34.8 million for <strong>the</strong> same<br />
quarter of 2010, an improvement of $48.0 million. This movement was mainly due <strong>to</strong> a $21.8 million loss on extinguishment of<br />
IPI liability in <strong>the</strong> prior year quarter in relation <strong>to</strong> a 1.0% IPI interest buyback, an $11.8 million reduction in expensed<br />
exploration costs on lower seismic activity, a $10.5 million increase in foreign exchange gains, and an $18.7 million<br />
improvement in income tax expense primarily from <strong>the</strong> impact of foreign exchange movements impacting temporary<br />
differences on translation of <strong>the</strong> nonmonetary assets of <strong>the</strong> refinery operation using period end rates. These gains have been<br />
offset in part by an $18.3 million reduction in gross margin for <strong>the</strong> quarter due primarily <strong>to</strong> decreased export product crack<br />
spreads and <strong>the</strong> impact of both <strong>the</strong> CRU and Crude Distillation Unit (“CDU”) being shut down.<br />
The operating segments of Corporate, Midstream Refining and Downstream collectively derived a net profit for <strong>the</strong> fourth<br />
quarter of $27.2 million, while <strong>the</strong> development segments of Upstream and Midstream Liquefaction had a net loss of $14.0<br />
million, for an aggregate net profit of $13.2 million.<br />
Total revenues increased by $95.2 million from $194.4 million in <strong>the</strong> quarter ended December 31, 2010 <strong>to</strong> $289.6 million in<br />
<strong>the</strong> quarter ended December 31, 2011 primarily due <strong>to</strong> higher volumes and prices during <strong>the</strong> quarter. The <strong>to</strong>tal volume of all<br />
products sold by us was 1.9 million barrels for quarter ended December 2011, compared with 1.6 million barrels in <strong>the</strong> same<br />
quarter of 2010.<br />
Variance Analysis<br />
A <strong>complete</strong> discussion of each of our business segments’ results can be found under <strong>the</strong> section ”Year and Quarter in<br />
Review”. The following analysis outlines <strong>the</strong> key variances, <strong>the</strong> net of which are <strong>the</strong> primary explanations for <strong>the</strong> changes in<br />
<strong>the</strong> consolidated results between <strong>the</strong> years and quarters ended December 31, 2011 and 2010.<br />
34
Yearly<br />
Variance<br />
($ millions)<br />
Quarterly<br />
Variance<br />
($ millions)<br />
$62.2 $48.0 Net profit/(loss) variance for <strong>the</strong> comparative periods primarily due <strong>to</strong>:<br />
($15.2) ($18.3) Reduction in gross margin for <strong>the</strong> year driven by increase in crude costs, decreases in export product<br />
crack spreads and reduced demand for export products, offset by volume increases and improved<br />
margins in <strong>the</strong> domestic market.<br />
$6.6 $1.5 Increase in o<strong>the</strong>r non-allocated revenue due <strong>to</strong> better utilization of construction and related equipment on<br />
civil works and related infrastructure development associated with <strong>the</strong> LNG Project.<br />
($0.1) $4.9 Decrease in office and administration and o<strong>the</strong>r expenses in <strong>the</strong> current quarter on higher capitalization of<br />
expenses (mainly relating <strong>to</strong> rig expenditure associated with corrosion caused by drilling mud, and<br />
expenditure associated with rig standby on <strong>the</strong> Tricera<strong>to</strong>ps 2 well drilling due <strong>to</strong> delays in finalization of <strong>the</strong><br />
location of <strong>the</strong> well and wea<strong>the</strong>r associated delays).<br />
$3.1 $1.4 Movement in gains from derivative contracts that were not accounted for as hedge accounted contracts.<br />
($1.5) $11.8 Higher exploration costs for seismic activity on our licenses PPL 236, 237 and 238 during <strong>the</strong> year. The<br />
majority of <strong>the</strong> seismic costs were incurred during <strong>the</strong> first three quarters of <strong>the</strong> current year and <strong>the</strong> fourth<br />
quarter of 2010. These seismic costs were expensed as incurred.<br />
$30.6 $21.8 Loss on extinguishment of IPI liability in 2010 in relation <strong>to</strong> <strong>the</strong> interest buyback of 1.4%, 1.0% of which<br />
was purchased in <strong>the</strong> fourth quarter. There have been no such buybacks during 2011.<br />
$12.0 - Litigation settlement expense in <strong>the</strong> third quarter of 2010 on settlement of <strong>the</strong> Todd Peters et al litigation for<br />
which we issued 199,677 common shares <strong>to</strong> <strong>the</strong> plaintiffs valued at $12.0 million.<br />
($3.4) ($1.6) Loss recognized on our investment in shares in FLEX LNG held by us as part of <strong>the</strong> framework agreements<br />
entered in<strong>to</strong> with FLEX LNG and Samsung Heavy Industries in April 2011.<br />
$35.8 $10.5 The PGK streng<strong>the</strong>ned against <strong>the</strong> USD from 0.3785 at <strong>the</strong> start of <strong>the</strong> year <strong>to</strong> 0.4665 as at December 31,<br />
2011. We are currently holding more PGK cash balances in PNG <strong>to</strong> partly mitigate <strong>the</strong> risk of a rising PGK<br />
which would affect exploration and development costs.<br />
($5.9) ($2.0) Increase in depreciation expense mainly due <strong>to</strong> <strong>the</strong> depreciation of construction machinery which was<br />
acquired over <strong>the</strong> last year, and <strong>the</strong> depreciation of <strong>the</strong> new ERP system.<br />
($6.0) ($1.0) Higher interest expense for <strong>the</strong> quarter and year primarily due <strong>to</strong> higher utilization of our Midstream and<br />
Downstream working capital facilities, and interest on <strong>the</strong> 2.75% convertible senior notes issued on<br />
November 10, 2010.<br />
$7.1 $18.7 Decrease in income tax expense for <strong>the</strong> year primarily from <strong>the</strong> impact of foreign exchange movements<br />
impacting temporary differences on translation of <strong>the</strong> nonmonetary assets of <strong>the</strong> refinery operation using<br />
period end rates.<br />
Analysis of Consolidated Cash Flows Comparing Years and Quarters Ended December 31, 2011 and 2010<br />
As at December 31, 2011, we had cash, cash equivalents, and cash restricted of $108.1 million (December 2010 – $280.9<br />
million), of which $39.3 million (December 2010 - $47.3 million) was restricted. In addition, we also had $11.8 million<br />
equivalent of PGK in short term treasury bills issued by <strong>the</strong> Bank of Papua New Guinea (December 2010 – nil). Of <strong>the</strong> <strong>to</strong>tal<br />
cash restricted of $39.3 million, $33.0 million (December 2010 - $40.7 million) was restricted pursuant <strong>to</strong> <strong>the</strong> BNP Paribas<br />
working capital facility utilization requirements, $5.9 million (December 2010 – $6.3 million) was restricted as a cash deposit<br />
on <strong>the</strong> OPIC secured loan relating <strong>to</strong> our half yearly instalment of $4.5 million and <strong>the</strong> related interest that will be payable with<br />
<strong>the</strong> next instalment on June 30, 2012, and <strong>the</strong> balance was made up of a cash deposit on office premises <strong>to</strong>ge<strong>the</strong>r with term<br />
deposits on our PPLs.<br />
Our cash inflows from operations for <strong>the</strong> year ended December 31, 2011 were $62.7 million compared with outflows of $13.6<br />
million for <strong>the</strong> year ended December 31, 2010, a net increase in cash inflows of $76.3 million. This increase in cash inflows is<br />
mainly due <strong>to</strong> a $26.2 million change in cash generated by operations prior <strong>to</strong> changes in operating working capital, related<br />
<strong>to</strong> net profits generated from operations less any non-cash expenses for <strong>the</strong> year. There was also a $50.1 million decrease in<br />
working capital associated with trade receivables, inven<strong>to</strong>ries and accounts payables.<br />
Cash outflows for investing activities for <strong>the</strong> year ended December 31, 2011 were $204.2 million compared with $111.2<br />
million for <strong>the</strong> year ended December 31, 2010. These outflows mainly relate <strong>to</strong> <strong>the</strong> net cash expenditure on exploration,<br />
appraisal and development activities (net of IPI cash calls) of $134.1 million, expenditure on plant and equipment of $42.1<br />
million, acquisition of FLEX LNG shares net of transaction costs of $7.5 million, investments in short term PGK treasury bills<br />
of $11.8 million, a $10.0 million increase in trade receivables and a $6.7 million decrease in working capital requirements of<br />
development segments relating <strong>to</strong> <strong>the</strong> timing of receipts and payments. These outflows were partly offset by a decrease of<br />
$8.0 million in <strong>the</strong> restricted cash balance under <strong>the</strong> BNP Paribas working capital facility.<br />
35
Cash outflows from financing activities for <strong>the</strong> year ended December 31, 2011 amounted <strong>to</strong> $27.2 million, compared with<br />
$311.8 million inflows for <strong>the</strong> year ended December 31, 2010. These cash outflows include two repayments of <strong>the</strong> OPIC<br />
secured loan of $9.0 million and $34.8 million repayments of <strong>the</strong> working capital facility. These outflows have been partly<br />
offset by receipts of cash contributions from Mitsui for <strong>the</strong> Condensate Stripping Project of $9.9 million, receipts from PNG<br />
LNG cash call of $2.2 million, and receipts of cash from <strong>the</strong> exercise of s<strong>to</strong>ck options of $4.5 million. The cash inflows /<br />
outflows associated with <strong>the</strong> working capital facility drawdown/repayments are due <strong>to</strong> <strong>the</strong> timing of cash flows and <strong>the</strong> use of<br />
working capital. The inflows from financing activities in <strong>the</strong> prior year relate primarily <strong>to</strong> <strong>the</strong> receipt of cash from <strong>the</strong> concurrent<br />
common shares and 2.75% convertible notes offerings in November 2010.<br />
Summary of Consolidated Quarterly Financial Results for Past Eight Quarters<br />
The following is a table containing <strong>the</strong> consolidated results for <strong>the</strong> eight quarters ended December 31, 2011 by business<br />
segment, and on a consolidated basis. Our IFRS transition date was January 1, 2010 and as such, <strong>the</strong> 2010 comparative<br />
information in <strong>the</strong> table below has been restated in accordance with IFRS.<br />
Quarters ended<br />
($ thousands except per<br />
share data)<br />
2011 2010<br />
Dec 31 Sept 30 June 30 March 31 Dec 31 Sept 30 June 30 March 31<br />
Upstream 1,891 2,645 4,638 668 245 714 1,349 998<br />
Midstream – Refining 237,640 231,455 262,111 217,743 158,092 173,379 194,016 152,093<br />
Midstream – Liquefaction - - - - - - - -<br />
Downstream 209,678 186,304 191,431 157,709 143,364 133,508 119,300 109,687<br />
Corporate 21,831 25,078 26,548 18,659 15,213 18,295 11,321 12,093<br />
Consolidation entries (181,428) (163,584) (180,945) (151,125) (122,545) (117,437) (100,637) (96,053)<br />
Total revenues 289,612 281,898 303,783 243,654 194,369 208,459 225,349 178,818<br />
Upstream 665 (6,169) 593 (10,957) (41,681) (11,753) (3,498) (1,964)<br />
Midstream – Refining 2,604 3,461 27,967 26,632 13,780 15,785 16,962 4,402<br />
Midstream – Liquefaction (4,123) (3,602) (4,035) (2,375) (1,959) (4,588) (3) (563)<br />
Downstream 6,808 3,570 5,777 8,744 4,709 1,674 7,060 4,492<br />
Corporate 10,134 1,548 13,940 5,223 4,566 (4,510) 1,751 4,402<br />
Consolidation entries (11,280) (10,263) (5,270) (9,200) (7,004) (5,229) (7,384) (5,911)<br />
EBITDA (1) 4,808 (11,455) 38,972 18,067 (27,589) (8,621) 14,888 4,858<br />
Upstream (9,402) (15,080) (6,703) (17,949) (47,845) (16,585) (7,943) (6,182)<br />
Midstream – Refining 15,684 (1,201) 17,314 14,894 9,504 11,998 12,056 (74)<br />
Midstream – Liquefaction (4,574) (3,980) (4,309) (2,604) (2,114) (4,970) (360) (911)<br />
Downstream 3,621 1,146 2,306 4,491 2,643 (325) 3,719 671<br />
Corporate 7,616 (473) 11,275 3,463 3,381 (5,398) 1,796 3,544<br />
Consolidation entries 252 (190) 3,657 (1,596) (401) 908 (1,435) (190)<br />
Net profit/(loss) 13,197 (19,778) 23,540 699 (34,832) (14,372) 7,833 (3,142)<br />
Net profit/(loss) per share (dollars)<br />
Per Share – Basic 0.27 (0.41) 0.49 0.01 (0.76) (0.33) 0.18 (0.07)<br />
Per Share – Diluted 0.27 (0.41) 0.48 0.01 (0.76) (0.33) 0.17 (0.07)<br />
1 EBITDA is a non-GAAP measure and is reconciled <strong>to</strong> IFRS in <strong>the</strong> section <strong>to</strong> this document entitled “Non-GAAP Measures and Reconciliation”.<br />
36
Year and Quarter in Review<br />
The following section provides a review of <strong>the</strong> year and quarter ended December 31, 2011 for each of our business segments.<br />
Upstream - Year and Quarter in Review<br />
Upstream – Operating results<br />
($ Thousands)<br />
Year ended December 31,<br />
2011 2010<br />
O<strong>the</strong>r non-allocated revenue 9,841 3,305<br />
Total revenue 9,841 3,305<br />
Office and administration and o<strong>the</strong>r expenses (5,122) (13,746)<br />
Exploration costs (18,435) (16,982)<br />
Gain on sale of oil and gas properties - 2,141<br />
Loss on extinguishment of IPI liability - (30,569)<br />
Foreign exchange loss (2,153) (3,044)<br />
EBITDA (1) (15,869) (58,895)<br />
Depreciation and amortization (3,255) (1,132)<br />
Interest expense (30,013) (18,528)<br />
Loss before income taxes (49,137) (78,555)<br />
Income tax expense - -<br />
Net loss (49,137) (78,555)<br />
1 EBITDA is a non-GAAP measure and is reconciled <strong>to</strong> IFRS in <strong>the</strong> section <strong>to</strong> this document entitled “Non-GAAP Measures and Reconciliation”.<br />
Analysis of Upstream Financial Results Comparing Year and Quarter Ended December 31, 2011 and 2010<br />
The following analysis outlines <strong>the</strong> key movements, <strong>the</strong> net of which primarily explains <strong>the</strong> difference in <strong>the</strong> results between <strong>the</strong><br />
years and quarters ended December 31, 2011 and 2010.<br />
Yearly Variance<br />
($ millions)<br />
Quarterly Variance<br />
($ millions)<br />
$29.4 $38.4 Net profit/(loss) variance for <strong>the</strong> comparative periods primarily due <strong>to</strong>:<br />
$6.5 $1.6 Increase in o<strong>the</strong>r non-allocated revenue driven by higher recovery of construction and related<br />
equipment charges on <strong>the</strong>ir better utilization during <strong>the</strong> period on LNG Project related civil works<br />
and related infrastructure development. Recoveries in relation <strong>to</strong> our percentage interest of <strong>the</strong><br />
development projects are offset against <strong>the</strong> relevant expenses, while <strong>the</strong> recoveries of <strong>the</strong> portion<br />
relating <strong>to</strong> external party interests in <strong>the</strong> development projects are classified under o<strong>the</strong>r<br />
non-allocated revenue.<br />
($1.5) $11.8 Higher exploration costs for seismic activity during <strong>the</strong> year on PPL 236. The majority of <strong>the</strong><br />
seismic costs were incurred during <strong>the</strong> first three quarters of 2011 and <strong>the</strong> fourth quarter of 2010.<br />
These seismic costs were expensed as incurred under <strong>the</strong> successful efforts method of<br />
accounting.<br />
($2.1) - Gain recognized on <strong>the</strong> sale of our 15% interest in PPL 244 in <strong>the</strong> year ended December 31,<br />
2010.<br />
$30.6 $21.8 Loss on extinguishment of IPI liability in 2010 in relation <strong>to</strong> <strong>the</strong> buyback of IPI interests amounting<br />
<strong>to</strong> 1.4%, 1.0% of which was purchased in <strong>the</strong> fourth quarter of 2010. There have been no such<br />
buybacks during 2011.<br />
$8.6 $7.0 Reduction in office and administration expenses as more expenses have been capitalized (mainly<br />
relating <strong>to</strong> rig expenditure associated with corrosion caused by drilling mud, and expenditure<br />
associated with rig standby on <strong>the</strong> Tricera<strong>to</strong>ps 2 well drilling due <strong>to</strong> delays in finalization of <strong>the</strong><br />
location of <strong>the</strong> well and wea<strong>the</strong>r associated delays).<br />
($11.5) ($3.2) Higher interest expense due <strong>to</strong> an increase in inter-company loan balances provided <strong>to</strong> fund<br />
exploration and development activities.<br />
37
Midstream - Refining - Year and Quarter in Review<br />
Midstream Refining – Operating results<br />
($ thousands)<br />
Year ended December 31,<br />
2011 2010<br />
External sales 362,606 298,071<br />
Inter-segment revenue - Sales 576,672 376,066<br />
Inter-segment revenue - Recharges 8,841 3,278<br />
Interest and o<strong>the</strong>r revenue 831 166<br />
Total segment revenue 948,950 677,581<br />
Cost of sales and operating expenses (897,825) (605,603)<br />
Office and administration and o<strong>the</strong>r expenses (18,939) (11,940)<br />
Derivative gain/(loss) 2,018 (1,592)<br />
Foreign exchange gain/(loss) 26,458 (7,518)<br />
EBITDA (1) 60,662 50,928<br />
Depreciation and amortization (11,254) (10,355)<br />
Interest expense (9,664) (6,585)<br />
Profit before income taxes 39,744 33,988<br />
Income tax benefit/(expense) 6,946 (505)<br />
Net profit 46,690 33,483<br />
Gross Margin (2) 41,453 68,534<br />
1 EBITDA is a non-GAAP measure and is reconciled <strong>to</strong> IFRS in <strong>the</strong> section <strong>to</strong> this document entitled “Non-GAAP Measures and Reconciliation”.<br />
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<br />
reconciled <strong>to</strong> IFRS in <strong>the</strong> section <strong>to</strong> this document entitled “Non-GAAP Measures and Reconciliation”.<br />
Midstream - Refining Operating Review<br />
Key Refining Metrics<br />
Quarter ended December 31, Quarter ended December 31,<br />
2011 2010 2011 2010<br />
Throughput (barrels per day) (1) 24,644 21,550 24,856 24,682<br />
Capacity utilization<br />
(based on 36,500 barrels per day operating capacity)<br />
50% 34% 54% 53%<br />
Cost of production per barrel (2) $5.18 $3.66 $4.58 $2.84<br />
Working capital financing cost per barrel of production (2) $0.76 $0.58 $0.73 $0.47<br />
Distillates as percentage of production 57.1% 58.70% 57.5% 51.00%<br />
1 Throughput per day has been calculated excluding shut down days. During 2011 and 2010, <strong>the</strong> refinery was shut down for 82 days and 81 days,<br />
respectively.<br />
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<br />
been adjusted <strong>to</strong> include <strong>the</strong> throughput that would have been necessary <strong>to</strong> produce <strong>the</strong> equivalent amount of finished product that we imported during <strong>the</strong> year.<br />
The increase in <strong>the</strong> cost of production per barrel for <strong>the</strong> current periods is mainly due <strong>to</strong> <strong>the</strong> depreciation of <strong>the</strong> USD against <strong>the</strong> PGK and AUD, <strong>the</strong><br />
currencies in which we incur our operating expenditures, and a general inflationary increase, higher personnel costs and system and IT upgrades performed<br />
during <strong>the</strong> current periods.<br />
During <strong>the</strong> second half of 2011, <strong>the</strong> PNG Cus<strong>to</strong>ms Service commenced an audit of our petroleum product imports in<strong>to</strong> Papua<br />
New Guinea for <strong>the</strong> years 2007 <strong>to</strong> 2010. We received a letter in November 2011 from <strong>the</strong> <strong>the</strong>n Commissioner of Cus<strong>to</strong>ms<br />
setting out certain findings from <strong>the</strong> audit. This letter included comments alleging that payment of import goods and services<br />
taxes (“GST”) was required and had not been made on imports of certain refined products. As well as requiring payment of<br />
GST, <strong>the</strong> letter noted that administrative penalties were able <strong>to</strong> be levied by Cus<strong>to</strong>ms in <strong>the</strong> range of 50% <strong>to</strong> 200% of <strong>the</strong><br />
assessed amounts as per <strong>the</strong> PNG Cus<strong>to</strong>ms Act. We have since met with <strong>the</strong> Cus<strong>to</strong>ms Service and provided it with<br />
supporting documentation <strong>to</strong> demonstrate that <strong>the</strong> GST amounts claimed in <strong>the</strong>ir letter have all been paid. We have currently<br />
made a provision based on our best estimate in relation <strong>to</strong> this matter and are working closely with <strong>the</strong> authority <strong>to</strong> provide all<br />
requested information in order <strong>to</strong> finalize <strong>the</strong> audit.<br />
38
Analysis of Midstream - Refining Financial Results Comparing <strong>the</strong> Year and Quarter Ended December 31, 2011 and 2010<br />
The following analysis outlines <strong>the</strong> key changes, <strong>the</strong> net of which primarily explains <strong>the</strong> variance in <strong>the</strong> results between <strong>the</strong><br />
years and quarters ended December 31, 2011 and 2010.<br />
Yearly Variance<br />
($ millions)<br />
Quarterly Variance<br />
($ millions)<br />
$13.2 $6.2 Net profit/(loss) variance for <strong>the</strong> comparative periods primarily due <strong>to</strong>:<br />
($27.1) ($19.9) Decrease in gross margin for <strong>the</strong> year mainly due <strong>to</strong> <strong>the</strong> following contributing fac<strong>to</strong>rs:<br />
- Decreases in export product crack spreads due <strong>to</strong> increase in crude costs and reduced<br />
demand for export products<br />
+ Increases in crude and product flat pricing over <strong>the</strong> year contributing <strong>to</strong> increased inven<strong>to</strong>ry<br />
gains for all products<br />
+ Better crude mix resulting in increased distillate yield percentage<br />
$34.0 $8.0 Increase in foreign exchange gain due <strong>to</strong> <strong>the</strong> streng<strong>the</strong>ning of <strong>the</strong> PGK against <strong>the</strong> USD. The PGK<br />
streng<strong>the</strong>ned against <strong>the</strong> USD from 0.3785 at <strong>the</strong> start of <strong>the</strong> year <strong>to</strong> 0.4665 as at December 31,<br />
2011. As part of our foreign exchange risk management strategy, we have begun holding more<br />
PGK cash balances in PNG <strong>to</strong> partly mitigate <strong>the</strong> risk of a rising PGK affecting our operations.<br />
($1.4) ($0.8) Increase in office and administration costs net of recharge revenue for <strong>the</strong> year was driven by<br />
higher salaries, wages and share compensation expenses, which were <strong>to</strong> a large extent impacted<br />
by <strong>the</strong> streng<strong>the</strong>ning of <strong>the</strong> PGK and Australian Dollar (“AUD”) against <strong>the</strong> USD during <strong>the</strong> period.<br />
$3.6 $1.3 Movement in gains from derivative contracts that were not accounted for as hedge accounted<br />
contracts.<br />
($3.1) ($1.8) Increase in interest expense on higher utilization of <strong>the</strong> working capital facilities.<br />
$7.5 $19.3 Decrease in income tax expense in 2011 primarily from <strong>the</strong> impact of foreign exchange<br />
movements impacting temporary differences on translation of <strong>the</strong> nonmonetary assets of <strong>the</strong><br />
refinery operation using period end rates, offset by income tax expense on profits generated by<br />
<strong>the</strong> operations.<br />
Midstream - Liquefaction - Year and Quarter in Review<br />
Midstream Liquefaction – Operating results<br />
($ thousands)<br />
Year ended December 31,<br />
2011 2010<br />
Interest and o<strong>the</strong>r revenue - 1<br />
Total segment revenue - 1<br />
Office and administration and o<strong>the</strong>r expenses (14,121) (7,023)<br />
Foreign exchange loss (13) (90)<br />
EBITDA (1) (14,134) (7,112)<br />
Depreciation and amortization (26) (25)<br />
Interest expense (1,308) (1,253)<br />
Loss before income taxes (15,468) (8,390)<br />
Income tax benefit - 36<br />
Net loss (15,468) (8,354)<br />
1 EBITDA is a non-GAAP measure and is reconciled <strong>to</strong> IFRS in <strong>the</strong> section <strong>to</strong> this document entitled “Non-GAAP Measures and Reconciliation”.<br />
Analysis of Midstream - Liquefaction Financial Results Comparing <strong>the</strong> Year and Quarter Ended December 31, 2011<br />
and 2010<br />
This segment’s results include <strong>the</strong> proportionate consolidation of our interest in <strong>the</strong> joint venture development of <strong>the</strong> proposed<br />
midstream facilities of <strong>the</strong> LNG Project. The development of <strong>the</strong>se facilities is being progressed in joint venture with Pac LNG<br />
through PNG LNG. We currently have an economic interest of 84.582% in this Joint Venture Company. This interest was<br />
reduced from 86.66% in December 2011 following <strong>the</strong> receipt of cash calls from Pac LNG.<br />
All costs incurred in connection with <strong>the</strong> LNG Project, subsequent <strong>to</strong> <strong>the</strong> execution of <strong>the</strong> shareholders’ agreement governing<br />
<strong>the</strong> development of <strong>the</strong> midstream facilities of <strong>the</strong> LNG Project on July 31, 2007, and through <strong>the</strong> pre-acquisition and<br />
feasibility stage have been expensed as incurred, unless <strong>the</strong>y were directly identified as property, plant and equipment. Since<br />
<strong>the</strong> execution of <strong>the</strong> LNG Project Agreement with <strong>the</strong> State in December 2009, all project-related direct costs have been<br />
capitalized, o<strong>the</strong>r than overheads and o<strong>the</strong>r costs that are incurred in <strong>the</strong> normal course of running <strong>the</strong> business, which are<br />
expensed.<br />
39
The following analysis outlines <strong>the</strong> key movements, <strong>the</strong> net of which primarily explains <strong>the</strong> variance in <strong>the</strong> results between <strong>the</strong><br />
years and quarters ended December 31, 2011 and 2010.<br />
Yearly Variance<br />
($ millions)<br />
Quarterly Variance<br />
($ millions)<br />
($7.1) ($2.5) Net profit/(loss) variance for <strong>the</strong> comparative periods primarily due <strong>to</strong>:<br />
($7.7) ($3.1) Increase in office, administration and o<strong>the</strong>r expenses for <strong>the</strong> year due <strong>to</strong> higher management<br />
expenses and share compensation costs related <strong>to</strong> <strong>the</strong> midstream facilities of <strong>the</strong> LNG Project<br />
development which are not capitalized. The increases are <strong>the</strong> result of increased activities<br />
undertaken <strong>to</strong> negotiate long term LNG offtake agreements, pre-feed work being undertaken for<br />
<strong>the</strong> LNG Project’s proposed land based liquefaction and fixed-floating liquefaction facilities, and<br />
also fur<strong>the</strong>r <strong>the</strong> discussions with <strong>the</strong> State <strong>to</strong> achieve approvals.<br />
$0.6 $0.6 Gain on proportionate consolidation of PNG LNG following a reduction in ownership from 86.66%<br />
<strong>to</strong> 84.582% in December 2011.<br />
Downstream - Year and Quarter in Review<br />
Midstream Refining – Operating results<br />
($ thousands)<br />
Year ended December 31,<br />
2011 2010<br />
External sales 743,663 504,303<br />
Inter-segment revenue - Sales 197 483<br />
Interest and o<strong>the</strong>r revenue 1,263 1,072<br />
Total segment revenue 745,123 505,858<br />
Cost of sales and operating expenses (704,213) (470,772)<br />
Office and administration and o<strong>the</strong>r expenses (15,780) (15,975)<br />
Foreign exchange loss (229) (1,176)<br />
EBITDA (1) 24,901 17,935<br />
Depreciation and amortization (4,026) (2,787)<br />
Interest expense (4,346) (3,739)<br />
Profit before income taxes 16,529 11,409<br />
Income tax expense (4,962) (4,701)<br />
Net profit 11,567 6,708<br />
Gross Margin (2) 39,647 34,014<br />
1 EBITDA is a non-GAAP measure and is reconciled <strong>to</strong> IFRS in <strong>the</strong> section <strong>to</strong> this document entitled “Non-GAAP Measures and Reconciliation”.<br />
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<br />
<strong>to</strong> IFRS in <strong>the</strong> section <strong>to</strong> this document entitled “Non-GAAP Measures and Reconciliation”.<br />
Downstream Operating Review<br />
Key Refining Metrics<br />
Quarter ended December 31, Quarter ended December 31,<br />
2011 2010 2011 2010<br />
Sales volumes (millions of liters) 187.7 170.2 678.0 626.5<br />
Average sales price per liter (PGK) 2.43 2.07 2.55 2.19<br />
Analysis of Downstream Financial Results Comparing <strong>the</strong> Year and Quarter Ended December 31, 2011 and 2010<br />
The following analysis outlines <strong>the</strong> key movements, <strong>the</strong> net of which primarily explains <strong>the</strong> variance in <strong>the</strong> results between <strong>the</strong><br />
years and quarters ended December 31, 2011 and 2010.<br />
40
Yearly Variance<br />
($ millions)<br />
Quarterly Variance<br />
($ millions)<br />
$4.9 $1.0 Net profit/(loss) variance for <strong>the</strong> comparative periods primarily due <strong>to</strong>:<br />
$5.6 ($0.1) Gross margins increased compared <strong>to</strong> <strong>the</strong> prior year mainly due <strong>to</strong> an increase in domestic sales<br />
volumes resulting from various development projects being undertaken in Papua New Guinea, <strong>the</strong><br />
impact of <strong>the</strong> revised pricing formula that came in<strong>to</strong> effect in late 2010, and <strong>the</strong> increasing price<br />
environment during <strong>the</strong> period leading <strong>to</strong> higher margins on inven<strong>to</strong>ries sold.<br />
$0.9 $1.8 Increase in foreign exchange gain due <strong>to</strong> <strong>the</strong> streng<strong>the</strong>ning of <strong>the</strong> PGK against <strong>the</strong> USD. The PGK<br />
streng<strong>the</strong>ned against <strong>the</strong> USD from 0.3785 at <strong>the</strong> start of <strong>the</strong> year <strong>to</strong> 0.4665 as at December 31,<br />
2011.<br />
($1.2) ($0.7) Increase in depreciation and amortization expenses due <strong>to</strong> <strong>the</strong> impact of capital additions over <strong>the</strong><br />
past year related primarily <strong>to</strong> office refurbishment and upgrade projects across various terminals<br />
and depots.<br />
($0.6) ($0.3) Increase in interest expense due <strong>to</strong> <strong>the</strong> increased utilization of <strong>the</strong> working capital facility during <strong>the</strong><br />
year.<br />
Corporate - Year and Quarter in Review<br />
Corporate – Operating results<br />
($ thousands)<br />
Year ended December 31,<br />
2011 2010<br />
External sales 266 -<br />
Inter-segment revenue - Sales 13,859 402<br />
Inter-segment revenue - Recharges 39,503 32,162<br />
Interest revenue 38,512 24,335<br />
O<strong>the</strong>r non-allocated revenue (23) 23<br />
Total revenue 92,117 56,922<br />
Cost of sales and operating expenses (11,421) -<br />
Office and administration and o<strong>the</strong>r expenses (47,371) (40,291)<br />
Derivative (loss)/gain (11) 527<br />
Foreign exchange gain 954 1,051<br />
Loss on Flex LNG investment (3,420) -<br />
Litigation settlement expense - (12,000)<br />
EBITDA (1) 30,848 6,209<br />
Depreciation and amortization (1,706) (106)<br />
Interest expense (6,012) (1,541)<br />
Profit before income taxes 23,130 4,562<br />
Income tax expense (1,248) (1,240)<br />
Net profit 21,882 3,322<br />
1 EBITDA is a non-GAAP measure and is reconciled <strong>to</strong> IFRS in <strong>the</strong> section <strong>to</strong> this document entitled “Non-GAAP Measures and Reconciliation”.<br />
Analysis of Corporate Financial Results Comparing <strong>the</strong> Year and Quarter Ended December 31, 2011 and 2010<br />
During 2011, our Corporate segment <strong>to</strong>ok over <strong>the</strong> management of our shipping business from Downstream operations. We<br />
currently operate two vessels transporting petroleum products for our Downstream segment and external cus<strong>to</strong>mers, both<br />
within PNG and for export in <strong>the</strong> South Pacific region. External sales above relates <strong>to</strong> <strong>the</strong> shipping charges billed <strong>to</strong> external<br />
cus<strong>to</strong>mers, and inter-segment revenue - sales relates <strong>to</strong> shipping charges billed <strong>to</strong> our Downstream segment.<br />
The following analysis outlines <strong>the</strong> key movements, <strong>the</strong> net of which primarily explains <strong>the</strong> variance in <strong>the</strong> results between <strong>the</strong><br />
years and quarters ended December 31, 2011 and 2010.<br />
41
Yearly Variance<br />
($ millions)<br />
Quarterly Variance<br />
($ millions)<br />
$18.6 $4.2 Net profit/(loss) variance for <strong>the</strong> comparative periods primarily due <strong>to</strong>:<br />
$12.0 - One time litigation settlement expense in <strong>the</strong> prior year on account of <strong>the</strong> agreed settlement of <strong>the</strong><br />
Todd Peters et al litigation for which we issued 199,677 common shares <strong>to</strong> <strong>the</strong> plaintiffs.<br />
($3.4) ($1.6) Loss recognized on our investment in shares in Flex LNG held by us as part of <strong>the</strong> framework<br />
agreements entered in<strong>to</strong> with FLEX LNG and Samsung Heavy Industries in April 2011. As per <strong>the</strong><br />
guidance under IFRS, an impairment loss has <strong>to</strong> be recognized in <strong>the</strong> income statement if<br />
reduction in fair value of <strong>the</strong> investment is evidenced by significant or prolonged declined in <strong>the</strong> fair<br />
value of <strong>the</strong> investment.<br />
$9.7 $4.6 Reduced interest expenses (net of recharged intercompany interest revenue from o<strong>the</strong>r segments)<br />
due <strong>to</strong> higher interest charges <strong>to</strong> o<strong>the</strong>r business segments on increased loan balances.<br />
($0.1) $0.6 Movement in foreign exchange gain mainly in relation <strong>to</strong> <strong>the</strong> streng<strong>the</strong>ning of <strong>the</strong> AUD and SGD<br />
against <strong>the</strong> USD.<br />
Consolidated Adjustments - Year and Quarter in Review<br />
Consolidation adjustment – Operating results<br />
($ thousands)<br />
Year ended December 31,<br />
2011 2010<br />
Inter-segment revenue - Sales (590,729) (376,951)<br />
Inter-segment revenue - Recharges (48,344) (35,440)<br />
Interest revenue (5) (38,010) (24,281)<br />
O<strong>the</strong>r non-allocated revenue - -<br />
Total revenue (677,083) (436,672)<br />
Cost of sales and operating expenses (1) 592,527 374,818<br />
Office and administration and o<strong>the</strong>r expenses (2) 48,541 36,325<br />
EBITDA (3) (36,015) (25,529)<br />
Depreciation and amortization (4) 130 130<br />
Interest expense (5) 38,010 24,282<br />
Profit/(loss) before income taxes 2,125 (1,117)<br />
Income tax expense - -<br />
Net profit/(loss) 2,125 (1,117)<br />
Gross Margin (6) 1,798 (2,133)<br />
1 Represents <strong>the</strong> elimination upon consolidation of our refinery sales <strong>to</strong> o<strong>the</strong>r segments and o<strong>the</strong>r minor inter-company product sales.<br />
2 Includes <strong>the</strong> elimination of inter-segment administration service fees.<br />
3 EBITDA is a non-GAAP measure and is reconciled <strong>to</strong> IFRS in <strong>the</strong> section <strong>to</strong> this document entitled “Non-GAAP Measures and Reconciliation”.<br />
4 Represents <strong>the</strong> amortization of a portion of costs capitalized <strong>to</strong> assets on consolidation.<br />
5 Includes <strong>the</strong> elimination of interest accrued between segments.<br />
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<br />
consolidation of our refinery sales <strong>to</strong> o<strong>the</strong>r segments. This measure is reconciled <strong>to</strong> IFRS in <strong>the</strong> section <strong>to</strong> this document entitled “Non-GAAP Measures and<br />
Reconciliation”.<br />
Analysis of Consolidation Adjustments Comparing <strong>the</strong> Year and Quarter Ended December 31, 2011 and 2010<br />
The following table outlines <strong>the</strong> key movements, <strong>the</strong> net of which primarily explains <strong>the</strong> variance in <strong>the</strong> results between <strong>the</strong><br />
years and quarters ended December 31, 2011 and 2010.<br />
Yearly Variance<br />
($ millions)<br />
Quarterly Variance<br />
($ millions)<br />
$3.2 $0.7 Net profit/(loss) variance for <strong>the</strong> comparative periods primarily due <strong>to</strong>:<br />
$3.2 $0.7 Variance in net income due <strong>to</strong> changes in intra-group profit eliminated on consolidation between<br />
Midstream Refining and Downstream segments in <strong>the</strong> prior periods relating <strong>to</strong> <strong>the</strong> Midstream<br />
Refining segment’s profit component of inven<strong>to</strong>ry on hand in <strong>the</strong> Downstream segment at period<br />
ends.<br />
Liquidity and Capital Resources<br />
Summary of Debt Facilities<br />
42
Summarized below are <strong>the</strong> debt facilities available <strong>to</strong> us and <strong>the</strong> balances outstanding as at December 31, 2011.<br />
Organization<br />
Facility<br />
Balance outstanding<br />
December 31, 2011<br />
Effective interest rate Maturity date<br />
OPIC secured loan $35,500,000 $35,500,000 6.93% December 2015<br />
BNP Paribas working capital facility $260,000,000 (2) $10,030,131 (1) 3.38% January 2012 (3)<br />
Westpac PGK working capital facility $37,320,000 (4) $6,450,372 9.65% November 2014<br />
BSP PGK working capital facility $23,325,000 $0 9.47% August 2012<br />
2.75% convertible notes $70,000,000 $70,000,000 7.91% (6) November 2015<br />
Mitsui unsecured loan (5) $10,393,023 $10,393,023 6.23% See detail below<br />
1 Excludes letters of credit <strong>to</strong>taling $164.9 million, which reduce <strong>the</strong> available balance of <strong>the</strong> facility <strong>to</strong> $85.1 million at December 31, 2011.<br />
2 The facility was increased by $30.0 million during <strong>the</strong> quarter ended March 31, 2011 from $190.0 million <strong>to</strong> $220.0 million, and was <strong>the</strong>n increased by a fur<strong>the</strong>r<br />
$10.0 million during <strong>the</strong> quarter ended June 30, 2011 <strong>to</strong> $230.0 million. During <strong>the</strong> quarter ended December 31, 2011 <strong>the</strong>re was a temporary $30.0 million<br />
increase <strong>to</strong> $260.0 million. The facility reverted back <strong>to</strong> a maximum availability of $230.0 million at <strong>the</strong> end of January 2012.<br />
3 The facility was extended after <strong>the</strong> end of <strong>the</strong> year, and it now matures on January 31, 2013.<br />
4 Subsequent <strong>to</strong> <strong>the</strong> year end, <strong>the</strong> limit on this facility was increased by approximately $4.7 million, with a new limit of approximately $42.0 million.<br />
5 Facility is <strong>to</strong> fund our share of <strong>the</strong> Condensate Stripping Project costs as <strong>the</strong>y are incurred pursuant <strong>to</strong> <strong>the</strong> JVOA.<br />
6 Effective rate after bifurcating <strong>the</strong> equity and debt components of <strong>the</strong> $70 million principal amount of 2.75% convertible senior notes due 2015.<br />
OPIC Secured Loan (Midstream Refinery)<br />
In 2001, one of our subsidiaries entered in<strong>to</strong> a loan agreement with OPIC for provision of an $85.0 million project financing<br />
facility for <strong>the</strong> development of our refinery in PNG. The loan is primarily secured by <strong>the</strong> assets of <strong>the</strong> refinery. On June 20,<br />
2011, OPIC signed agreements agreeing <strong>to</strong> release all of <strong>the</strong> sponsor support collateral and requirements for <strong>the</strong> loan granted<br />
in 2001 in recognition of our financial and operational maturity. The balance outstanding under <strong>the</strong> loan as at December 31,<br />
2011 was $35.5 million. The interest rate on <strong>the</strong> loan is equal <strong>to</strong> <strong>the</strong> agreed U.S. Government treasury cost applicable <strong>to</strong> each<br />
promissory note that was issued and is outstanding plus 3%, and is payable quarterly in arrears. Principal repayments of $4.5<br />
million each are due on June 30 and December 31 of each year until December 31, 2015. At December 31, 2011, $5.9<br />
million was, and is still, being held on deposit <strong>to</strong> secure our June 30, 2012 principal and interest payments on <strong>the</strong> secured<br />
loan.<br />
BNP Paribas Working Capital Facility (Midstream Refinery)<br />
This working capital facility is used <strong>to</strong> finance purchases of crude feeds<strong>to</strong>ck for our refinery. In accordance with <strong>the</strong> agreement<br />
with BNP Paribas, <strong>the</strong> <strong>to</strong>tal facility is split in<strong>to</strong> two components, Facility 1 and Facility 2 which are renewable annually. At<br />
December 31, 2011, Facility 1 had a limit of $200.0 million (increased temporarily from $170.0 million during <strong>the</strong> quarter<br />
ended December 31, 2011) and finances <strong>the</strong> purchases of crude and hydrocarbon products through <strong>the</strong> issuance of<br />
documentary letters of credit and standby letters of credit, short term advances, advances on merchandise, freight loans, and<br />
has a sublimit of Euro 18.0 million or <strong>the</strong> USD equivalent for hedging transactions. At January 31, 2012, <strong>the</strong> limit on Facility 1<br />
reverted back <strong>to</strong> $170.0 million. Facility 2 allows borrowings of up <strong>to</strong> $60.0 million and can be used for partly cash-secured<br />
short term advances and for discounting of any monetary receivables acceptable <strong>to</strong> BNP Paribas in order <strong>to</strong> reduce Facility 1<br />
balances. The facility is secured by sales contracts, purchase contracts, certain cash accounts associated with <strong>the</strong> refinery, all<br />
crude and refined products of <strong>the</strong> refinery and trade receivables.<br />
As of December 31, 2011, $85.1 million remained available for use under <strong>the</strong> facility. The facility bears interest at LIBOR plus<br />
3.5% on short term advances. The weighted average interest rate under <strong>the</strong> working capital facility was 3.38% for <strong>the</strong> year<br />
ended December 31, 2011 (compared with 2.69% for <strong>the</strong> same period of 2010), after including <strong>the</strong> reduction in interest due<br />
<strong>to</strong> <strong>the</strong> deposit amounts (restricted cash) maintained as security.<br />
Bank South Pacific and Westpac Working Capital Facility (Downstream)<br />
On Oc<strong>to</strong>ber 24, 2008, we secured a PGK 150.0 million (approximately $70.0 million) combined revolving working capital<br />
facility for our Downstream wholesale and retail petroleum products distribution business from Bank of South Pacific Limited<br />
and Westpac Bank PNG Limited. The facility limit as at December 31, 2011 was PGK 130.0 million (approximately $60.6<br />
million).<br />
The Westpac facility limit is PGK 80.0 million (approximately $37.3 million). This facility was for an initial term of three years<br />
and was renewed in November 2011 for a fur<strong>the</strong>r three years <strong>to</strong> November 2014. Subsequent <strong>to</strong> year end, <strong>the</strong> limit of this<br />
facility was increased by PGK 10.0 million (approximately $4.7 million) with an increased limit of PGK 90.0 million<br />
(approximately $42.0 million). In addition, a secured loan of $15.0 million was provided as part of this increased facility which<br />
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<br />
PGK 50.0 million (approximately $23.3 million), and was renewed in August 2011 for ano<strong>the</strong>r year. As at December 31, 2011,<br />
PGK 13.8 million (approximately $6.5 million) of this combined facility had been utilized.<br />
The weighted average interest rate under <strong>the</strong> Westpac facility was 10.0% for <strong>the</strong> quarter and 9.65% for <strong>the</strong> year ended<br />
December 31, 2011, while <strong>the</strong> weighted average interest rate under <strong>the</strong> BSP facility was 9.94% for <strong>the</strong> quarter and 9.47% for<br />
<strong>the</strong> year ended December 31, 2011.<br />
2.75% Convertible Notes (Corporate)<br />
On November 10, 2010, we <strong>complete</strong>d <strong>the</strong> issuance of $70.0 million unsecured 2.75% convertible notes with a maturity of<br />
five years. The convertible notes rank junior <strong>to</strong> any secured indebtedness and <strong>to</strong> all existing and future liabilities of us and our<br />
subsidiaries, including <strong>the</strong> BNP Paribas working capital facility, <strong>the</strong> OPIC secured loan facility, <strong>the</strong> BSP and Westpac working<br />
capital facilities, <strong>the</strong> Mitsui preliminary financing agreement, trade payables and lease obligations.<br />
We pay interest on <strong>the</strong> notes semi-annually on May 15 and November 15. The notes are convertible in<strong>to</strong> cash or common<br />
shares, based on an initial conversion rate of 10.4575 common shares per $1,000 principal amount, which represents an<br />
initial conversion price of approximately $95.625 per common share. The initial conversion price is subject <strong>to</strong> standard<br />
anti-dilution provisions designed <strong>to</strong> maintain <strong>the</strong> value of <strong>the</strong> conversion option in <strong>the</strong> event we take certain actions with<br />
respect <strong>to</strong> our common shares, such as s<strong>to</strong>ck splits, reverse s<strong>to</strong>ck splits, s<strong>to</strong>ck dividends and cash dividends, that affect all<br />
of <strong>the</strong> holders of our common shares equally and that could have a dilutive effect on <strong>the</strong> value of <strong>the</strong> conversion rights of <strong>the</strong><br />
holders of <strong>the</strong> notes or that confer a benefit upon our current shareholders not o<strong>the</strong>rwise available <strong>to</strong> <strong>the</strong> convertible notes.<br />
Upon conversion, holders will receive cash, common shares or a combination <strong>the</strong>reof, at our option. The convertible notes<br />
are redeemable at our option if our share price has been at least 125% ($119.53 per share) of <strong>the</strong> conversion price for at least<br />
15 trading days during any 20 consecutive trading day period. Upon a fundamental change, which would include a change<br />
of control, holders may require us <strong>to</strong> repurchase <strong>the</strong>ir convertible notes for cash at a purchase price equal <strong>to</strong> <strong>the</strong> principal<br />
amount of <strong>the</strong> notes <strong>to</strong> be repurchased, plus accrued and unpaid interest.<br />
Mitsui Unsecured Loan (Upstream)<br />
On April 15, 2010, we entered in<strong>to</strong> preliminary joint venture and financing agreements with Mitsui relating <strong>to</strong> <strong>the</strong> Condensate<br />
Stripping Project. On August 4, 2010, we entered in<strong>to</strong> <strong>the</strong> Condensate Stripping Project Joint Venture with Mitsui for <strong>the</strong><br />
condensate stripping facilities. Mitsui and <strong>InterOil</strong> hold equal interest in <strong>the</strong> joint venture. Mitsui is <strong>to</strong> be responsible for<br />
arranging or providing financing for <strong>the</strong> capital costs of <strong>the</strong> condensate stripping facility.<br />
The portion of funding that relates <strong>to</strong> Mitsui’s share of <strong>the</strong> Condensate Stripping Project as at December 31, 2011,<br />
amounting <strong>to</strong> approximately $11.4 million, is held in current liabilities as <strong>the</strong> agreement requires refund of all funds advanced<br />
by Mitsui under <strong>the</strong> preliminary financing agreement if a positive FID is not reached. The portion of funding that relates <strong>to</strong> our<br />
share of <strong>the</strong> Condensate Stripping Project (amounting <strong>to</strong> $10.4 million), funded by Mitsui, is classed as an unsecured loan and<br />
interest accrues daily based on LIBOR plus a margin of 6%.<br />
While cash flows from operations are expected <strong>to</strong> be sufficient <strong>to</strong> cover our operating commitments, should <strong>the</strong>re be a major<br />
long term deterioration in refining or wholesale and retail margins, our operations may not generate sufficient cash flows <strong>to</strong><br />
cover all of <strong>the</strong> interest and principal payments under our debt facilities noted above. Also, our exploration and development<br />
activities require funding beyond our operational cash flows and <strong>the</strong> cash balances we currently hold. As a result, we will be<br />
required <strong>to</strong> raise additional capital and/or refinance <strong>the</strong>se facilities in <strong>the</strong> future. We can provide no assurances that we will<br />
be able <strong>to</strong> obtain such additional capital or that our lenders will agree <strong>to</strong> refinance <strong>the</strong>se debt facilities, or, if available, that <strong>the</strong><br />
terms of any such capital raising or refinancing will be acceptable <strong>to</strong> us.<br />
O<strong>the</strong>r Sources of Capital<br />
Currently our share of expenditures on exploration wells, appraisal wells and extended well programs is funded by a<br />
combination of contributions made by capital raising activities, operational cash flows, IPI inves<strong>to</strong>rs and asset sales.<br />
Cash calls are made on IPI inves<strong>to</strong>rs and Pac LNG (for its 2.5% direct interest in <strong>the</strong> Elk and Antelope field acquired during<br />
2009) for <strong>the</strong>ir share of amounts spent on certain appraisal wells and extended well programs where <strong>the</strong>y participate in such<br />
wells and programs pursuant <strong>to</strong> <strong>the</strong> relevant agreements in place with <strong>the</strong>m.<br />
44
Summary of Cash Flows<br />
($ Thousands)<br />
Year ended December 31,<br />
2011 2010 2009<br />
Net cash inflows/(outflows) from:<br />
Operations 62,670 (13,561) 44,500<br />
Investing (204,241) (111,158) (85,567)<br />
Financing (27,165) 311,846 38,546<br />
Net cash movement (168,736) 187,127 (2,521)<br />
Opening cash 233,577 46,450 48,971<br />
Exchange gains on cash and cash equivalents 4,005 - -<br />
Closing cash 68,846 233,577 46,450<br />
Analysis of Cash Flows Provided By/(Used In) Operating Activities Comparing <strong>the</strong> Years ended December 31, 2011<br />
and 2010<br />
The following table outlines <strong>the</strong> key variances in <strong>the</strong> cash flows from operating activities between <strong>the</strong> years ended December<br />
31, 2011 and 2010:<br />
Yearly Variance<br />
($ millions)<br />
$76.2 Variance for <strong>the</strong> comparative periods primarily due <strong>to</strong>:<br />
$26.1 Increase in cash generated by operations prior <strong>to</strong> changes in operating working capital for <strong>the</strong> year ended December<br />
31, 2011, mainly due <strong>to</strong> <strong>the</strong> increased profits from operations adjusted for non cash items mainly relating <strong>to</strong> <strong>the</strong> loss<br />
on extinguishment of IPI liability and non cash litigation settlement expense in <strong>the</strong> prior year.<br />
$50.1 Decrease in cash used by operations relating <strong>to</strong> changes in operating working capital. The decrease in cash used for<br />
<strong>the</strong> year is due primarily <strong>to</strong> a $28.0 million decrease in inven<strong>to</strong>ries due <strong>to</strong> timing of crude and export shipments and a<br />
$71.6 million increase in accounts payable and accrued liabilities, partially offset by a $43.8 million increase in trade<br />
receivables.<br />
Analysis of Cash Flows Provided By/(Used In) Investing Activities Comparing <strong>the</strong> Years Ended December 31, 2011<br />
and 2010<br />
The following table outlines <strong>the</strong> key variances in <strong>the</strong> cash flows from investing activities between <strong>the</strong> years ended December<br />
31, 2011 and 2010:<br />
Yearly Variance<br />
($ millions)<br />
($93.1) Variance for <strong>the</strong> comparative periods primarily due <strong>to</strong>:<br />
($21.8) Higher cash outflows on exploration and development program expenditures related <strong>to</strong> seismic activity on PPL 236<br />
and PPL 237, FEED work for <strong>the</strong> Condensate Stripping Project and LNG Project, and site preparations for <strong>the</strong><br />
Tricera<strong>to</strong>ps 2 field appraisal well.<br />
($23.0) Lower cash calls and related inflows from IPI inves<strong>to</strong>rs due <strong>to</strong> activity being focused on seismic activities, for which<br />
no contribution is required, ra<strong>the</strong>r than appraisal drilling and subsequent work program activities.<br />
($19.5) Higher expenditure on plant and equipment. The expenditures were mainly associated with refurbishment of retail<br />
sites, tank upgrades, camp and office refurbishments and, less significantly, relocation of <strong>the</strong> corporate offices in<br />
PNG and Australia.<br />
($15.5) Receipt in 2010 of <strong>the</strong> final installment of $13.9 million relating <strong>to</strong> <strong>the</strong> sale of 2.5% direct working interest in <strong>the</strong> Elk<br />
and Antelope fields <strong>to</strong> Pac LNG in September 2009 and $1.6 million proceeds from <strong>the</strong> sale of our interest in PPL<br />
244.<br />
($11.8) Investment in short term PGK Treasury bills.<br />
($7.5) Acquisition of FLEX LNG shares net of transaction costs.<br />
$26.0 Higher cash inflows due <strong>to</strong> reduction in our cash restricted balances in line with <strong>the</strong> usage of <strong>the</strong> BNP working<br />
capital facility.<br />
($20.0) Increase in cash used in our Upstream segment for working capital requirements. This working capital relates <strong>to</strong><br />
movements in accounts receivable, accounts payable and accruals in our Upstream and Midstream Liquefaction<br />
operations.<br />
45
Analysis of Cash Flows Provided By/(Used In) Financing Activities Comparing <strong>the</strong> Years Ended December 31, 2011 and<br />
2010<br />
The following table outlines <strong>the</strong> key variances in <strong>the</strong> cash flows from financing activities between years ended December 31,<br />
2011 and 2010:<br />
Yearly Variance<br />
($ millions)<br />
($339.0) Variance for <strong>the</strong> comparative periods primarily due <strong>to</strong>:<br />
($61.4) Higher repayments of <strong>the</strong> BNP Paribas working capital facility due <strong>to</strong> increased working capital requirements.<br />
($206.7) Net proceeds after transaction costs from <strong>the</strong> issuance of shares relating <strong>to</strong> <strong>the</strong> issuance of 2,800,000 common<br />
shares in November 2010.<br />
($66.3) Net proceeds after transaction costs from <strong>the</strong> issuance of $70.0 million of 2.75% convertible notes in November<br />
2010.<br />
$1.4 Proceeds received from Pac LNG for its share of costs incurred in developing <strong>the</strong> LNG Project.<br />
($2.0) Reduction in funding received from Mitsui relating <strong>to</strong> <strong>the</strong> Condensate Stripping Project.<br />
($5.0) Proceeds received from Petromin for contributions <strong>to</strong>wards cash calls made with respect <strong>to</strong> development activities<br />
for <strong>the</strong> Elk and Antelope fields. No proceeds were received during 2011.<br />
Capital Expenditures<br />
Upstream Capital Expenditures<br />
Capital expenditures for exploration in Papua New Guinea for <strong>the</strong> year <strong>to</strong> December 31, 2011 were $107.6 million, compared<br />
with $82.8 million during <strong>the</strong> same period of 2010.<br />
The following table outlines <strong>the</strong> key expenditures in <strong>the</strong> year ended December 31, 2011:<br />
Yearly Variance<br />
($ millions)<br />
$107.6 Expenditures in <strong>the</strong> year ended December 31, 2011 primarily due <strong>to</strong>:<br />
$7.1 Completion costs on <strong>the</strong> Antelope-2 well, mainly relating <strong>to</strong> expenditure on our drilling rig necessitated by corrosion<br />
caused by <strong>the</strong> use of drilling mud used <strong>to</strong> conduct <strong>the</strong> side tracks and <strong>complete</strong> <strong>the</strong> well.<br />
$16.9 Costs for early works in respect of <strong>the</strong> Condensate Stripping Project.<br />
$24.2 Costs associated with <strong>the</strong> Tricera<strong>to</strong>ps 2 well relating <strong>to</strong> pre-spud and standby costs.<br />
$16.7 Costs for <strong>the</strong> construction of a road from our Antelope field <strong>to</strong> our river-based logistics hub on <strong>the</strong> Purari river.<br />
$6.2 Capital works costs on infrastructure at <strong>the</strong> river based logistics hub.<br />
$36.5 O<strong>the</strong>r expenditures, including heavy equipment purchases and drilling inven<strong>to</strong>ry.<br />
IPI inves<strong>to</strong>rs and Pac LNG (2.5% direct interest in Elk and Antelope fields) are presently required <strong>to</strong> fund 24.3886% of <strong>the</strong><br />
Elk and Antelope fields extended well program costs <strong>to</strong> maintain <strong>the</strong>ir interest in those fields. The amounts capitalized in our<br />
books, or expensed as incurred, in relation <strong>to</strong> <strong>the</strong> extended well program are <strong>the</strong> net amounts after adjusting for <strong>the</strong>se<br />
interests.<br />
Petromin had agreed <strong>to</strong> fund 20.5% of ongoing costs for developing <strong>the</strong> fields. There were no contributions from Petromin<br />
during <strong>the</strong> year ended December 31, 2011 and <strong>the</strong>refore <strong>the</strong> <strong>to</strong>tal advance payment received from Petromin remains at $15.4<br />
million. At <strong>the</strong> end of <strong>the</strong> 2011 year, <strong>the</strong> parties agreed that <strong>the</strong> investment agreement between Petromin and <strong>InterOil</strong><br />
governing Petromin’s participation in <strong>the</strong> Elk and Antelope fields should terminate. Petromin remains <strong>the</strong> State’s nominee <strong>to</strong><br />
acquire <strong>the</strong> State’s interest in <strong>the</strong> Elk and Antelope fields under relevant Papua New Guinean legislation, once a PDL is<br />
granted. We have proposed that cash contributions made by Petromin <strong>to</strong> date <strong>to</strong> fund <strong>the</strong> development will be held and<br />
credited against <strong>the</strong> State’s obligation <strong>to</strong> contribute its portion of sunk costs upon grant of <strong>the</strong> PDL.<br />
The preliminary financing agreement entered in<strong>to</strong> with Mitsui provides for funding by Mitsui of all <strong>the</strong> costs relating <strong>to</strong> <strong>the</strong><br />
Condensate Stripping Project. 50% of <strong>the</strong> funding is for Mitsui’s share of <strong>the</strong> project and <strong>the</strong> o<strong>the</strong>r 50% is funding by Mitsui<br />
of all <strong>the</strong> costs relating <strong>to</strong> <strong>the</strong> Condensate Stripping Project. 50% of <strong>the</strong> funding is for Mitsui’s share of <strong>the</strong> project and <strong>the</strong><br />
o<strong>the</strong>r 50% is funding by Mitsui of our share of <strong>the</strong> project. Mitsui contributed $9.9 million during <strong>the</strong> year for both Mitsui’s and<br />
our share, and has contributed $21.8 million in aggregate. In <strong>the</strong> event that a positive FID is not reached or made, we will be<br />
required <strong>to</strong> refund all of Mitsui’s contributions (i.e. for our share and Mitsui’s) within a specified period.<br />
46
Midstream Capital Expenditures<br />
Capital expenditures <strong>to</strong>taled $15.9 million in our Midstream Refining segment for <strong>the</strong> year ended December 31, 2011, mainly<br />
associated with camp and office building works, mo<strong>to</strong>r vehicles and heavy pumper tanker purchases.<br />
Following <strong>the</strong> signing of <strong>the</strong> LNG Project Agreement with <strong>the</strong> State in December 2009, $5.3 million of costs incurred during<br />
<strong>the</strong> year in relation <strong>to</strong> <strong>the</strong> Midstream - Liquefaction segment have been capitalized.<br />
Downstream Capital Expenditures<br />
Capital expenditures for <strong>the</strong> Downstream segment <strong>to</strong>taled $10.2 million for <strong>the</strong> year ended December 31, 2011. These<br />
expenditures mainly related <strong>to</strong> a number of upgrade projects across various terminals and depots, and office refurbishments.<br />
Corporate Capital Expenditures<br />
Capital expenditures for <strong>the</strong> Corporate segment <strong>to</strong>taled $3.1 million for <strong>the</strong> year ended December 31, 2011. These<br />
expenditures mainly related <strong>to</strong> project costs in relation <strong>to</strong> <strong>the</strong> new business system implementation in <strong>the</strong> Downstream<br />
business and costs associated with relocation of <strong>the</strong> corporate office in Cairns, Australia.<br />
Capital Requirements<br />
The oil and gas exploration and development, refining and liquefaction industries are capital intensive and our business plans<br />
necessarily involve raising additional capital. The availability and cost of such capital is highly dependent on market conditions<br />
at <strong>the</strong> time we raise such capital. No assurance can be given that we will be successful in obtaining new capital on terms that<br />
are acceptable <strong>to</strong> us, particularly given current market volatility.<br />
The majority of our “net cash from operating activities” adjusted for “proceeds from/(repayments of) working capital facilities”<br />
is used in our appraisal and development programs for <strong>the</strong> Elk and Antelope, and Tricera<strong>to</strong>ps fields in PNG. Our net cash<br />
from working activities is not sufficient <strong>to</strong> fund those appraisal and development programs.<br />
Upstream<br />
We are required under our $125.0 million IPI Agreement of 2005 <strong>to</strong> drill eight exploration wells. We have drilled four wells <strong>to</strong><br />
date. As at December 31, 2011, we are committed under <strong>the</strong> terms of our exploration licenses or PPL’s <strong>to</strong> spend a fur<strong>the</strong>r<br />
$61.9 million through 2015. As at December 31, 2011, management estimates that satisfying <strong>the</strong>se license commitments<br />
with <strong>the</strong> expenditure of $61.9 million would also satisfy our commitments <strong>to</strong> <strong>the</strong> IPI inves<strong>to</strong>rs in relation <strong>to</strong> drilling <strong>the</strong> final four<br />
wells and satisfy <strong>the</strong> commitments in relation <strong>to</strong> <strong>the</strong> IPI agreement.<br />
In addition, <strong>the</strong> terms of grant of PRL 15 require us <strong>to</strong> spend a fur<strong>the</strong>r $73.0 million on <strong>the</strong> development of <strong>the</strong> Elk and<br />
Antelope fields by <strong>the</strong> end of 2014.<br />
We do not have sufficient funds <strong>to</strong> <strong>complete</strong> planned exploration and development and we will need <strong>to</strong> raise additional funds<br />
in order for us <strong>to</strong> <strong>complete</strong> <strong>the</strong> programs and meet our exploration commitments. Therefore, we must extend or secure<br />
sufficient funding through renewed borrowings, equity raising and or asset sales <strong>to</strong> enable <strong>the</strong> availability of sufficient cash <strong>to</strong><br />
meet <strong>the</strong>se obligations over time and <strong>complete</strong> <strong>the</strong>se long term plans. No assurances can be given that we will be successful<br />
in obtaining new capital on terms acceptable <strong>to</strong> us, particularly given recent market volatility.<br />
We will also be required <strong>to</strong> obtain substantial amounts of financing for <strong>the</strong> development of <strong>the</strong> Elk and Antelope fields,<br />
condensate stripping and associated facilities, pipelines and LNG export terminal facilities, and it will take a number of years<br />
<strong>to</strong> <strong>complete</strong> <strong>the</strong>se projects. In <strong>the</strong> event that positive FID is reached in respect of <strong>the</strong>se projects, we seek <strong>to</strong> be in a position <strong>to</strong><br />
access <strong>the</strong> capital markets and/or sell an interest in our upstream properties in order <strong>to</strong> raise adequate capital. In September<br />
2011, we retained financial advisors <strong>to</strong> help solicit and evaluate proposals from potential strategic partners <strong>to</strong> acquire<br />
interests in our Elk and Antelope fields, LNG Project and exploration licenses. The solicitation process is now under way and<br />
we believe, it will, if successful, provide a fur<strong>the</strong>r source of funds for exploration and development activities. No assurances<br />
can be given that we will be able <strong>to</strong> attract strategic partners on terms acceptable <strong>to</strong> us.<br />
The availability and cost of various sources of financing is highly dependent on market conditions and our condition at <strong>the</strong><br />
time we raise such capital and we can provide no assurances that we will be able <strong>to</strong> obtain such financing or conduct such<br />
sales on terms that are acceptable.<br />
47
Midstream - Refining<br />
We believe that we will have sufficient funds from our operating cash flows <strong>to</strong> pay our estimated capital expenditures<br />
associated with our Midstream Refining segment in 2012. We also believe cash flows from operations will be sufficient <strong>to</strong><br />
cover <strong>the</strong> costs of operating our refinery and <strong>the</strong> financing charges incurred under our crude import facility. Should <strong>the</strong>re be a<br />
long term deterioration in refining margins, our refinery may not generate sufficient cash flows <strong>to</strong> cover all of <strong>the</strong> interest and<br />
principal payments under our secured loan agreements. As a result, we may be required <strong>to</strong> raise additional capital and/or<br />
refinance <strong>the</strong>se facilities in <strong>the</strong> future.<br />
Midstream - Liquefaction<br />
On September 28, 2010, we and LNGL (a wholly owned subsidiary of PNG LNG) signed a heads of agreement with EWC <strong>to</strong><br />
construct a three mtpa land based liquefaction facility in <strong>the</strong> Gulf Province of Papua New Guinea. Following this agreement,<br />
on February 2, 2011, <strong>the</strong> parties signed certain conditional framework agreements defining certain parameters for <strong>the</strong><br />
aforementioned development, construction, financing and <strong>the</strong> operation of <strong>the</strong> planned land-based liquefaction facilities.<br />
These facilities are intended <strong>to</strong> be developed in phases and fur<strong>the</strong>r definitive agreements are contemplated.<br />
The LNG facilities are intended <strong>to</strong> be developed in two phases, an initial two mtpa followed by a one mtpa expansion. In<br />
return for its commitment <strong>to</strong> fully fund <strong>the</strong> construction of <strong>the</strong> facilities, EWC is <strong>to</strong> be entitled <strong>to</strong> a fee of 14.5% of <strong>the</strong> proceeds<br />
from LNG revenue from <strong>the</strong>se facilities, less agreed deductions, and subject <strong>to</strong> adjustments based on timing and execution.<br />
On April 11, 2011, we and Pac LNG entered in<strong>to</strong> certain conditional framework agreements with FLEX LNG and Samsung<br />
Heavy Industries for <strong>the</strong> proposed construction of a 1.8 mtpa or 2 mtpa fixed-floating liquefied natural gas vessel. Such a<br />
vessel is expected <strong>to</strong> integrate with and augment <strong>the</strong> land-based modules <strong>to</strong> be developed with EWC. The framework<br />
agreements provided that <strong>the</strong> parties were <strong>to</strong> undertake project specific FEED work and negotiate final binding agreements in<br />
time for a FID decision in mid-December 2011. Project specific FEED work was carried out. However, as FID was not reached<br />
by mid-December 2011, <strong>the</strong>se framework agreements with FLEX LNG and Samsung lapsed and were not extended. We are<br />
continuing <strong>to</strong> negotiate with FLEX LNG.<br />
The fixed-floating project is intended <strong>to</strong> integrate with and augment proposed on-shore infrastructure <strong>to</strong> transport LNG from<br />
<strong>the</strong> onshore Elk and Antelope fields in <strong>the</strong> Gulf Province of Papua New Guinea pursuant <strong>to</strong> arrangements with EWC and<br />
Mitsui.<br />
In September 2011, we retained financial advisors <strong>to</strong> help solicit and evaluate proposals from potential strategic partners <strong>to</strong>,<br />
amongst o<strong>the</strong>r things, obtain an interest in, operate and help finance <strong>the</strong> development of <strong>the</strong> LNG Project. No assurances can<br />
be given that we will be able <strong>to</strong> attract strategic partners on terms acceptable <strong>to</strong> us, how such an agreement will affect our<br />
current LNG Project plans or whe<strong>the</strong>r such a partner will be acceptable <strong>to</strong> <strong>the</strong> PNG government.<br />
Completion of <strong>the</strong> LNG Project will require substantial amounts of financing and construction will take a number of years <strong>to</strong><br />
<strong>complete</strong>. As a joint venture partner in development, if <strong>the</strong> project is <strong>complete</strong>d, we would be required <strong>to</strong> fund our share of<br />
certain common facilities of <strong>the</strong> development. No assurances can be given that we will be able <strong>to</strong> source sufficient gas,<br />
successfully construct such a facility, or as <strong>to</strong> <strong>the</strong> timing of such construction. The availability and cost of capital is highly<br />
dependent on market conditions and our circumstances at <strong>the</strong> time we raise such capital.<br />
Downstream<br />
We believe on <strong>the</strong> basis of current market conditions and <strong>the</strong> status of our business that our cash flows from operations will<br />
be sufficient <strong>to</strong> meet our estimated capital expenditures for our wholesale and retail distribution business segment for 2012.<br />
Contractual Obligations and Commitments<br />
The following table contains information on payments required <strong>to</strong> meet contracted exploration and debt obligations due for<br />
each of <strong>the</strong> next five years and <strong>the</strong>reafter. It should be read in conjunction with our financial statements for <strong>the</strong> year ended<br />
December 31, 2011 and <strong>the</strong> notes <strong>the</strong>re<strong>to</strong>:<br />
48
Contractual obligations<br />
($ thousands)<br />
Payments Due by Period<br />
Total Less than 1 year 1 - 2 years 2 - 3 years 3 - 4 years 4 - 5 years<br />
More than<br />
5 years<br />
Petroleum prospecting and retention<br />
licenses (a) 134,900 44,400 36,350 44,050 9,900 200 -<br />
Secured and unsecured loans (b) 51,586 21,727 10,749 10,131 8,979 - -<br />
2.75% Convertible notes obligations 77,540 1,925 1,925 1,925 71,765 - -<br />
Indirect participation interest - PNGDV 1,384 540 844 - - - -<br />
Total 265,410 68,592 49,868 56,106 90,644 200 -<br />
A The amount pertaining <strong>to</strong> <strong>the</strong> petroleum prospecting and retention licenses represents <strong>the</strong> amount we have committed as a condition on renewal of <strong>the</strong>se<br />
licenses. We are committed <strong>to</strong> spend a fur<strong>the</strong>r $61.9 million as a condition of renewal of our petroleum prospecting licenses through 2014 under our exploration<br />
licenses. As at December 31, 2011, management estimates that satisfying this license commitment with <strong>the</strong> expenditure of $61.9 million would also satisfy our<br />
commitments <strong>to</strong> <strong>the</strong> IPI inves<strong>to</strong>rs in relation <strong>to</strong> drilling <strong>the</strong> final four wells and satisfy <strong>the</strong> commitments in relation <strong>to</strong> <strong>the</strong> IPI agreement. In addition, <strong>the</strong> terms of grant<br />
of PRL15, requires us <strong>to</strong> spend a fur<strong>the</strong>r $73.0 million on <strong>the</strong> development of <strong>the</strong> Elk and Antelope fields by <strong>the</strong> end of 2014.<br />
B The effective interest rate on <strong>the</strong>se loans for <strong>the</strong> year ended December 31, 2011 was 6.93%.<br />
The following table contains information on payments required <strong>to</strong> meet our operating lease commitments. It should be read in<br />
conjunction with our financial statements for <strong>the</strong> year ended December 31, 2011 and <strong>the</strong> notes <strong>the</strong>re<strong>to</strong>:<br />
($ Thousands)<br />
Year ended December 31,<br />
2011 2010<br />
Not later than 1 year 6,983 6,257<br />
Later than 1 year and not later than 5 years 6,560 8,558<br />
Later than 5 years 2,958 458<br />
Total 16,501 15,273<br />
Off Balance Sheet Arrangements<br />
Nei<strong>the</strong>r during <strong>the</strong> year ended, nor as at December 31, 2011, did we have any off balance sheet arrangements or any<br />
relationships with unconsolidated entities or financial partnerships.<br />
Transactions with Related Parties<br />
Petroleum Independent and Exploration <strong>Corporation</strong>, is owned by Mr. Mulacek, our Chairman and Chief Executive Officer.<br />
Prior <strong>to</strong> 2011, Petroleum Independent and Exploration <strong>Corporation</strong> received a management fee in its capacity as <strong>the</strong> General<br />
Manager of one of our subsidiaries, S.P. <strong>InterOil</strong> LDC, in compliance with OPIC loan requirements. During <strong>the</strong> year ended<br />
December 31, 2010, Petroleum Independent and Exploration <strong>Corporation</strong> received $150,000. On June 20, 2011, OPIC<br />
signed agreements agreeing <strong>to</strong> release all of <strong>the</strong> sponsor support collateral and requirements for <strong>the</strong> loan granted <strong>to</strong> us in<br />
2001 in recognition of our financial and operational maturity. As a result, no fees were paid <strong>to</strong> Petroleum Independent and<br />
Exploration <strong>Corporation</strong> in <strong>the</strong> year ended December 31, 2011. In November of 2011, we elected <strong>to</strong> exchange <strong>the</strong> 5,000<br />
shares held in S.P. <strong>InterOil</strong> LDC by Petroleum Independent and Exploration <strong>Corporation</strong> for 5,000 shares in <strong>InterOil</strong><br />
<strong>Corporation</strong>. The sponsor agreements were terminated with Petroleum Independent and Exploration <strong>Corporation</strong> on<br />
exchange of <strong>the</strong> share holding interest in S.P. <strong>InterOil</strong> LDC. Subsequent <strong>to</strong> year end, S.P. <strong>InterOil</strong> LDC has been renamed<br />
South Pacific Refining Limited.<br />
Breckland Limited, a company controlled by Mr. Roger Grundy, one of our direc<strong>to</strong>rs, previously provided technical and<br />
advisory services <strong>to</strong> us on normal commercial terms. Amounts paid or payable <strong>to</strong> Breckland for technical services during <strong>the</strong><br />
year ended December 31, 2011 amounted <strong>to</strong> $nil (December 2010 - $21,923).<br />
Share Capital<br />
Our authorized share capital consists of an unlimited number of common shares and unlimited number of preferred shares, of<br />
which 1,035,554 series A preferred shares are authorized (none of which are outstanding). As of December 31, 2011, we had<br />
48,121,071 common shares (50,833,593 common shares on a fully diluted basis) and no preferred shares outstanding. The<br />
potential dilutive instruments outstanding as at December 31, 2011 included employee s<strong>to</strong>ck options and restricted s<strong>to</strong>ck in<br />
respect of 1,640,017 common shares, IPI conversion rights <strong>to</strong> 340,480 common shares and 732,025 common shares<br />
relating <strong>to</strong> <strong>the</strong> $70.0 million principal amount 2.75% convertible senior notes due November 15, 2015. The 5,000 common<br />
shares previously recorded as potentially dilutive instruments were issued <strong>to</strong> Petroleum Independent and Exploration<br />
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<strong>Corporation</strong> in <strong>the</strong> quarter ended December 31, 2011 in exchange for <strong>the</strong> 5,000 shares it held in our subsidiary, S.P. <strong>InterOil</strong><br />
LDC.<br />
Derivative Instruments<br />
Our revenues are derived from <strong>the</strong> sale of refined products. Prices for refined products and crude feeds<strong>to</strong>cks can be<br />
volatile and sometimes experience large fluctuations over short periods of time as a result of relatively small changes in<br />
supplies, wea<strong>the</strong>r conditions, economic conditions and government actions. Due <strong>to</strong> <strong>the</strong> nature of our business, <strong>the</strong>re is<br />
always a time difference between <strong>the</strong> purchase of a crude feeds<strong>to</strong>ck and its arrival at <strong>the</strong> refinery and <strong>the</strong> supply of finished<br />
products <strong>to</strong> <strong>the</strong> various markets.<br />
Generally, we purchase crude feeds<strong>to</strong>ck two months in advance, whereas <strong>the</strong> supply/export of finished products will take<br />
place after <strong>the</strong> crude feeds<strong>to</strong>ck is discharged and processed. Due <strong>to</strong> <strong>the</strong> fluctuation in prices during this period, we use<br />
various derivative instruments as a <strong>to</strong>ol <strong>to</strong> reduce <strong>the</strong> risks of changes in <strong>the</strong> relative prices of our crude feeds<strong>to</strong>cks and<br />
refined products. These derivatives, which we use <strong>to</strong> manage our price risk, effectively enable us <strong>to</strong> lock-in <strong>the</strong> refinery margin<br />
such that we are protected in <strong>the</strong> event that <strong>the</strong> difference between our sale price of <strong>the</strong> refined products and <strong>the</strong> acquisition<br />
price of our crude feeds<strong>to</strong>cks contracts is reduced. Conversely, when we have locked-in <strong>the</strong> refinery margin and if <strong>the</strong><br />
difference between our sales price of <strong>the</strong> refined products and our acquisition price of crude feeds<strong>to</strong>cks expands or<br />
increases, <strong>the</strong>n <strong>the</strong> benefits would be limited <strong>to</strong> <strong>the</strong> locked-in margin.<br />
The derivative instruments which we generally use are <strong>the</strong> over-<strong>the</strong>-counter swaps. The swap transactions are concluded<br />
between counterparties in <strong>the</strong> derivatives swaps market, unlike futures which are transacted on <strong>the</strong> International Petroleum<br />
Exchange and Nymex Exchanges. We believe <strong>the</strong>se hedge counterparties <strong>to</strong> be credit worthy. It is common place among<br />
refiners and trading companies in <strong>the</strong> Asia Pacific market <strong>to</strong> use derivatives swaps as a <strong>to</strong>ol <strong>to</strong> hedge <strong>the</strong>ir price exposures<br />
and margins. Due <strong>to</strong> <strong>the</strong> wide usage of derivatives <strong>to</strong>ols in <strong>the</strong> Asia Pacific region, <strong>the</strong> swaps market generally provides<br />
sufficient liquidity for <strong>the</strong> hedging and risk management activities. The derivatives swap instrument covers commodities or<br />
products such as jet and kerosene, diesel, naphtha, and also bench-mark crudes such as Tapis and Dubai. By using <strong>the</strong>se<br />
<strong>to</strong>ols, we actively engage in hedging activities <strong>to</strong> lock in margins. Occasionally, <strong>the</strong>re is insufficient liquidity in <strong>the</strong> crude swaps<br />
market and we <strong>the</strong>n use o<strong>the</strong>r derivative instruments such as Brent futures on <strong>the</strong> IPE <strong>to</strong> hedge our crude costs.<br />
At December 31, 2011, we had a net receivable of $0.6 million (December 2010 – payable of $0.2 million) relating <strong>to</strong> open<br />
contracts <strong>to</strong> sell gasoil crack swaps and sell dated Brent swaps for which hedge accounting has not been applied, and Brent<br />
swaps that have been priced out and will be settled in January and February 2012.<br />
A gain of $2.0 million was recognized on <strong>the</strong> non-hedge accounted derivative contracts for <strong>the</strong> year ended December 31,<br />
2011 (December 2010 – $1.6 million loss).<br />
In addition <strong>to</strong> <strong>the</strong> commodity derivative contracts, we have also entered in<strong>to</strong> foreign exchange derivative contracts <strong>to</strong> manage<br />
our foreign exchange risk in relation <strong>to</strong> AUD. As at December 31, 2011, we had $11,457 payable (December 2010 - nil)<br />
relating <strong>to</strong> our foreign currency derivatives. An $11,457 loss has been recognized on foreign exchange derivative contracts for<br />
<strong>the</strong> year ended December 31, 2011 (December 2011 - $0.5 million gain).<br />
Industry Trends and Key Events<br />
Competitive Environment and Regulated Pricing<br />
We are currently <strong>the</strong> sole refiner of hydrocarbons in Papua New Guinea although <strong>the</strong>re is no legal restraint upon o<strong>the</strong>r<br />
refineries being established. The PNG Government has agreed <strong>to</strong> ensure that all domestic distribu<strong>to</strong>rs purchase <strong>the</strong>ir refined<br />
petroleum products from our refinery, or any o<strong>the</strong>r refinery which is constructed in Papua New Guinea, at an Import Parity<br />
Price (“IPP”). The IPP is moni<strong>to</strong>red by <strong>the</strong> ICCC. In general, <strong>the</strong> IPP is <strong>the</strong> price that would be paid in Papua New Guinea for a<br />
refined product being imported. For all price controlled products (diesel, unleaded petrol, kerosene and aviation fuel) produced<br />
and sold locally in Papua New Guinea, <strong>the</strong> IPP is calculated by adding <strong>the</strong> costs that would typically be incurred <strong>to</strong> import<br />
such product <strong>to</strong> Mean of Platts Singapore (“MOPS”) which is <strong>the</strong> benchmark price for refined products in <strong>the</strong> region in which<br />
we operate.<br />
In our refining business, we compete with several companies for available supplies of crude oil and o<strong>the</strong>r feeds<strong>to</strong>cks and for<br />
outlets for our refined products. Many of our competi<strong>to</strong>rs obtain a significant portion of <strong>the</strong>ir feeds<strong>to</strong>cks from company owned<br />
production, which may enable <strong>the</strong>m <strong>to</strong> obtain feeds<strong>to</strong>cks at a lower cost. The high cost of transporting goods <strong>to</strong> and from<br />
Papua New Guinea reduces <strong>the</strong> availability of alternate fuel sources and retail outlets for our refined products. Competi<strong>to</strong>rs<br />
that have <strong>the</strong>ir own production or extensive distribution networks are at times able <strong>to</strong> offset losses from refining operations<br />
50
and may be better positioned <strong>to</strong> withstand periods of depressed refining margins or feeds<strong>to</strong>ck shortages. In addition, new<br />
technology is making refining more efficient, which could lead <strong>to</strong> lower prices and reduced margins. We cannot be certain that<br />
we will be able <strong>to</strong> implement new technologies in a timely basis or at a cost that is acceptable <strong>to</strong> us.<br />
We are also a significant participant in <strong>the</strong> retail and wholesale distribution business in Papua New Guinea. The ICCC<br />
regulates <strong>the</strong> maximum prices and margins that may be charged by <strong>the</strong> wholesale and retail hydrocarbon distribution<br />
industry in Papua New Guinea. Margins were last reviewed by <strong>the</strong> ICCC in 2010 and will be fur<strong>the</strong>r reviewed in 2014. We and<br />
our competi<strong>to</strong>rs may charge less than <strong>the</strong> maximum margin set by <strong>the</strong> ICCC in order <strong>to</strong> maintain competitiveness.<br />
Our main competi<strong>to</strong>r in <strong>the</strong> wholesale and retail distribution business in Papua New Guinea is ExxonMobil. We also compete<br />
with smaller local distribu<strong>to</strong>rs of petroleum products. Our competi<strong>to</strong>rs source small quantities from our refinery from both <strong>the</strong><br />
refinery gantry for <strong>the</strong> Port Moresby market and by tanker vessel for <strong>the</strong> markets outside Port Moresby. Our major competitive<br />
advantage is <strong>the</strong> large widespread distribution network we maintain with adequate s<strong>to</strong>rage capacity that services most areas<br />
of PNG. We also believe that our commitment <strong>to</strong> <strong>the</strong> distribution business in Papua New Guinea at a time when major<br />
integrated oil and gas companies exited <strong>the</strong> Papua New Guinea fuel distribution market provides us with a competitive<br />
advantage. However, major-integrated oil and gas companies such as ExxonMobil have greater resources than we do and<br />
could if <strong>the</strong>y decided <strong>to</strong> do so, expand much more rapidly in this market than we can.<br />
Our proposed LNG Project faces competition, including competing liquefaction facilities and related infrastructure, from<br />
competi<strong>to</strong>rs with far greater resources, including major international energy companies. Many competing companies have<br />
secured access <strong>to</strong>, or are pursuing development or acquisition of, liquefaction facilities <strong>to</strong> serve <strong>the</strong> same markets we intend<br />
<strong>to</strong> target. In addition, competi<strong>to</strong>rs have developed or reopened additional liquefaction facilities in o<strong>the</strong>r international<br />
markets, which may also compete with our LNG Project. Almost all of <strong>the</strong>se competi<strong>to</strong>rs have longer operating his<strong>to</strong>ries,<br />
more development experience, greater name recognition, larger staffs and substantially greater financial, technical and<br />
marketing resources and access <strong>to</strong> natural gas and LNG supplies than we do. The superior resources that <strong>the</strong>se competi<strong>to</strong>rs<br />
have available for deployment could allow <strong>the</strong>m <strong>to</strong> compete successfully against our LNG businesses, which could have a<br />
material adverse effect on our business, results of operations, financial condition, liquidity and prospects.<br />
Financing Arrangements<br />
We continue <strong>to</strong> moni<strong>to</strong>r liquidity risk by setting of acceptable gearing levels and ensuring <strong>the</strong>y are moni<strong>to</strong>red. Our aim is <strong>to</strong><br />
maintain our debt-<strong>to</strong>-capital ratio, or gearing levels, (debt/(shareholders’ equity + debt)) at 50% or less. This was achieved<br />
throughout 2011 and 2010. Gearing levels were 12% in December 2011 and 13% in December 2010.<br />
On November 10, 2010, we <strong>complete</strong>d concurrent public offerings of $70.0 million aggregate principal amount of 2.75%<br />
convertible senior notes due 2015 and 2,800,000 common shares at a price of $75.00 per share for proceeds of $210.0<br />
million, raising gross proceeds of $280.0 million from <strong>the</strong> combined offerings.<br />
No financing arrangements were entered in<strong>to</strong> in 2011.<br />
For details of o<strong>the</strong>r financial arrangements in place, see “Liquidity and Capital Resources – Summary of Debt Facilities”.<br />
We had cash, cash equivalents and cash restricted of $108.1 million as at December 31, 2011, of which $39.3 million was<br />
restricted (as governed by BNP working capital facility utilization requirements and OPIC secured loan facility). In addition, we<br />
also had $11.8 million equivalent of PGK in short term treasury bills issued by <strong>the</strong> Bank of Papua New Guinea. With regard <strong>to</strong><br />
our cash and cash equivalents, we invest in bankers acceptances and money market instruments with major financial<br />
institutions that we believe are creditworthy. We also had $85.1 million of <strong>the</strong> combined BNP working capital facility available<br />
for use in our Midstream – Refining operations, and $54.2 million of <strong>the</strong> Westpac/BSP combined working capital facility<br />
available for use in our Downstream operations.<br />
Crude Prices<br />
Crude prices increased steadily throughout 2011, with <strong>the</strong> price of Dated Brent crude oil (as quoted by Platts) starting <strong>the</strong><br />
year at $97 per bbl and closing <strong>the</strong> year at $108 per bbl. The average price for Dated Brent for 2011 was $111 per bbl<br />
compared with $79 per bbl for Dated Brent for 2010.<br />
At year end we had $85.1 million of <strong>the</strong> combined BNP working capital facility available for use in our Midstream –<br />
Refining operations, and approximately $54.2 million of <strong>the</strong> Westpac/BSP combined working capital facility available for use<br />
in our Downstream operations. Any increase in prices will have an impact on <strong>the</strong> utilization of our working capital facilities, and<br />
related interest and financing charges on <strong>the</strong> utilized amounts.<br />
51
Any volatility of crude prices means that we face significant timing and margin risk on our crude cargos. A significant<br />
portion of this timing and margin risk is managed by us through short and long term hedges. There was a net receivable of<br />
$0.6 million relating <strong>to</strong> open contracts <strong>to</strong> sell gasoil crack swaps and sell Dated Brent swaps for which hedge accounting has<br />
not been applied, and Brent swaps that have been priced out and were settled in January and February of 2012.<br />
Refining Margin<br />
The distillation process used by our refinery <strong>to</strong> convert crude feeds<strong>to</strong>cks in<strong>to</strong> refined products is commonly referred <strong>to</strong> as<br />
hydroskimming. While <strong>the</strong> Singapore Tapis hydroskimming margin is a useful indica<strong>to</strong>r of <strong>the</strong> general margin available for<br />
hydroskimming refineries in <strong>the</strong> region in which we operate, it should be noted that <strong>the</strong> differences in our approach <strong>to</strong> crude<br />
selection, transportation costs and IPP pricing work so that our realized margin generally differs <strong>to</strong> some extent.<br />
Distillate margins <strong>to</strong> Dated Brent streng<strong>the</strong>ned during 2011 compared with his<strong>to</strong>rical levels due <strong>to</strong> increasing demand.<br />
Naphtha crack spreads were negative for all of 2011, which has negatively affected our gross margin for <strong>the</strong> period.<br />
Domestic Demand<br />
Sales results for our refinery for 2011 indicate that Papua New Guinea’s domestic demand for middle distillates (which<br />
includes diesel and jet fuels) from <strong>the</strong> refinery has increased by approximately 6.4% compared with 2010. However, <strong>the</strong> <strong>to</strong>tal<br />
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<br />
volume of PNG domestic sales only for 2011 was 4.9 million barrels as compared with 4.6 million barrels in 2010.<br />
The refinery on average sold 12,649 bbls per day of refined petroleum products <strong>to</strong> <strong>the</strong> domestic market during fiscal year<br />
2011 compared with 11,780 bbls per day in 2010.<br />
Interest Rates<br />
The LIBOR USD overnight rate is <strong>the</strong> benchmark floating rate used in our midstream working capital facility and <strong>the</strong>refore<br />
accounts for a significant proportion of our interest rate exposure. The LIBOR USD overnight rate remained constant at<br />
between 0.2% and 0.3% for 2010 and <strong>the</strong>n reduced <strong>to</strong> between 0.15% and 0.2% for <strong>the</strong> majority of 2011. Any rate<br />
increases would add additional cost <strong>to</strong> financing our crude cargoes and vice versa as our BNP Paribas working capital facility<br />
is linked <strong>to</strong> LIBOR rates. See “Liquidity and Capital Resources – Summary of Debt Facilities”.<br />
Exchange Rates<br />
Changes in <strong>the</strong> PGK <strong>to</strong> USD exchange rate can affect our Midstream Refinery results as <strong>the</strong>re is a timing difference between<br />
<strong>the</strong> foreign exchange rates utilized when setting <strong>the</strong> monthly IPP, which is set in PGK, and <strong>the</strong> foreign exchange rate used <strong>to</strong><br />
convert <strong>the</strong> subsequent receipt of PGK proceeds <strong>to</strong> USD <strong>to</strong> repay our crude cargo borrowings. The PGK has streng<strong>the</strong>ned<br />
against <strong>the</strong> USD every month during <strong>the</strong> year ended December 31, 2011 (from 0.3785 <strong>to</strong> 0.4665).<br />
Changes in <strong>the</strong> AUD and SGD <strong>to</strong> USD exchange rate can affect our Corporate results as <strong>the</strong> expenses of <strong>the</strong> Corporate<br />
offices in Australia and Singapore are incurred in <strong>the</strong> respective local currencies. The AUD and SGD exposures are minimal<br />
currently as funds are transferred <strong>to</strong> AUD and SGD from USD as required. No material balances are held in AUD or SGD.<br />
However, we are exposed <strong>to</strong> translation risks resulting from AUD and SGD fluctuations as in country costs are being incurred<br />
in AUD and SGD and <strong>report</strong>ing for those costs being in USD. We have entered in<strong>to</strong> AUD <strong>to</strong> USD foreign currency forward<br />
contracts <strong>to</strong> manage <strong>the</strong> foreign exchange risk in relation <strong>to</strong> <strong>the</strong> expenses <strong>to</strong> be incurred in AUD.<br />
Risk Fac<strong>to</strong>rs<br />
Our business operations and financial position are subject <strong>to</strong> a range of risks. A summary of <strong>the</strong> key risks that may impact<br />
upon <strong>the</strong> matters addressed in this document have been included under section “Forward Looking Statements” above.<br />
Detailed risk fac<strong>to</strong>rs can be found under <strong>the</strong> heading “Risk Fac<strong>to</strong>rs” in our 2011 Annual Information Form available at<br />
www.sedar.com.<br />
Critical Accounting Estimates<br />
The preparation of financial statements in accordance with IFRS requires our management <strong>to</strong> make estimates and<br />
assumptions that affect <strong>the</strong> amounts <strong>report</strong>ed in <strong>the</strong> consolidated financial statements and accompanying notes. Actual<br />
results could differ from those estimates. The effect of changes in estimates on future periods have not been disclosed in <strong>the</strong><br />
consolidated financial statements as estimating it is impracticable. The following accounting policies involve estimates that<br />
52
are considered critical due <strong>to</strong> <strong>the</strong> level of sensitivity and judgment involved, as well as <strong>the</strong> impact on our consolidated financial<br />
position and results of operations. The information about our critical accounting estimates should be read in conjunction with<br />
Note 2 of <strong>the</strong> notes <strong>to</strong> our consolidated financial statements for <strong>the</strong> year ended December 31, 2011, available at<br />
www.sedar.com which summarizes our significant accounting policies.<br />
Income Taxes<br />
We use <strong>the</strong> asset and liability method of accounting for income taxes. Under <strong>the</strong> asset and liability method, deferred tax<br />
assets and liabilities are recognized for <strong>the</strong> deferred tax consequences attributable <strong>to</strong> differences between <strong>the</strong> financial<br />
statement carrying amounts of existing assets and liabilities and <strong>the</strong>ir respective tax bases. Deferred tax assets and liabilities<br />
are measured using enacted tax rates expected <strong>to</strong> apply <strong>to</strong> taxable income in <strong>the</strong> years in which those temporary differences<br />
are expected <strong>to</strong> be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized<br />
in income in <strong>the</strong> period that includes <strong>the</strong> date of enactment. In considering <strong>the</strong> recoverability of deferred tax assets and<br />
liabilities, we consider a number of fac<strong>to</strong>rs, including <strong>the</strong> consistency of profits generated from <strong>the</strong> refinery, likelihood of<br />
production from Upstream operations <strong>to</strong> utilize <strong>the</strong> carried forward exploration costs, etc. If actual results differ from <strong>the</strong><br />
estimates or we adjust <strong>the</strong> estimates in future periods, a reduction in our deferred tax assets will result in a corresponding<br />
increase in deferred tax expenses.<br />
Oil and Gas Properties<br />
We use <strong>the</strong> successful-efforts method <strong>to</strong> account for our oil and gas exploration and development activities. Under this<br />
method, costs are accumulated on a field-by-field basis with certain explora<strong>to</strong>ry expenditures and explora<strong>to</strong>ry dry holes being<br />
expensed as incurred. We continue <strong>to</strong> carry as an asset <strong>the</strong> cost of drilling explora<strong>to</strong>ry wells if <strong>the</strong> required capital<br />
expenditure is made and drilling of additional explora<strong>to</strong>ry wells is underway or firmly planned for <strong>the</strong> near future, or when<br />
exploration and evaluation activities have not yet reached a stage <strong>to</strong> allow reasonable assessment regarding <strong>the</strong> existence of<br />
economical reserves. Capitalized costs for producing wells will be subject <strong>to</strong> depletion using <strong>the</strong> units-of-production method.<br />
Geological and geophysical costs are expensed as incurred. If our plans change or we adjust our estimates in future periods,<br />
a reduction in our oil and gas properties asset will result in a corresponding increase in <strong>the</strong> amount of our exploration<br />
expenses.<br />
Asset Retirement Obligations<br />
A liability is recognized for future legal or constructive retirement obligations associated with <strong>the</strong> Company’s property, plant<br />
and equipment. The amount recognized is <strong>the</strong> net present value of <strong>the</strong> estimated costs of future dismantlement, site<br />
res<strong>to</strong>ration and abandonment of properties based upon current regulations and economic circumstances at period end.<br />
During <strong>the</strong> quarter ended June 30, 2011, Management received <strong>the</strong> results of an independent assessment of <strong>the</strong> potential<br />
asset retirement obligations of <strong>the</strong> refinery. As a result of this assessment, Management has recognized an asset retirement<br />
obligation at December 31, 2011 of $4,562,269. If we adjust <strong>the</strong> estimates in future periods, it may result in increased capital<br />
expenditures and a corresponding increase in liabilities.<br />
Environmental Remediation<br />
Remediation costs are accrued based on estimates of known environmental remediation exposure. Ongoing environmental<br />
compliance costs, including maintenance and moni<strong>to</strong>ring costs, are expensed as incurred. Provisions are determined on an<br />
assessment of current costs, current legal requirements and current technology. Changes in estimates are dealt with on a<br />
prospective basis. We currently do not have any amounts accrued for environmental remediation obligations as current<br />
legislation does not require it. Future legislative action and regula<strong>to</strong>ry initiatives could result in changes <strong>to</strong> our operating<br />
permits which may result in increased capital expenditures and operating costs.<br />
Impairment of Long-Lived Assets<br />
We are required <strong>to</strong> review <strong>the</strong> carrying value of all property, plant and equipment, including <strong>the</strong> carrying value of oil and gas<br />
assets, and goodwill for potential impairment. We test long-lived assets for recoverability whenever events or changes in<br />
circumstances indicate that its carrying amount may not be recoverable by <strong>the</strong> future undiscounted cash flows. If impairment<br />
is indicated, <strong>the</strong> amount by which <strong>the</strong> carrying value exceeds <strong>the</strong> estimated fair value of <strong>the</strong> long-lived asset is charged <strong>to</strong><br />
earnings. In order <strong>to</strong> determine fair value, our management must make certain estimates and assumptions including, among<br />
o<strong>the</strong>r things, an assessment of market conditions (including estimation of gross refining margins, crude price environments<br />
and its impact on IPP, etc), projected cash flows, investment rates, interest/equity rates and growth rates, that could<br />
significantly impact <strong>the</strong> fair value of <strong>the</strong> asset being tested for impairment. Due <strong>to</strong> <strong>the</strong> significant subjectivity of <strong>the</strong><br />
assumptions used <strong>to</strong> test for recoverability and <strong>to</strong> determine fair value, changes in market conditions could result in significant<br />
53
significant impairment charges in <strong>the</strong> future, thus affecting our earnings. Our impairment evaluations are based on<br />
assumptions that are consistent with our business plans.<br />
Legal and O<strong>the</strong>r Contingent Matters<br />
We are required <strong>to</strong> determine whe<strong>the</strong>r a loss is probable based on judgment and interpretation of laws and regulations and<br />
whe<strong>the</strong>r <strong>the</strong> loss can reasonably be estimated. When <strong>the</strong> amount of a contingent loss is determined it is charged <strong>to</strong> earnings.<br />
Our management continually moni<strong>to</strong>rs known and potential contingent matters and makes appropriate provisions by charges<br />
<strong>to</strong> earnings when warranted by circumstances.<br />
During <strong>the</strong> second half of 2011, <strong>the</strong> PNG Cus<strong>to</strong>ms Service commenced an audit of our petroleum product imports in<strong>to</strong> Papua<br />
New Guinea for <strong>the</strong> years 2007 <strong>to</strong> 2010. We received a letter in November 2011 from <strong>the</strong> <strong>the</strong>n Commissioner of Cus<strong>to</strong>ms<br />
setting out certain findings from <strong>the</strong> audit. This letter included comments alleging that payment of import GST was required<br />
and had not been made on imports of certain refined products. As well as requiring payment of GST, <strong>the</strong> letter noted that<br />
administrative penalties were able <strong>to</strong> be levied by Cus<strong>to</strong>ms in <strong>the</strong> range of 50% <strong>to</strong> 200% of <strong>the</strong> assessed amounts as per <strong>the</strong><br />
PNG Cus<strong>to</strong>ms Act. We have since met with <strong>the</strong> Cus<strong>to</strong>ms Service and provided it with supporting documentation <strong>to</strong><br />
demonstrate that <strong>the</strong> GST amounts claimed in <strong>the</strong>ir letter have all been paid. We have currently made a provision based on<br />
our best estimate in relation <strong>to</strong> this matter and are working closely with <strong>the</strong> authority <strong>to</strong> provide all requested information in<br />
order <strong>to</strong> finalize <strong>the</strong> audit.<br />
New Accounting Standards<br />
New accounting standards not yet applicable as at December 31, 2011<br />
The following new standards have been issued but are not yet effective for <strong>the</strong> financial year beginning January 1, 2011 and<br />
have not been early adopted:<br />
• IFRS 9 ‘Financial Instruments’ (effective from January 1, 2015): This addresses <strong>the</strong> classification and measurement of<br />
financial assets. The standard is not applicable until January 1, 2013 but is available for early adoption. We have yet <strong>to</strong><br />
assess IFRS 9’s full impact. We have not yet decided <strong>to</strong> adopt IFRS 9 early.<br />
• IFRS 10 ‘Consolidated Financial Statements’ (effective from January 1, 2013): This builds on existing principles by<br />
identifying <strong>the</strong> concept of control as <strong>the</strong> determining fac<strong>to</strong>r in whe<strong>the</strong>r an entity should be included within <strong>the</strong><br />
consolidated financial statements. The standard provides additional guidance <strong>to</strong> assist in determining control where this<br />
is difficult <strong>to</strong> assess. This new standard might impact <strong>the</strong> entities that a group consolidates as its subsidiaries. We have<br />
yet <strong>to</strong> assess IFRS 10’s full impact.<br />
• IFRS 11 ‘Joint Arrangements’ (effective from January 1, 2013): This provides for a more realistic reflection of joint<br />
arrangements by focusing on <strong>the</strong> rights and obligations of <strong>the</strong> arrangement, ra<strong>the</strong>r than its legal form. There are two<br />
types of joint arrangements: joint operations and joint ventures. Joint operations arise where a joint opera<strong>to</strong>r has rights<br />
<strong>to</strong> <strong>the</strong> assets and obligations relating <strong>to</strong> <strong>the</strong> arrangement and hence accounts for its interest in assets, liabilities,<br />
revenue and expenses. Joint ventures arise where <strong>the</strong> joint opera<strong>to</strong>r has rights <strong>to</strong> <strong>the</strong> net assets of <strong>the</strong> arrangement<br />
and hence equity accounts for its interest. Proportional consolidation of joint ventures is no longer allowed. We have yet<br />
<strong>to</strong> assess IFRS 11’s full impact.<br />
• IFRS 12 ‘Disclosure of Interests in O<strong>the</strong>r Entities’ (effective from January 1, 2013): This standard is a new standard on<br />
disclosure requirements for all forms of interests in o<strong>the</strong>r entities, including joint arrangements, associates, special<br />
purpose vehicles and o<strong>the</strong>r off balance sheet vehicles. We have yet <strong>to</strong> assess IFRS 12’s full impact.<br />
• IFRS 13 ‘Fair Value Measurement’ (effective from January 1, 2013): This aims <strong>to</strong> improve consistency and reduce<br />
complexity by providing a precise definition of fair value and a single source of fair value measurement and disclosure<br />
requirements for use across IFRS. We have yet <strong>to</strong> assess IFRS 13’s full impact.<br />
• IAS 27 ‘Separate Financial Statements’ (effective from January 1, 2013): This includes <strong>the</strong> provisions on separate<br />
financial statements that are left after <strong>the</strong> control provisions of IAS 27 have been included in <strong>the</strong> new IFRS 10. We have<br />
yet <strong>to</strong> assess IAS 27’s full impact.<br />
• IAS 28 ‘Investments in Associates and Joint Ventures’ (effective from January 1, 2013): This now includes <strong>the</strong><br />
requirements for joint ventures, as well as associates, <strong>to</strong> be equity accounted following <strong>the</strong> issue of IFRS 11. We have<br />
yet <strong>to</strong> assess IAS 28’s full impact.<br />
54
• IAS 1 ‘Presentation of financial statements’ (amendment): The IASB has issued an amendment <strong>to</strong> IAS 1, which<br />
changes <strong>the</strong> disclosure of items presented in o<strong>the</strong>r comprehensive income (OCI) in <strong>the</strong> statement of comprehensive<br />
income. The IASB originally proposed that all entities should present profit or loss and OCI <strong>to</strong>ge<strong>the</strong>r in a single<br />
statement of comprehensive income. The proposal has been withdrawn and IAS 1 will still permit profit or loss and OCI<br />
<strong>to</strong> be presented in ei<strong>the</strong>r a single statement or in two consecutive statements. The amendment was developed jointly<br />
with <strong>the</strong> FASB, which has removed <strong>the</strong> option in US generally accepted accounting principles <strong>to</strong> present OCI in <strong>the</strong><br />
statement of changes in equity. The amendment is effective for annual periods starting on or after July 1, 2012, subject<br />
<strong>to</strong> EU endorsement. This amendment will not have any material impact on our financial statements.<br />
Changeover <strong>to</strong> International Financial Reporting Standards<br />
The AcSB adopted IFRS as issued by IASB as GAAP, effective January 1, 2011, with a transition date of January 1, 2010. We<br />
have adopted IFRS and have prepared our financial statements for <strong>the</strong> year ended December 31, 2011 in accordance with<br />
IFRS and restated our financial statements for <strong>the</strong> year ended December 31, 2010 <strong>to</strong> comply with IFRS. The financial<br />
information contained in this MD&A that relates <strong>to</strong> periods prior <strong>to</strong> January 1, 2010 has been prepared under our previous<br />
GAAP and has not been restated.<br />
(i) Application of IFRS 1:<br />
Our financial statements for <strong>the</strong> year ended December 31, 2011, are <strong>the</strong> first annual financial statements prepared in<br />
compliance with IFRS. We have applied IFRS 1 in preparing <strong>the</strong> consolidated financial statements for <strong>the</strong> year ended<br />
December 31, 2011.<br />
Our transition date <strong>to</strong> IFRS was January 1, 2010 and we have prepared our opening IFRS balance sheet at that date. In<br />
preparing <strong>the</strong> consolidated financial statements for <strong>the</strong> year ended December 31, 2011 in accordance with IFRS 1, we have<br />
applied <strong>the</strong> relevant manda<strong>to</strong>ry exceptions and certain optional exemptions from full retrospective application of IFRS.<br />
(ii) Exemptions from full retrospective application – elected by <strong>the</strong> Company<br />
We have elected <strong>to</strong> apply <strong>the</strong> following optional exemptions from full retrospective application.<br />
• Business combinations exemption: A first-time adopter may elect not <strong>to</strong> apply IFRS 3 - ‘Business Combinations’ (as<br />
revised in 2008) retrospectively <strong>to</strong> past business combinations (business combinations that occurred before <strong>the</strong> date of<br />
transition <strong>to</strong> IFRS). However, if a first-time adopter restates any business combination <strong>to</strong> comply with IFRS 3 (as revised<br />
in 2008), it shall restate all later business combinations and shall also apply IAS 27 (as amended in 2008) from that<br />
same date. We have made <strong>the</strong> election not <strong>to</strong> apply IFRS 3 retrospectively <strong>to</strong> past business combinations.<br />
• Fair value as deemed cost exemption: An entity may elect <strong>to</strong> measure an item of property, plant and equipment at <strong>the</strong><br />
date of transition <strong>to</strong> IFRS at its fair value and use that fair value as its deemed cost at that date. We have made <strong>the</strong><br />
election not <strong>to</strong> revalue our property, plant and equipment <strong>to</strong> fair value or deemed cost. His<strong>to</strong>rical cost will be<br />
maintained as plant and equipment cost base on transition.<br />
• Cumulative translation differences exemption: Consistent with <strong>the</strong> previous GAAP treatment in prior periods, IAS 21<br />
requires an entity: (a) <strong>to</strong> recognize some translation differences in o<strong>the</strong>r comprehensive income and accumulate <strong>the</strong>se<br />
in a separate component of equity; and (b) on disposal of a foreign operation, <strong>to</strong> reclassify <strong>the</strong> cumulative translation<br />
difference for that foreign operation (including, if applicable, gains and losses on related hedges) from equity <strong>to</strong> profit or<br />
loss as part of <strong>the</strong> gain or loss on disposal. An election can be made <strong>to</strong> be exempted from this requirement on<br />
transition and start with ‘zero’ translation differences. We have not made <strong>the</strong> election <strong>to</strong> restate our cumulative<br />
translation differences balance <strong>to</strong> zero, and have elected <strong>to</strong> continue with <strong>the</strong> current translation differences in<br />
comprehensive income as <strong>the</strong>se are already in compliance with IAS 21.<br />
• Oil and Gas assets exemption: Oil and Gas industry specific accounting under IFRS or previous GAAP is currently not<br />
as comprehensive as <strong>the</strong> guidance provided under U.S. generally accepted accounting principles accounting for<br />
industry specific oil and gas transactions. Paragraph D8A of IFRS 1 provides an exemption in relation <strong>to</strong> Oil and Gas<br />
assets by allowing companies <strong>to</strong> continue using <strong>the</strong> same policies as used under <strong>the</strong> previous GAAP and carrying<br />
forward <strong>the</strong> carrying amounts of <strong>the</strong> Oil and Gas assets under GAAP in<strong>to</strong> IFRS. We have availed this exemption and<br />
elected <strong>to</strong> maintain our Oil and Gas assets at carrying amount under GAAP treatment in prior periods, which will be <strong>the</strong><br />
deemed cost under IFRS.<br />
• Interests in joint ventures entities exemption: Superseded CICA Section 3055 differs from IAS 31 as IAS 31 permits <strong>the</strong><br />
55
• use of ei<strong>the</strong>r <strong>the</strong> proportionate consolidation method or <strong>the</strong> equity method <strong>to</strong> account for joint venture entities. IAS 31<br />
recommends <strong>the</strong> use of proportionate consolidation as it better reflects <strong>the</strong> substance and economic reality, however, it<br />
does permit <strong>the</strong> use of equity method. Superseded CICA Section 3055 only allows <strong>the</strong> use of proportionate<br />
consolidation method <strong>to</strong> account for joint venture entities. We have elected <strong>to</strong> maintain our joint venture accounting<br />
under <strong>the</strong> proportionate consolidation model for both our incorporated and unincorporated joint venture interests.<br />
The remaining optional exemptions are not applicable <strong>to</strong> us.<br />
(iii) Exceptions from full retrospective application followed by <strong>the</strong> Company<br />
All manda<strong>to</strong>ry exceptions in IFRS 1 were not applicable because <strong>the</strong>re were no significant differences in management’s<br />
application of GAAP in <strong>the</strong>se areas.<br />
Impact of adoption of IFRS on financial <strong>report</strong>ing<br />
Following a review of <strong>the</strong> IFRS, <strong>the</strong>re were two IFRS adjustments <strong>to</strong> <strong>the</strong> opening January 1, 2010 balance sheet:<br />
a) In relation <strong>to</strong> <strong>the</strong> deferred gain on contributions <strong>to</strong> <strong>the</strong> LNG Project recorded on our balance sheet, under IFRS, we were<br />
required <strong>to</strong> offset <strong>the</strong>se deferred gains against any underlying assets that are carried in relation <strong>to</strong> <strong>the</strong>se deferred gains. Based<br />
on this guidance, we have offset <strong>the</strong> deferred gains against deferred LNG project costs carried within <strong>the</strong> plant and equipment<br />
in <strong>the</strong> balance sheet under <strong>the</strong> Midstream – Liquefaction segment. For fur<strong>the</strong>r details, please refer <strong>to</strong> Note 3(b) in <strong>the</strong><br />
Condensed Consolidated Financial Statements for <strong>the</strong> year ended December 31, 2011.<br />
b) In accordance with guidance under IFRS, deferred tax assets have been recognized for temporary differences that arise on<br />
translation of <strong>the</strong> nonmonetary assets held by Midstream refining operations that are translated from <strong>the</strong> functional currency of<br />
<strong>the</strong> tax return (PGK) <strong>to</strong> <strong>the</strong> <strong>report</strong>ing currency (USD) using period end rates. Previously under GAAP, <strong>the</strong>se temporary<br />
differences in relation <strong>to</strong> functional currency translation of nonmonetary assets were specifically disallowed from recognition.<br />
O<strong>the</strong>r than <strong>the</strong> transition adjustments affecting <strong>the</strong> consolidated balance sheets, consolidated income statements,<br />
consolidated statements of comprehensive income and consolidated statements of changes in equity as noted above, <strong>the</strong>re<br />
were no transition differences noted in relation <strong>to</strong> consolidated statement of cash flows.<br />
Non-GAAP Measures and Reconciliation<br />
Non-GAAP measures, including gross margin and EBITDA, included in this MD&A are not defined nor have a standardized<br />
meaning prescribed by IFRS or our previous GAAP; accordingly, <strong>the</strong>y may not be comparable <strong>to</strong> similar measures provided by<br />
o<strong>the</strong>r issuers. Gross margin is a non-GAAP measure and is “sales and operating revenues” less “cost of sales and operating<br />
expenses”. The following table reconciles sales and operating revenues, a GAAP measure, <strong>to</strong> Gross margin:<br />
Consolidated – Operating results<br />
($ thousands)<br />
Quarter ended December 31,<br />
2011 2010 2011<br />
Midstream – Refining 939,278 674,137 574,409<br />
Downstream 743,860 504,786 388,991<br />
Corporate 14,125 402 21,194<br />
Consolidation Entries (590,729) (376,951) (296,115)<br />
Sales and operating revenues 1,106,534 802,374 688,479<br />
Midstream – Refining (897,825) (605,603) (516,349)<br />
Downstream (704,213) (470,772) (359,623)<br />
Corporate (1) (11,421) - -<br />
Consolidation Entries 592,527 374,818 273,989<br />
Cost of sales and operating expenses (1,020,932) (701,557) (601,983)<br />
Midstream – Refining 41,453 68,534 58,060<br />
Downstream 39,647 34,014 29,368<br />
Corporate (1) 2,704 402 21,194<br />
Consolidation Entries 1,798 (2,133) (22,126)<br />
Gross Margin 85,602 100,817 86,496<br />
1 Corporate expenses are classified below <strong>the</strong> gross margin line and mainly relates <strong>to</strong> ‘Office and admin and o<strong>the</strong>r expenses’ and ‘Interest expense’.<br />
2 The 2009 financial information was prepared in accordance with <strong>the</strong> Company’s former GAAP, and has not been restated in accordance with IFRS.<br />
56
EBITDA represents our net income/(loss) plus <strong>to</strong>tal interest expense (excluding amortization of debt issuance costs), income<br />
tax expense, depreciation and amortization expense. EBITDA is used by us <strong>to</strong> analyze operating performance. EBITDA does<br />
not have a standardized meaning prescribed by GAAP (i.e., IFRS) and, <strong>the</strong>refore, may not be comparable with <strong>the</strong> calculation<br />
of similar measures for o<strong>the</strong>r companies. The items excluded from EBITDA are significant in assessing our operating results.<br />
Therefore, EBITDA should not be considered in isolation or as an alternative <strong>to</strong> net earnings, operating profit, net cash<br />
provided from operating activities and o<strong>the</strong>r measures of financial performance prepared in accordance with IFRS. Fur<strong>the</strong>r,<br />
EBITDA is not a measure of cash flow under IFRS and should not be considered as such. For reconciliation of EBITDA <strong>to</strong> <strong>the</strong><br />
net income (loss) under IFRS, refer <strong>to</strong> <strong>the</strong> following table.<br />
The following table reconciles net income (loss), a GAAP measure, <strong>to</strong> EBITDA, a non-GAAP measure for each of <strong>the</strong> last eight<br />
quarters. Our IFRS transition date was January 1, 2010 and as such, <strong>the</strong> 2010 comparative information has been restated in<br />
accordance with IFRS.<br />
Quarters ended<br />
($ thousands)<br />
2011 2010<br />
Dec 31 Sep 31 Jun 30 Mar 31 Dec 31 Sep 30 Jun 30 Mar 31<br />
Upstream 665 (6,169) 593 (10,957) (41,681) (11,753) (3,498) (1,964)<br />
Midstream – Refining 2,604 3,461 27,967 26,632 13,780 15,785 16,962 4,402<br />
Midstream – Liquefaction (4,123) (3,602) (4,035) (2,375) (1,959) (4,588) (3) (563)<br />
Downstream 6,808 3,570 5,777 8,744 4,709 1,674 7,060 4,492<br />
Corporate 10,134 1,548 13,940 5,223 4,566 (4,510) 1,751 4,402<br />
Consolidation Entries (11,280) (10,263) (5,270) (9,200) (7,004) (5,229) (7,384) (5,911)<br />
Earnings before interest,<br />
taxes, depreciation and<br />
amortization<br />
Subtract:<br />
4,808 (11,455) 38,972 18,067 (27,589) (8,621) 14,888 4,858<br />
Upstream (8,712) (7,806) (7,142) (6,352) (5,481) (4,600) (4,367) (4,081)<br />
Midstream – Refining (3,285) (2,494) (2,211) (1,675) (1,509) (1,693) (1,651) (1,731)<br />
Midstream – Liquefaction (445) (372) (268) (223) (184) (376) (351) (342)<br />
Downstream (1,170) (1,233) (1,116) (826) (835) (938) (1,167) (800)<br />
Corporate (1,498) (1,477) (1,641) (1,395) (1,158) (342) (20) (20)<br />
Consolidation Entries 11,500 10,041 8,894 7,572 6,571 6,107 5,917 5,688<br />
Interest expense (3,610) (3,341) (3,484) (2,899) (2,596) (1,842) (1,639) (1,286)<br />
Upstream 0 - - - - - - -<br />
Midstream – Refining 19,243 678 (5,677) (7,298) (65) 101 (366) (173)<br />
Midstream – Liquefaction 0 - - - 36 - - -<br />
Downstream (595) (297) (1,449) (2,623) (495) (322) (1,524) (2,360)<br />
Corporate (493) (195) (629) 71 (11) (529) 97 (797)<br />
Consolidation Entries 0 0 0 - (2) (2) (1) -<br />
Income taxes 18,155 186 (7,755) (9,850) (537) (752) (1,794) (3,330)<br />
Upstream (1,355) (1,105) (154) (641) (683) (232) (78) (138)<br />
Midstream – Refining (2,878) (2,846) (2,764) (2,765) (2,700) (2,195) (2,888) (2,571)<br />
Midstream – Liquefaction (6) (6) (6) (6) (7) (6) (6) (6)<br />
Downstream (1,422) (894) (906) (804) (737) (739) (651) (660)<br />
Corporate (527) (349) (395) (435) (16) (17) (32) (41)<br />
Consolidation Entries 32 32 32 32 33 32 33 32<br />
Depreciation and<br />
amortisation<br />
(6,156) (5,168) (4,193) (4,619) (4,110) (3,157) (3,622) (3,384)<br />
Upstream (9,402) (15,080) (6,703) (17,949) (47,845) (16,585) (7,943) (6,182)<br />
Midstream – Refining 15,684 (1,201) 17,314 14,894 9,504 11,998 12,056 (74)<br />
Midstream – Liquefaction (4,574) (3,980) (4,309) (2,604) (2,114) (4,970) (360) (911)<br />
Downstream 3,621 1,146 2,306 4,491 2,643 (325) 3,719 671<br />
Corporate 7,616 (473) 11,275 3,463 3,381 (5,398) 1,796 3,544<br />
Consolidation Entries 252 (190) 3,657 (1,596) (401) 908 (1,435) (190)<br />
Net profit/(loss) per<br />
segment<br />
13,197 (19,778) 23,540 699 (34,832) (14,372) 7,833 (3,142)<br />
57
Public Securities Filings<br />
You may access additional information about us, including our 2011 Annual Information Form, in documents filed with <strong>the</strong><br />
Canadian Securities Administra<strong>to</strong>rs at www.sedar.com, and in documents, including our Form 40-F, filed with <strong>the</strong> U.S.<br />
Securities and Exchange Commission at www.sec.gov. Additional information is also available on our website<br />
www.interoil.com.<br />
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS<br />
OVER FINANCIAL REPORTING<br />
Our certifying officers have designed disclosure controls and procedures, as such term is defined in National Instrument<br />
52-109 - Certification of Disclosure in Issuer’s Annual and Interim Filings (“National Instrument 52-109”), or caused <strong>the</strong>m <strong>to</strong><br />
be designed under <strong>the</strong>ir supervision. As of December 31, 2011, our Chief Executive Officer (“CEO”) and our Chief Financial<br />
Officer (“CFO”) carried out an internal evaluation of <strong>the</strong> effectiveness of our disclosure controls and procedures. Based on that<br />
evaluation, our CEO and CFO concluded that <strong>the</strong> disclosure controls and procedures provide reasonable assurance that all<br />
material information relating <strong>to</strong> us is made known <strong>to</strong> us by o<strong>the</strong>rs and all information required <strong>to</strong> be disclosed in our annual<br />
and interim filings is recorded, processed, summarized and <strong>report</strong>ed within <strong>the</strong> time periods specified in applicable<br />
Canadian securities legislation. Our CEO and CFO are responsible for establishing and maintaining internal control over<br />
financing <strong>report</strong>ing (“ICFR”), as such term is defined in National Instrument 52-109. The control framework <strong>the</strong> CEO and CFO<br />
used <strong>to</strong> design <strong>the</strong> Company’s ICFR is <strong>the</strong> framework established by <strong>the</strong> Committee of Sponsoring Organizations entitled<br />
Internals Controls – Integrated Framework (<strong>the</strong> “COSO Framework”).<br />
Under <strong>the</strong> supervision of <strong>the</strong> CEO and <strong>the</strong> CFO, <strong>the</strong> Company conducted an evaluation of <strong>the</strong> effectiveness of our ICFR as<br />
at December 31, 2011 based on <strong>the</strong> COSO Framework. Based on this evaluation, <strong>the</strong>y concluded that as of December 31,<br />
2011, our ICFR provides reasonable assurance regarding <strong>the</strong> reliability of financial <strong>report</strong>ing and <strong>the</strong> preparation of financial<br />
statements for external purposes in accordance with IFRS.<br />
Effective April 26, 2011, we migrated our downstream segment <strong>to</strong> <strong>the</strong> new ERP system, Microsoft Dynamics AX, <strong>to</strong> <strong>complete</strong><br />
<strong>the</strong> roll out of <strong>the</strong> system implementation which started during 2010 financial year. In addition <strong>to</strong> <strong>the</strong> MS Dynamics AX, <strong>the</strong><br />
downstream segment also implemented MS Dynamics NAV, fuel distribution system <strong>to</strong> process sales orders and manages<br />
inven<strong>to</strong>ry and warehousing. This migration has effectively <strong>complete</strong>d <strong>the</strong> ERP system implementation resulting in all our<br />
business segments running on a single ERP platform.<br />
Management has reviewed <strong>the</strong> internal controls over financial <strong>report</strong>ing affected by <strong>the</strong> implementation of <strong>the</strong> new ERP<br />
System and made appropriate changes <strong>to</strong> internal controls as part of <strong>the</strong> implementation. Following <strong>the</strong> implementation,<br />
<strong>the</strong>se new controls were evaluated and tested according <strong>to</strong> our established processes. Based on this evaluation, we believe<br />
that we have designed adequate and appropriate internal control over financial <strong>report</strong>ing <strong>to</strong> ensure that <strong>the</strong> financial<br />
statements were materially accurate for <strong>the</strong> year ended December 31, 2011.<br />
During <strong>the</strong> year ended December 31, 2011, <strong>the</strong>re has been no o<strong>the</strong>r change in our internal control over financial <strong>report</strong>ing that<br />
has materially affected, or is reasonably likely <strong>to</strong> affect, our internal control over financial <strong>report</strong>ing, o<strong>the</strong>r than as noted above.<br />
58
Management’s Report<br />
The management of <strong>InterOil</strong> <strong>Corporation</strong> is responsible for <strong>the</strong> financial information and operating<br />
data presented in this Annual Report.<br />
The consolidated financial statements have been prepared by management in accordance with<br />
International Financial Reporting Standards. When alternative accounting methods exist, management has<br />
chosen those it deems most appropriate in <strong>the</strong> circumstances. Financial statements are not precise as <strong>the</strong>y<br />
include certain amounts based on estimates and judgments. Management has determined such amounts<br />
on a reasonable basis in order <strong>to</strong> ensure that <strong>the</strong> financial statements are presented fairly, in all material<br />
respects. Financial information presented elsewhere in this Annual Report has been prepared on a basis<br />
consistent with that in <strong>the</strong> consolidated financial statements.<br />
<strong>InterOil</strong> <strong>Corporation</strong> maintains systems of internal accounting and administrative controls. These systems<br />
are designed <strong>to</strong> provide reasonable assurance that <strong>the</strong> financial information is relevant, reliable and accurate<br />
and that <strong>the</strong> Company’s assets are properly accounted for and adequately safeguarded.<br />
The Audit Committee, appointed by <strong>the</strong> Board of Direc<strong>to</strong>rs, is composed of independent non-management<br />
direc<strong>to</strong>rs. The Committee meets regularly with management, as well as <strong>the</strong> independent audi<strong>to</strong>rs, <strong>to</strong><br />
discuss auditing, internal controls, accounting policy and financial <strong>report</strong>ing matters. The Committee reviews<br />
<strong>the</strong> annual consolidated financial statements with both management and <strong>the</strong> independent audi<strong>to</strong>rs and<br />
<strong>report</strong>s its findings <strong>to</strong> <strong>the</strong> Board of Direc<strong>to</strong>rs before such statements are approved by <strong>the</strong> Board.<br />
The 2011 consolidated financial statements have been audited by PricewaterhouseCoopers, <strong>the</strong><br />
independent audi<strong>to</strong>rs, in accordance with Canadian generally accepted auditing standards and auditing<br />
standards issued by <strong>the</strong> Public Company Accounting Oversight Board, on behalf of <strong>the</strong> shareholders.<br />
PricewaterhouseCoopers has full and free access <strong>to</strong> <strong>the</strong> Audit Committee.<br />
Phil E. Mulacek<br />
Chief Executive Officer<br />
Collin F. Visaggio<br />
Chief Financial Officer<br />
59
March 16, 2012<br />
Independent Audi<strong>to</strong>r’s Report<br />
To <strong>the</strong> Shareholders of <strong>InterOil</strong> <strong>Corporation</strong><br />
We have <strong>complete</strong>d an integrated audit of <strong>InterOil</strong> <strong>Corporation</strong> 2011 consolidated financial statements and its<br />
internal control over financial <strong>report</strong>ing as at December 31, 2011 and an audit of its 2010 consolidated financial<br />
statements. Our opinions, based on our audits, are presented below.<br />
Report on <strong>the</strong> consolidated financial statements<br />
We have audited <strong>the</strong> accompanying consolidated financial statements of <strong>InterOil</strong> <strong>Corporation</strong>, which comprise <strong>the</strong><br />
Consolidated Balance Sheets as at December 31, 2011, December 31, 2010 and January 1, 2010 and <strong>the</strong><br />
Consolidated Income Statements, Statements of Comprehensive Income, Changes in Equity and Cash Flows for<br />
<strong>the</strong> years ended December 31, 2011 and December 31, 2010, and <strong>the</strong> related notes, which comprise a summary of<br />
significant accounting policies and o<strong>the</strong>r explana<strong>to</strong>ry information.<br />
Management’s responsibility for <strong>the</strong> consolidated financial statements<br />
Management is responsible for <strong>the</strong> preparation and fair presentation of <strong>the</strong>se consolidated financial statements in<br />
accordance with International Financial Reporting Standards as issued by <strong>the</strong> International Accounting Standards<br />
Board and for such internal control as management determines is necessary <strong>to</strong> enable <strong>the</strong> preparation of<br />
consolidated financial statements that are free from material misstatement, whe<strong>the</strong>r due <strong>to</strong> fraud or error.<br />
Audi<strong>to</strong>r’s responsibility<br />
Our responsibility is <strong>to</strong> express an opinion on <strong>the</strong>se consolidated financial statements based on our audits. We<br />
conducted our audits in accordance with Canadian generally accepted auditing standards and <strong>the</strong> standards of <strong>the</strong><br />
Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform<br />
an audit <strong>to</strong> obtain reasonable assurance about whe<strong>the</strong>r <strong>the</strong> consolidated financial statements are free from material<br />
misstatement. Canadian generally accepted auditing standards require that we comply with ethical requirements.<br />
An audit involves performing procedures <strong>to</strong> obtain audit evidence, on a test basis, about <strong>the</strong> amounts and<br />
disclosures in <strong>the</strong> consolidated financial statements. The procedures selected depend on <strong>the</strong> audi<strong>to</strong>r’s judgment,<br />
including <strong>the</strong> assessment of <strong>the</strong> risks of material misstatement of <strong>the</strong> consolidated financial statements, whe<strong>the</strong>r due<br />
<strong>to</strong> fraud or error. In making those risk assessments, <strong>the</strong> audi<strong>to</strong>r considers internal control relevant <strong>to</strong> <strong>the</strong> company’s<br />
preparation and fair presentation of <strong>the</strong> consolidated financial statements in order <strong>to</strong> design audit procedures that<br />
are appropriate in <strong>the</strong> circumstances. An audit also includes evaluating <strong>the</strong> appropriateness of accounting principles<br />
and policies used and <strong>the</strong> reasonableness of accounting estimates made by management, as well as evaluating <strong>the</strong><br />
overall presentation of <strong>the</strong> consolidated financial statements.<br />
We believe that <strong>the</strong> audit evidence we have obtained in our audits is sufficient and appropriate <strong>to</strong> provide a basis for<br />
our audit opinion on <strong>the</strong> consolidated financial statements.<br />
Opinion<br />
In our opinion, <strong>the</strong> consolidated financial statements present fairly, in all material respects, <strong>the</strong> financial position of<br />
<strong>InterOil</strong> <strong>Corporation</strong> as at December 31, 2011, December 31, 2010 and January 1, 2010 and its financial<br />
performance and its cash flows for years ended December 31, 2011 and December 31, 2010 in accordance with<br />
International Financial Reporting Standards as issued by <strong>the</strong> International Accounting Standards Board.<br />
PricewaterhouseCoopers, ABN 52 780 433 757<br />
Darling Park Tower 2, 201 Sussex Street, GPO BOX 2650, SYDNEY NSW1171<br />
T +61 2 8266 0000, F +61 2 8266 9999, www.pwc.com.au<br />
60
Report on internal control over financial <strong>report</strong>ing<br />
We have also audited <strong>InterOil</strong> <strong>Corporation</strong>’s internal control over financial <strong>report</strong>ing as at December 31, 2011, based<br />
on criteria established in Internal Control - Integrated Framework, issued by <strong>the</strong> Committee of Sponsoring<br />
Organizations of <strong>the</strong> Treadway Commission (COSO).<br />
Management’s responsibility for internal control over financial <strong>report</strong>ing<br />
Management is responsible for maintaining effective internal control over financial <strong>report</strong>ing and for its assessment of<br />
<strong>the</strong> effectiveness of internal control over financial <strong>report</strong>ing included in Management’s Report on Internal Control over<br />
Financial Reporting.<br />
Audi<strong>to</strong>r’s responsibility<br />
Our responsibility is <strong>to</strong> express an opinion on <strong>the</strong> company’s internal control over financial <strong>report</strong>ing based on our<br />
audit. We conducted our audit of internal control over financial <strong>report</strong>ing in accordance with <strong>the</strong> standards of <strong>the</strong><br />
Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform <strong>the</strong><br />
audit <strong>to</strong> obtain reasonable assurance about whe<strong>the</strong>r effective internal control over financial <strong>report</strong>ing was maintained<br />
in all material respects.<br />
An audit of internal control over financial <strong>report</strong>ing includes obtaining an understanding of internal control over<br />
financial <strong>report</strong>ing, assessing <strong>the</strong> risk that a material weakness exists, testing and evaluating <strong>the</strong> design and<br />
operating effectiveness of internal control, based on <strong>the</strong> assessed risk, and performing such o<strong>the</strong>r procedures as we<br />
consider necessary in <strong>the</strong> circumstances.<br />
We believe that our audit provides a reasonable basis for our audit opinion on <strong>the</strong> company’s internal control over<br />
financial <strong>report</strong>ing.<br />
Definition of internal control over financial <strong>report</strong>ing<br />
A company’s internal control over financial <strong>report</strong>ing is a process designed <strong>to</strong> provide reasonable assurance<br />
regarding <strong>the</strong> reliability of financial <strong>report</strong>ing and <strong>the</strong> preparation of financial statements for external purposes in<br />
accordance with generally accepted accounting principles. A company’s internal control over financial <strong>report</strong>ing<br />
includes those policies and procedures that: (i) pertain <strong>to</strong> <strong>the</strong> maintenance of records that, in reasonable detail,<br />
accurately and fairly reflect <strong>the</strong> transactions and dispositions of <strong>the</strong> assets of <strong>the</strong> company; (ii) provide reasonable<br />
assurance that transactions are recorded as necessary <strong>to</strong> permit preparation of financial statements in accordance<br />
with generally accepted accounting principles, and that receipts and expenditures of <strong>the</strong> company are being made<br />
only in accordance with authorizations of management and direc<strong>to</strong>rs of <strong>the</strong> company; and (iii) provide reasonable<br />
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of <strong>the</strong> company’s<br />
assets that could have a material effect on <strong>the</strong> financial statements.<br />
Inherent limitations<br />
Because of its inherent limitations, internal control over financial <strong>report</strong>ing may not prevent or detect misstatements.<br />
Also, projections of any evaluation of effectiveness <strong>to</strong> future periods are subject <strong>to</strong> <strong>the</strong> risk that controls may become<br />
inadequate because of changes in conditions or that <strong>the</strong> degree of compliance with <strong>the</strong> policies or procedures may<br />
deteriorate.<br />
Opinion<br />
In our opinion, <strong>InterOil</strong> <strong>Corporation</strong> maintained, in all material respects, effective internal control over financial<br />
<strong>report</strong>ing as at December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued<br />
by COSO.<br />
Charterd Accountants<br />
March 16, 2012<br />
PricewaterhouseCoopers<br />
Sydney, Australia<br />
PricewaterhouseCoopers, ABN 52 780 433 757<br />
Darling Park Tower 2, 201 Sussex Street, GPO BOX 2650, SYDNEY NSW1171<br />
T +61 2 8266 0000, F +61 2 8266 9999, www.pwc.com.au<br />
61
Consolidated Financial Statements<br />
Consolidated Income Statements<br />
(Expressed in United States dollars)<br />
Year ended December 31,<br />
2011 2010<br />
$ $<br />
Revenue<br />
Sales and operating revenues 1,106,533,853 802,374,399<br />
Interest 1,356,124 150,816<br />
O<strong>the</strong>r 11,058,090 4,470,048<br />
1,118,948,067 806,995,263<br />
Changes in inven<strong>to</strong>ries of finished goods and work in progress 43,934,439 57,010,311<br />
Raw materials and consumables used (1,064,866,361) (758,566,961)<br />
Administrative and general expenses (41,160,824) (41,047,949)<br />
Derivative gains/(losses) 2,006,321 (1,065,188)<br />
Legal and professional fees (6,801,334) (6,902,241)<br />
Exploration costs, excluding exploration impairment (note 13) (18,435,150) (16,981,929)<br />
Finance costs (18,163,769) (12,064,982)<br />
Depreciation and amortization (20,136,649) (14,274,922)<br />
Gain on sale of oil and gas properties - 2,140,783<br />
Loss on extinguishment of liability - (30,568,710)<br />
Litigation settlement expense - (12,000,000)<br />
Loss on available-for-sale investment (note 14) (3,420,406) -<br />
Foreign exchange gains/(losses) 25,018,661 (10,776,823)<br />
(1,102,025,072) (845,098,611)<br />
Profit/(loss) before income taxes 16,922,995 (38,103,348)<br />
Income taxes<br />
Current tax expense (note 15) (5,512,842) (3,898,067)<br />
Deferred tax benefit/(expense) (note 15) 6,248,509 (2,511,656)<br />
735,667 (6,409,723)<br />
Profit/(loss) for <strong>the</strong> year 17,658,662 (44,513,071)<br />
Profit/(loss) is attributable <strong>to</strong>:<br />
Owners of <strong>InterOil</strong> <strong>Corporation</strong> 17,652,461 (44,519,573)<br />
Non-controlling interest 6,201 6,502<br />
17,658,662 (44,513,071)<br />
Basic profit/(loss) per share 0.37 (1.00)<br />
Diluted profit/(loss) per share 0.36 (1.00)<br />
Weighted average number of common shares outstanding<br />
Basic (Expressed in number of common shares) 47,977,478 44,329,670<br />
Diluted (Expressed in number of common shares) 49,214,190 44,329,670<br />
Year ended December 31,<br />
2011 2010<br />
$ $<br />
Profit/(loss) for <strong>the</strong> year 17,658,662 (44,513,071)<br />
O<strong>the</strong>r comprehensive income:<br />
Exchange difference on translation of foreign operations, net of tax 20,527,270 1,110,201<br />
Movement on available-for-sale financial assets, net of tax (407,565) -<br />
O<strong>the</strong>r comprehensive income for <strong>the</strong> year, net of tax 20,119,705 1,110,201<br />
Total comprehensive income/(loss) for <strong>the</strong> year 37,778,367 (43,402,870)<br />
Total comprehensive income/(loss) for <strong>the</strong> year is attributable <strong>to</strong>:<br />
Owners of <strong>InterOil</strong> <strong>Corporation</strong> 37,772,166 (43,409,372)<br />
Non-controlling interests 6,201 6,502<br />
37,778,367 (43,402,870)<br />
See accompanying notes <strong>to</strong> <strong>the</strong> consolidated financial statements<br />
62
Consolidated Balance Sheet<br />
(Expressed in United States dollars)<br />
Year ended December 31,<br />
2011 2010 2009<br />
$ $ $<br />
Assets<br />
Current assets:<br />
Cash and cash equivalents (note 6) 68,846,441 233,576,821 46,449,819<br />
Cash restricted (note 9) 32,982,001 40,664,995 22,698,829<br />
Short term treasury bills - held-<strong>to</strong>-maturity (note 8) 11,832,110 - -<br />
Trade and o<strong>the</strong>r receivables (note 10) 135,273,600 48,047,496 61,194,136<br />
Derivative financial instruments (note 9) 595,440 - -<br />
O<strong>the</strong>r current assets 867,967 505,059 639,646<br />
Inven<strong>to</strong>ries (note 11) 171,071,799 127,137,360 70,127,049<br />
Prepaid expenses 5,477,596 3,593,574 6,964,950<br />
Total current assets 426,946,954 453,525,305 208,074,429<br />
Non-current assets:<br />
Cash restricted (note 9) 6,268,762 6,613,074 6,609,746<br />
Goodwill (note 17) 6,626,317 6,626,317 6,626,317<br />
Plant and equipment (note 12) 246,043,948 225,205,427 218,794,649<br />
Oil and gas properties (note 13) 362,852,766 255,294,738 172,483,562<br />
Deferred tax assets (note 15) 35,965,273 28,477,690 30,319,163<br />
Available-for-sale investments (note 14) 3,650,786 - -<br />
Total non-current assets 661,407,852 522,217,246 434,833,437<br />
Total assets 1,088,354,806 975,742,551 642,907,866<br />
Liabilities and shareholders' equity<br />
Current liabilities:<br />
Trade and o<strong>the</strong>r payables (note 16) 159,882,177 75,132,880 59,372,354<br />
Income tax payable 4,085,137 955,074 -<br />
Derivative financial instruments (note 9) 11,457 178,578 -<br />
Working capital facilities (note 18) 16,480,503 51,254,326 24,626,419<br />
Unsecured loan and current portion of secured loan (note 20) 19,393,023 14,456,757 9,000,000<br />
Current portion of Indirect participation interest (note 21) 540,002 540,002 540,002<br />
Total current liabilities 200,392,299 142,517,617 93,538,775<br />
Non-current liabilities:<br />
Secured loan (note 20) 26,037,166 34,813,222 43,589,278<br />
2.75% convertible notes liability (note 26) 55,637,630 52,425,489 -<br />
Deferred gain on contributions <strong>to</strong> LNG project (note 22) 5,810,775 8,949,857 10,824,212<br />
Indirect participation interest (note 21) 34,134,840 34,134,387 39,559,718<br />
Asset retirement obligations (note 23) 4,562,269 - -<br />
Deferred tax liabilities (note 15) 1,889,391 - -<br />
Total non-current liabilities 128,072,071 130,322,955 93,973,208<br />
Total liabilities 328,464,370 272,840,572 187,511,983<br />
Equity:<br />
Equity attributable <strong>to</strong> owners of <strong>InterOil</strong> <strong>Corporation</strong>:<br />
Share capital (note 25) 905,981,614 895,651,052 613,361,363<br />
Authorized - unlimited<br />
Issued and outstanding - 48,121,071 (Dec 31, 2010 - 47,800,552)<br />
2.75% convertible notes (note 26) 14,298,036 14,298,036 -<br />
Contributed surplus 25,644,245 16,738,417 21,297,177<br />
Accumulated O<strong>the</strong>r Comprehensive Income 29,380,882 9,261,177 8,150,976<br />
Conversion options (note 21) 12,150,880 12,150,880 13,270,880<br />
Accumulated deficit (227,565,221) (245,217,682) (200,698,109)<br />
63
Year ended December 31,<br />
2011 2010 2009<br />
$ $ $<br />
Total equity attributable <strong>to</strong> owners of <strong>InterOil</strong> <strong>Corporation</strong> 759,890,436 702,881,880 455,382,287<br />
Non-controlling interest - 20,099 13,596<br />
Total equity 759,890,436 702,901,979 455,395,883<br />
Total liabilities and equity 1,088,354,806 975,742,551 642,907,866<br />
See accompanying notes <strong>to</strong> <strong>the</strong> consolidated financial statements<br />
Consolidated Statements of Changes in Equity<br />
(Expressed in United States dollars)<br />
Year ended December 31,<br />
Transactions with owners as owners:<br />
2011 2010<br />
$ $<br />
Share capital<br />
At beginning of year 895,651,052 613,361,363<br />
Issue of capital s<strong>to</strong>ck (note 25) 10,330,562 282,289,689<br />
At end of year 905,981,614 895,651,052<br />
2.75% convertible notes<br />
At beginning of year 14,298,036 -<br />
Issue of convertible notes (note 26) - 14,298,036<br />
At end of year 14,298,036 14,298,036<br />
Contributed surplus<br />
At beginning of year 16,738,417 21,297,177<br />
Fair value of options and restricted s<strong>to</strong>ck transferred <strong>to</strong> share capital (note 27) (5,598,009) (8,454,758)<br />
S<strong>to</strong>ck compensation expense (note 27) 14,721,387 11,804,000<br />
Loss on extinguishment of IPI conversion options (note 21) - (7,908,002)<br />
Loss on buyback of non-controlling interest (note 24) (217,550) -<br />
At end of year 25,644,245 16,738,417<br />
Accumulated O<strong>the</strong>r Comprehensive Income<br />
Foreign currency translation reserve<br />
At beginning of year 9,261,177 8,150,976<br />
Foreign currency translation movement for <strong>the</strong> year, net of tax 20,527,270 1,110,201<br />
Foreign currency translation reserve at end of year 29,788,447 9,261,177<br />
Gain/(loss) on available-for-sale financial assets<br />
At beginning of year - -<br />
Gain/(loss) on available-for-sale financial assets, net of tax (note 14) (407,565) -<br />
Gain/(loss) on available-for-sale financial assets at end of year (407,565) -<br />
Accumulated o<strong>the</strong>r comprehensive income at end of year 29,380,882 9,261,177<br />
Conversion options<br />
At beginning of year 12,150,880 13,270,880<br />
Movement for <strong>the</strong> year (note 21) - (1,120,000)<br />
At end of year 12,150,880 12,150,880<br />
Accumulated deficit<br />
At beginning of year (245,217,682) (200,698,109)<br />
Net profit/(loss) for <strong>the</strong> year 17,652,461 (44,519,573)<br />
At end of year (227,565,221) (245,217,682)<br />
Total <strong>InterOil</strong> <strong>Corporation</strong> shareholders’ equity at end of year 759,890,436 702,881,880<br />
Transactions with non-controlling interest<br />
At beginning of year 20,099 13,597<br />
Net profit for <strong>the</strong> year 6,201 6,502<br />
Buyback of non-controlling interest (note 24) (26,300) -<br />
At end of year - 20,099<br />
Total equity at end of year 759,890,436 702,901,979<br />
64
Consolidated Statements of Changes in Equity<br />
(Expressed in United States dollars)<br />
Year ended December 31,<br />
Transactions with owners as owners:<br />
2011 2010<br />
$ $<br />
Share capital<br />
At beginning of year 895,651,052 613,361,363<br />
Issue of capital s<strong>to</strong>ck (note 25) 10,330,562 282,289,689<br />
At end of year 905,981,614 895,651,052<br />
2.75% convertible notes<br />
At beginning of year 14,298,036 -<br />
Issue of convertible notes (note 26) - 14,298,036<br />
At end of year 14,298,036 14,298,036<br />
Contributed surplus<br />
At beginning of year 16,738,417 21,297,177<br />
Fair value of options and restricted s<strong>to</strong>ck transferred <strong>to</strong> share capital (note 27) (5,598,009) (8,454,758)<br />
S<strong>to</strong>ck compensation expense (note 27) 14,721,387 11,804,000<br />
Loss on extinguishment of IPI conversion options (note 21) - (7,908,002)<br />
Loss on buyback of non-controlling interest (note 24) (217,550) -<br />
At end of year 25,644,245 16,738,417<br />
Accumulated O<strong>the</strong>r Comprehensive Income<br />
Foreign currency translation reserve<br />
At beginning of year 9,261,177 8,150,976<br />
Foreign currency translation movement for <strong>the</strong> year, net of tax 20,527,270 1,110,201<br />
Foreign currency translation reserve at end of year 29,788,447 9,261,177<br />
Gain/(loss) on available-for-sale financial assets<br />
At beginning of year - -<br />
Gain/(loss) on available-for-sale financial assets, net of tax (note 14) (407,565) -<br />
Gain/(loss) on available-for-sale financial assets at end of year (407,565) -<br />
Accumulated o<strong>the</strong>r comprehensive income at end of year 29,380,882 9,261,177<br />
Conversion options<br />
At beginning of year 12,150,880 13,270,880<br />
Movement for <strong>the</strong> year (note 21) - (1,120,000)<br />
At end of year 12,150,880 12,150,880<br />
Accumulated deficit<br />
At beginning of year (245,217,682) (200,698,109)<br />
Net profit/(loss) for <strong>the</strong> year 17,652,461 (44,519,573)<br />
At end of year (227,565,221) (245,217,682)<br />
Total <strong>InterOil</strong> <strong>Corporation</strong> shareholders’ equity at end of year 759,890,436 702,881,880<br />
Transactions with non-controlling interest<br />
At beginning of year 20,099 13,597<br />
Net profit for <strong>the</strong> year 6,201 6,502<br />
Buyback of non-controlling interest (note 24) (26,300) -<br />
At end of year - 20,099<br />
Total equity at end of year 759,890,436 702,901,979<br />
See accompanying notes <strong>to</strong> <strong>the</strong> consolidated financial statements.<br />
65
Consolidated Statement of Cash Flows<br />
(Expressed in United States dollars)<br />
Year ended December 31,<br />
2011 2010<br />
$ $<br />
Cash flows generated from (used in):<br />
Operating activities<br />
Net profit/(loss) for <strong>the</strong> year 17,658,662 (44,513,071)<br />
Adjustments for non-cash and non-operating transactions<br />
Depreciation and amortization 20,136,649 14,274,922<br />
Deferred tax assets (5,598,192) 1,841,473<br />
Gain on sale of exploration assets - (2,140,783)<br />
Accretion of convertible notes liability 3,212,141 432,632<br />
Amortization of deferred financing costs 223,944 1,223,944<br />
Timing difference between derivatives recognized and settled (762,561) 178,578<br />
S<strong>to</strong>ck compensation expense, including restricted s<strong>to</strong>ck 14,721,387 11,804,000<br />
Movement in net realizable value write down 259,406 -<br />
Accretion of asset retirement obligation liability 159,356 -<br />
Oil and gas properties expensed 18,435,150 16,981,929<br />
Loss on extinguishment of IPI Liability - 30,568,710<br />
Non-cash litigation settlement expense - 12,000,000<br />
Loss on Flex LNG investment 3,420,406 -<br />
Gain on proportionate consolidation of LNG project (555,030) -<br />
Unrealized foreign exchange gain (2,618,814) (72,456)<br />
Change in operating working capital<br />
Increase in trade and o<strong>the</strong>r receivables (53,064,305) (9,224,005)<br />
(Increase)/decrease in o<strong>the</strong>r current assets and prepaid expenses (2,246,930) 3,505,963<br />
Increase in inven<strong>to</strong>ries (28,003,484) (56,115,637)<br />
Increase in trade and o<strong>the</strong>r payables 77,291,915 5,692,543<br />
Net cash generated from/(used in) operating activities 62,669,700 (13,561,258)<br />
Investing activities<br />
Expenditure on oil and gas properties (134,927,701) (113,128,916)<br />
Proceeds from IPI cash calls 749,794 23,723,752<br />
Expenditure on plant and equipment (42,050,435) (22,560,055)<br />
Proceeds received on sale of exploration assets - 15,544,465<br />
Investment in short term treasury bills (11,832,110) -<br />
Acquisition of Flex LNG Ltd shares, including transaction costs (7,478,756) -<br />
Decrease/(increase) in restricted cash held as security on borrowings 8,027,306 (17,969,494)<br />
Change in non-operating working capital<br />
Increase in trade and o<strong>the</strong>r receivables (10,000,000) -<br />
(Decrease)/increase in trade and o<strong>the</strong>r payables (6,727,960) 3,232,029<br />
Net cash used in investing activities (204,239,862) (111,158,219)<br />
Financing activities<br />
Repayments of OPIC secured loan (9,000,000) (9,000,000)<br />
Proceeds from Mitsui for Condensate Stripping Plant 9,872,532 11,913,514<br />
Proceeds from/(repayments of) Clarion Finanz secured loan, net of transaction costs - (1,000,000)<br />
Proceeds from PNG LNG cash call 2,247,533 866,600<br />
Proceeds from Petromin for Elk and Antelope field development - 5,000,000<br />
(Repayments of)/proceeds from working capital facility (34,773,823) 26,627,907<br />
Proceeds from issue of common shares, net of transaction costs 4,488,703 211,147,565<br />
Proceeds from issue of convertible notes, net of transaction costs - 66,290,893<br />
Net cash (used in)/generated from financing activities (27,165,055) 311,846,479<br />
(Decrease)/increase in cash and cash equivalents (168,735,217) 187,127,002<br />
Cash and cash equivalents, beginning of year 233,576,821 46,449,819<br />
66
Year ended December 31,<br />
2011 2010<br />
$ $<br />
Exchange gains on cash and cash equivalents 4,004,837 -<br />
Cash and cash equivalents, end of year (note 6) 68,846,441 233,576,821<br />
Comprising of:<br />
Cash on Deposit 18,758,288 233,576,821<br />
Term Deposits 50,088,153 -<br />
Total cash and cash equivalents, end of year 68,846,441 233,576,821<br />
See accompanying notes <strong>to</strong> <strong>the</strong> consolidated financial statements<br />
Notes <strong>to</strong> Consolidated Financial Statements<br />
(Expressed in United States dollars)<br />
1. General Information<br />
<strong>InterOil</strong> <strong>Corporation</strong> (<strong>the</strong> “Company” or “<strong>InterOil</strong>”) is a publicly traded, integrated oil and gas company operating in Papua<br />
New Guinea (“PNG”). The Company is incorporated and domiciled in Canada. The Company is a Yukon Terri<strong>to</strong>ry corporation,<br />
continued under <strong>the</strong> Business <strong>Corporation</strong>s Act (Yukon Terri<strong>to</strong>ry) on August 24, 2007. The address of its registered office is<br />
300-204 Black Street, Whitehorse, Yukon, Canada.<br />
Management has organized <strong>the</strong> Company’s operations in<strong>to</strong> four major segments - Upstream, Midstream, Downstream and<br />
Corporate. Upstream includes exploration, appraisal and development operations for crude oil and natural gas structures in<br />
PNG. Upstream currently includes <strong>the</strong> development of <strong>the</strong> Elk and Antelope fields infrastructure, including <strong>the</strong> condensate<br />
stripping and associated facilities, and <strong>the</strong> gas ga<strong>the</strong>ring and associated common facilities, in connection with<br />
commercializing significant gas discoveries. Midstream consists of both Midstream Refining and Midstream Liquefaction.<br />
Midstream Refining includes refining of products for <strong>the</strong> domestic market in PNG and exports, and Midstream Liquefaction<br />
includes <strong>the</strong> work being undertaken <strong>to</strong> develop liquefaction and associated facilities (”LNG project”) in PNG for <strong>the</strong> export of<br />
liquefied natural gas. Downstream includes wholesale and retail distribution of refined products in PNG. Corporate engages<br />
in business development and improvement, common services and management, financing and treasury, product shipping,<br />
government and inves<strong>to</strong>r relations. Common and integrated costs are recovered from <strong>report</strong>ing segments on an equitable<br />
driver basis.<br />
These consolidated financial statements were approved for issue on March 16, 2012.<br />
2. Significant accounting policies<br />
The accounting policies set out below have been applied consistently <strong>to</strong> all years presented in <strong>the</strong>se consolidated financial<br />
statements and in preparing <strong>the</strong> opening IFRS balance sheet at January 1, 2010 for <strong>the</strong> purposes of <strong>the</strong> transition <strong>to</strong> IFRSs as<br />
if <strong>the</strong>se policies had always been in effect unless o<strong>the</strong>rwise indicated.<br />
(a) Basis of preparation and adoption of IFRS<br />
The Company prepares its consolidated financial statements in accordance with Canadian generally accepted<br />
accounting principles as set out in <strong>the</strong> Handbook of <strong>the</strong> Canadian Institute of Chartered Accountants (“CICA Handbook”). In<br />
2010, <strong>the</strong> CICA Handbook was revised <strong>to</strong> incorporate International Financial Reporting Standards (“IFRS”) and <strong>to</strong> require<br />
publicly accountable enterprises <strong>to</strong> apply such standards effective for years beginning on or after January 1, 2011.<br />
Accordingly, <strong>the</strong> company has commenced <strong>report</strong>ing on this basis from January 1, 2011, and in <strong>the</strong>se consolidated financial<br />
statements prepared for <strong>the</strong> year ended December 31, 2011 (“financial statements”). In <strong>the</strong>se consolidated financial<br />
statements, <strong>the</strong> term “Canadian GAAP” refers <strong>to</strong> Canadian GAAP before <strong>the</strong> adoption of IFRS.<br />
These consolidated financial statements have been prepared in accordance with IFRS as issued by <strong>the</strong> IASB applicable <strong>to</strong> <strong>the</strong><br />
preparation of financial statements including IFRS 1 – ‘First-time Adoption of International Financial Reporting Standards’.<br />
The effective date of transition is January 1, 2010. An explanation of how <strong>the</strong> transition <strong>to</strong> IFRSs has affected <strong>the</strong> <strong>report</strong>ed<br />
balance sheets, income statements and cash flows of <strong>the</strong> Company is provided in note 3.<br />
67
This note includes reconciliations of equity and <strong>to</strong>tal comprehensive income for comparative years and of equity at <strong>the</strong> date<br />
of transition <strong>report</strong>ed under Canadian GAAP <strong>to</strong> those <strong>report</strong>ed for those years and at <strong>the</strong> date of transition under IFRSs. The<br />
consolidated financial statements for <strong>the</strong> year ended December 31, 2011 have been prepared under <strong>the</strong> his<strong>to</strong>rical cost<br />
convention, except for derivative financial instruments and available-for-sale investments which are measured at fair value.<br />
The preparation of financial statements requires <strong>the</strong> use of certain critical accounting estimates. It also requires management<br />
<strong>to</strong> exercise its judgment in <strong>the</strong> process of applying <strong>the</strong> Company’s accounting policies. Estimates and judgments are<br />
continually evaluated and are based on his<strong>to</strong>rical experience and o<strong>the</strong>r fac<strong>to</strong>rs, including expectations of future events that are<br />
believed <strong>to</strong> be reasonable under <strong>the</strong> circumstances. The Company makes estimates and assumptions concerning <strong>the</strong> future.<br />
The resulting accounting estimates will, by definition, seldom equal <strong>the</strong> related actual results. The estimates and assumptions<br />
that have a significant risk of causing a material adjustment <strong>to</strong> <strong>the</strong> carrying amounts of assets and liabilities within <strong>the</strong> next<br />
financial year are addressed below.<br />
• Net realizable value of inven<strong>to</strong>ry: Inven<strong>to</strong>ry is recorded at <strong>the</strong> lower of cost or net realizable value. To determine <strong>the</strong> net<br />
realizable value of finished goods inven<strong>to</strong>ry, <strong>the</strong> IPP pricing from January 2012 is considered (IPP is based on<br />
December MOPS product pricing) along with estimated Naphtha, LSWR and LPG pricing based on <strong>the</strong> expected date<br />
of sale. The estimates are based on <strong>the</strong> most reliable evidence available at <strong>the</strong> time <strong>the</strong> estimates are made, of <strong>the</strong><br />
amounts that are expected <strong>to</strong> be realized. These estimates take in<strong>to</strong> consideration fluctuations of price or cost directly<br />
relating <strong>to</strong> events occurring after <strong>the</strong> end of <strong>the</strong> period <strong>to</strong> <strong>the</strong> extent that such events confirm conditions existing at <strong>the</strong><br />
end of <strong>the</strong> <strong>report</strong>ing period.<br />
• Convertible notes: The convertible notes are assessed based on <strong>the</strong> substance of <strong>the</strong> contractual arrangement in<br />
determining whe<strong>the</strong>r it exhibits <strong>the</strong> fundamental characteristic of a financial liability or equity. Management has<br />
assessed that <strong>the</strong> note instrument mainly exhibits characteristics that are liability in nature, however, <strong>the</strong> embedded<br />
conversion feature is in equity in nature and needs <strong>to</strong> be bifurcated and disclosed separately within equity.<br />
Management applied residual basis and valued <strong>the</strong> liability component first and assigned <strong>the</strong> residual value <strong>to</strong> <strong>the</strong><br />
equity component. Management fair valued <strong>the</strong> liability component by deducting <strong>the</strong> premium paid by holders<br />
specifically for <strong>the</strong> conversion feature. The conversion price of $95.625 per share includes a premium of 27.5% <strong>to</strong> <strong>the</strong><br />
issue price of <strong>the</strong> concurrent common shares offering of $75 per share. Therefore, <strong>the</strong> $70,000,000 <strong>to</strong>tal issue<br />
represents 127.5% of <strong>the</strong> liability portion.<br />
• Deferred gain on contributions <strong>to</strong> LNG project: The Company has a recognized deferred gain on its contributions <strong>to</strong> <strong>the</strong><br />
Joint Venture based on <strong>the</strong> share of o<strong>the</strong>r joint venture partners in <strong>the</strong> project. As <strong>InterOil</strong>’s shareholding within <strong>the</strong> Joint<br />
Venture Company as at December 31, 2011 is 84.582%, <strong>the</strong> gain on contribution of non cash assets <strong>to</strong> <strong>the</strong><br />
project by <strong>InterOil</strong> relating <strong>to</strong> o<strong>the</strong>r joint venture partners’ shareholding (15.418% - amounting <strong>to</strong> $15,113,190) has<br />
been recognized by <strong>InterOil</strong> in its balance sheet as a deferred gain. This deferred gain will increase/decrease as <strong>the</strong><br />
o<strong>the</strong>r Joint Venture partners decrease/increase <strong>the</strong>ir shareholding in <strong>the</strong> project.<br />
This amount has been recorded as a reduction of deferred LNG project costs of $9,302,415 at December 31, 2011<br />
which has reduced <strong>the</strong> LNG project costs <strong>to</strong> nil at December 31, 2011, with <strong>the</strong> remaining balance of $5,810,775<br />
being recorded as a deferred gain. The deferred gain will be recognized in <strong>the</strong> consolidated income statement when<br />
<strong>the</strong> risks and rewards have considered <strong>to</strong> be passed.<br />
• Asset retirement obligation: A liability is recognized for future legal or constructive retirement obligations associated with<br />
<strong>the</strong> Company’s property, plant and equipment. The amount recognized is <strong>the</strong> net present value of <strong>the</strong> estimated costs<br />
of future dismantlement, site res<strong>to</strong>ration and abandonment of properties based upon current regulations and economic<br />
circumstances at period end. During <strong>the</strong> quarter ended June 30, 2011, Management received <strong>the</strong> results of an<br />
independent assessment of <strong>the</strong> potential asset retirement obligations of <strong>the</strong> refinery. As a result of this assessment,<br />
Management has recognized an asset retirement obligation at December 31, 2011 of $4,562,269.<br />
• Share-based payments: The fair value of s<strong>to</strong>ck options at grant date is determined using a Black-Scholes option<br />
pricing model that takes in<strong>to</strong> account <strong>the</strong> exercise price, <strong>the</strong> terms of <strong>the</strong> option, <strong>the</strong> vesting criteria, <strong>the</strong> share price at<br />
grant date, expected price volatility of <strong>the</strong> underlying share, <strong>the</strong> expected yield and risk-free interest rate for <strong>the</strong> term<br />
of <strong>the</strong> option. Upon exercise of options, <strong>the</strong> balance of <strong>the</strong> contributed surplus relating <strong>to</strong> those options is transferred<br />
<strong>to</strong> share capital. The fair value of restricted s<strong>to</strong>ck on grant date is <strong>the</strong> market value of <strong>the</strong> s<strong>to</strong>ck. The Company uses<br />
<strong>the</strong> fair value based method <strong>to</strong> account for employee s<strong>to</strong>ck based compensation benefits. Under <strong>the</strong> fair value based<br />
method, compensation expense is measured at fair value at <strong>the</strong> date of grant and is expensed over <strong>the</strong> award’s vesting<br />
period.<br />
68
Rate Regulation<br />
<strong>InterOil</strong> is currently <strong>the</strong> sole refiner of hydrocarbons in PNG. The Company’s 30 year project agreement with <strong>the</strong> Independent<br />
State of Papua New Guinea (“<strong>the</strong> State”) expires in 2035. The State has undertaken <strong>to</strong> ensure that all domestic distribu<strong>to</strong>rs<br />
purchase <strong>the</strong>ir refined petroleum products from <strong>the</strong> Company’s refinery, or any o<strong>the</strong>r refinery which is constructed in PNG, at<br />
an Import Parity Price (”IPP”). The IPP is moni<strong>to</strong>red by <strong>the</strong> Papua New Guinea Independent Consumer and Competition<br />
Commission (”ICCC”). In general, <strong>the</strong> IPP is <strong>the</strong> price that would be paid in PNG for a refined product being imported. For all<br />
price controlled products (diesel, unleaded petrol, kerosene and aviation fuel) produced and sold locally in PNG, <strong>the</strong> IPP is<br />
calculated by adding <strong>the</strong> costs that would typically be incurred <strong>to</strong> import such product <strong>to</strong> ‘Mean of Platts Singapore’ (“MOPS”)<br />
which is <strong>the</strong> benchmark price for refined products in <strong>the</strong> region in which <strong>the</strong> Company operates.<br />
<strong>InterOil</strong> is also a significant participant in <strong>the</strong> retail and wholesale distribution business in PNG. The ICCC regulates <strong>the</strong><br />
maximum prices that may be charged by <strong>the</strong> wholesale and retail hydrocarbon distribution industry in PNG. The Downstream<br />
business may charge less than <strong>the</strong> maximum margin set by <strong>the</strong> ICCC in order <strong>to</strong> maintain its competitiveness with o<strong>the</strong>r<br />
participants in <strong>the</strong> market. In November 2010, <strong>the</strong> ICCC released its review <strong>report</strong> which will govern <strong>the</strong> pricing arrangements<br />
for petroleum products in PNG until <strong>the</strong> end of 2014, taking effect from November 1, 2010. The purpose of <strong>the</strong> review was<br />
<strong>to</strong> consider <strong>the</strong> extent <strong>to</strong> which <strong>the</strong> existing regulation of price setting arrangements at both wholesale and retail levels should<br />
continue or be revised for <strong>the</strong> next five year period. The <strong>report</strong> recommended an increase in margins for wholesale business<br />
and certain o<strong>the</strong>r activities, while <strong>the</strong> retail margin is <strong>to</strong> remain <strong>the</strong> same. It also recommended some increases in moni<strong>to</strong>ring<br />
industry activity in PNG mainly, relating <strong>to</strong> import of products by distribu<strong>to</strong>rs and in relation <strong>to</strong> aviation fuel pricing.<br />
No rate regulated assets or liabilities have been recognized.<br />
(b) Going concern<br />
These consolidated financial statements have been prepared on a going concern basis, which contemplates <strong>the</strong> realization of<br />
assets and settlement of liabilities in <strong>the</strong> normal course of business as <strong>the</strong>y become due.<br />
The net current assets as at December 31, 2011 amounted <strong>to</strong> $226.6 million compared <strong>to</strong> $311.0 million as at December 31,<br />
2010. The Company has cash, cash equivalents and cash restricted of $108.1 million as at December 31, 2011 (December<br />
2010 - $280.9 million), of which $39.3 million is restricted (December 2010 - $47.3 million). The Company also has<br />
investments in Bank of PNG treasury bills of $11.8 million as at December 31, 2011 (December 2010 - $nil).<br />
With respect <strong>to</strong> its Upstream operations, <strong>the</strong> Company has no obligation <strong>to</strong> execute exploration activities within a set<br />
timeframe and <strong>the</strong>refore has <strong>the</strong> ability <strong>to</strong> select <strong>the</strong> timing of <strong>the</strong>se activities as long as <strong>the</strong> minimum license commitments in<br />
relation <strong>to</strong> <strong>the</strong> Company’s Petroleum Prospecting Licenses (“PPL”) and Petroleum Retention Licenses (“PRL”) are met. Refer<br />
note 29 for fur<strong>the</strong>r information on <strong>the</strong>se commitments.<br />
The Company has a short term <strong>to</strong>tal working capital facility of $230.0 million (increased temporarily <strong>to</strong> $260.0 million in<br />
November 2011, and reverted back <strong>to</strong> $230.0 million on January 31, 2012) for its Midstream – Refining operation that is<br />
renewable annually with BNP Paribas. This facility is secured by <strong>the</strong> assets it is drawn down against. As at December 31,<br />
2011 $174.9 million of <strong>the</strong> combined facility has been utilized, and <strong>the</strong> remaining facility of $85.1 million (including <strong>the</strong><br />
temporary increase of $30.0 million) remains available for use. The facility was renewed in February 2012 at an increased limit<br />
of $240.0 million until January 31, 2013.<br />
The Company has an approximate $60.6 million (Papua New Guinea Kina (“PGK”) 130.0 million) revolving working capital<br />
facility for its Downstream operations in PNG from Bank of South Pacific Limited (“BSP”) and Westpac Bank PNG Limited<br />
(“Westpac”). As at December 31, 2011, $6.4 million (PGK 13.8 million) of this combined facility has been utilized, and $54.2<br />
million (PGK 116.2 million) of this facility remains available for use. The Westpac facility was for an initial term of three years<br />
and was renewed in November 2011 through <strong>to</strong> November 2014. The facility was fur<strong>the</strong>r increased, subsequent <strong>to</strong> year end<br />
in February 2012, by $4.7 million (PGK 10.0 million) bringing <strong>the</strong> <strong>to</strong>tal facility <strong>to</strong> $65.3 million (PGK 140.0 million). In addition a<br />
secured loan of $15.0 million was provided as part of this increased facility which is repayable in equal installments over 3.5<br />
years with an interest rate of LIBOR + 4.4% per annum. The BSP facility is renewable annually and was renewed in August<br />
2011 through <strong>to</strong> August 2012.<br />
The Company believes that it has sufficient funds for <strong>the</strong> Midstream Refinery and Downstream operations; however, existing<br />
cash balances and ongoing cash generated from <strong>the</strong>se operations will not be sufficient <strong>to</strong> facilitate fur<strong>the</strong>r necessary<br />
development of <strong>the</strong> Elk and Antelope fields, condensate stripping and liquefaction facilities. Therefore <strong>the</strong> Company must<br />
extend or secure sufficient funding through renewed or additional borrowings, equity raising and or asset sales <strong>to</strong> enable<br />
sufficient cash <strong>to</strong> be available <strong>to</strong> fur<strong>the</strong>r its development plans. Management expects that <strong>the</strong> Company will be able <strong>to</strong> secure<br />
69
<strong>the</strong> necessary financing through one, or a combination of, <strong>the</strong> aforementioned alternatives. Accordingly, <strong>the</strong>se consolidated<br />
financial statements have been prepared on a going concern basis in <strong>the</strong> belief that <strong>the</strong> Company will realize its assets and<br />
settle its liabilities and commitments in <strong>the</strong> normal course of business and for at least <strong>the</strong> amounts stated.<br />
(c) New standards issued but not yet effective<br />
The following new standards, new interpretations and amendments <strong>to</strong> standards and interpretations have been issued but are<br />
not yet effective for <strong>the</strong> financial year beginning January 1, 2011 and have not been early adopted:<br />
• IFRS 9 ‘Financial Instruments’ (effective from January 1, 2015): This addresses <strong>the</strong> classification and measurement of<br />
financial assets. The standard is not applicable until January 1, 2015 but is available for early adoption. The Company<br />
is yet <strong>to</strong> assess IFRS 9’s full impact. The Company has not yet decided <strong>to</strong> early adopt IFRS 9.<br />
• IFRS 10 ‘Consolidated Financial Statements’ (effective from January 1, 2013): This builds on existing principles by<br />
identifying <strong>the</strong> concept of control as <strong>the</strong> determining fac<strong>to</strong>r in whe<strong>the</strong>r an entity should be included within <strong>the</strong><br />
consolidated financial statements. The standard provides additional guidance <strong>to</strong> assist in determining control where<br />
this is difficult <strong>to</strong> assess. This new standard might impact <strong>the</strong> entities that a group consolidates as its subsidiaries. The<br />
Company is yet <strong>to</strong> assess IFRS 10’s full impact.<br />
• IFRS 11 ‘Joint Arrangements’ (effective from January 1, 2013): This provides for a more realistic reflection of joint<br />
arrangements by focusing on <strong>the</strong> rights and obligations of <strong>the</strong> arrangement, ra<strong>the</strong>r than its legal form. There are two<br />
types of joint arrangements: joint operations and joint ventures. Joint operations arise where a joint opera<strong>to</strong>r has rights<br />
<strong>to</strong> <strong>the</strong> assets and obligations relating <strong>to</strong> <strong>the</strong> arrangement and hence accounts for its interest in assets, liabilities,<br />
revenue and expenses. Joint ventures arise where <strong>the</strong> joint opera<strong>to</strong>r has rights <strong>to</strong> <strong>the</strong> net assets of <strong>the</strong> arrangement<br />
and hence equity accounts for its interest. Proportional consolidation of joint ventures is no longer allowed. The<br />
Company is yet <strong>to</strong> assess IFRS 11’s full impact.<br />
• IFRS 12 ‘Disclosure of Interests in O<strong>the</strong>r Entities’ (effective from January 1, 2013): This is a new standard on<br />
disclosure requirements for all forms of interests in o<strong>the</strong>r entities, including joint arrangements, associates, special<br />
purpose vehicles and o<strong>the</strong>r off balance sheet vehicles. The Company is yet <strong>to</strong> assess IFRS 12’s full impact.<br />
• IFRS 13 ‘Fair Value Measurement’ (effective from January 1, 2013): This aims <strong>to</strong> improve consistency and reduce<br />
complexity by providing a precise definition of fair value and a single source of fair value measurement and disclosure<br />
requirements for use across IFRSs. The Company is yet <strong>to</strong> assess IFRS 13’s full impact.<br />
• IAS 27 ‘Separate Financial Statements’ (effective from January 1, 2013): This includes <strong>the</strong> provisions on separate<br />
financial statements that are left after <strong>the</strong> control provisions of IAS 27 have been included in <strong>the</strong> new IFRS 10. The<br />
Company is yet <strong>to</strong> assess IAS 27’s full impact.<br />
• IAS 28 ‘Investments in Associates and Joint Ventures’ (effective from January 1, 2013): This now includes <strong>the</strong><br />
requirements for joint ventures, as well as associates, <strong>to</strong> be equity accounted following <strong>the</strong> issue of IFRS 11. The<br />
Company is yet <strong>to</strong> assess IAS 28’s full impact.<br />
• IAS 1 ‘Presentation of financial statements’ (amendment): The IASB has issued an amendment <strong>to</strong> IAS 1, which<br />
changes <strong>the</strong> disclosure of items presented in o<strong>the</strong>r comprehensive income (“OCI”) in <strong>the</strong> statement of comprehensive<br />
income. The IASB originally proposed that all entities should present profit or loss and OCI <strong>to</strong>ge<strong>the</strong>r in a single<br />
statement of comprehensive income. The proposal has been withdrawn and IAS 1 will still permit profit or loss and OCI<br />
<strong>to</strong> be presented in ei<strong>the</strong>r a single statement or in two consecutive statements. The amendment was developed jointly<br />
with <strong>the</strong> FASB, which has removed <strong>the</strong> option in US GAAP <strong>to</strong> present OCI in <strong>the</strong> statement of changes in equity. The<br />
amendment is effective for annual periods starting on or after 1 July 2012, subject <strong>to</strong> EU endorsement. This<br />
amendment will not have any material impact on <strong>the</strong> Company’s financial statements.<br />
(d) Principles of Consolidation<br />
• Business combinations: The Company applies <strong>the</strong> acquisition method <strong>to</strong> account for business combinations. The<br />
consideration transferred for <strong>the</strong> acquisition of a subsidiary is <strong>the</strong> fair value of <strong>the</strong> assets transferred, <strong>the</strong> liabilities<br />
incurred <strong>to</strong> <strong>the</strong> former owners of <strong>the</strong> acquiree and <strong>the</strong> equity interests issued by <strong>the</strong> group. The consideration<br />
transferred includes <strong>the</strong> fair value of any asset or liability resulting from a contingent consideration arrangement.<br />
Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured<br />
initially at <strong>the</strong>ir fair values at <strong>the</strong> acquisition date. The Company recognizes any non-controlling interest in <strong>the</strong> acquiree<br />
on an acquisition-by-acquisition basis, ei<strong>the</strong>r at fair value or at <strong>the</strong> non-controlling interest’s proportionate share of <strong>the</strong><br />
70
ecognized amounts of acquiree’s identifiable net assets.<br />
If <strong>the</strong> business combination is achieved in stages, <strong>the</strong> acquisition date fair value of <strong>the</strong> acquirer’s previously held equity<br />
interest in <strong>the</strong> acquire is remeasured <strong>to</strong> fair value at <strong>the</strong> acquisition date through profit or loss. Any contingent<br />
consideration <strong>to</strong> be transferred by <strong>the</strong> Company is recognized at fair value at <strong>the</strong> acquisition date. Subsequent<br />
changes <strong>to</strong> <strong>the</strong> fair value of <strong>the</strong> contingent consideration that is deemed <strong>to</strong> be an asset or liability is recognized in<br />
accordance with IAS 39 ei<strong>the</strong>r in profit or loss or as a change <strong>to</strong> o<strong>the</strong>r comprehensive income. Contingent<br />
consideration that is classified as equity is not remeasured, and its subsequent settlement is accounted for within<br />
equity.<br />
The Company measures goodwill at <strong>the</strong> acquisition date as <strong>the</strong> fair value of <strong>the</strong> consideration transferred including <strong>the</strong><br />
recognized amount of any non-controlling interests in <strong>the</strong> acquiree, less <strong>the</strong> fair value of <strong>the</strong> identifiable assets acquired<br />
and liabilities assumed, all measured as of <strong>the</strong> acquisition date.<br />
Transaction costs, o<strong>the</strong>r than those associated with <strong>the</strong> issue of debt or equity securities, that <strong>the</strong> Company incurs in<br />
connection with a business combination are expensed as incurred.<br />
• Subsidiaries: The consolidated financial statements of <strong>the</strong> Company incorporates <strong>the</strong> assets, liabilities and results of<br />
<strong>InterOil</strong> <strong>Corporation</strong> and of all subsidiaries as at December 31, 2011 and December 31, 2010, and for <strong>the</strong> periods <strong>the</strong>n<br />
ended. Subsidiaries of <strong>InterOil</strong> <strong>Corporation</strong> as at December 31, 2011 included SP <strong>InterOil</strong> LDC (100%), SPI E<br />
xploration and Production <strong>Corporation</strong> (100%), SPI Distribution Limited (100%), <strong>InterOil</strong> LNG Holdings Inc. (100%),<br />
<strong>InterOil</strong> Australia Pty Ltd (100%), Direct Employment Services Company (100%), <strong>InterOil</strong> New York Inc. (100%), <strong>InterOil</strong><br />
Singapore Pte Ltd (100%), <strong>InterOil</strong> Finance Inc. (100%), <strong>InterOil</strong> Shipping Pte Ltd (100%) and <strong>the</strong>ir subsidiaries. <strong>InterOil</strong><br />
<strong>Corporation</strong> and its subsidiaries <strong>to</strong>ge<strong>the</strong>r are referred <strong>to</strong> in <strong>the</strong>se consolidated financial statements as <strong>the</strong> Company or<br />
<strong>the</strong> consolidated entity.<br />
Subsidiaries are all those entities over which <strong>the</strong> Company has <strong>the</strong> power <strong>to</strong> determine strategic operating, investing<br />
and financing policies without <strong>the</strong> cooperation of o<strong>the</strong>rs. The existence and effect of potential voting rights that are<br />
currently exercisable or convertible are considered when assessing whe<strong>the</strong>r <strong>the</strong> Company controls ano<strong>the</strong>r entity.<br />
Subsidiaries are fully consolidated from <strong>the</strong> date on which control is transferred <strong>to</strong> <strong>the</strong> Company. They are de<br />
consolidated from <strong>the</strong> date that control ceases.<br />
Intercompany transactions, balances and unrealized gains on transactions between companies are eliminated on<br />
consolidation. Non-controlling interests in <strong>the</strong> results and equity of subsidiaries are shown separately in <strong>the</strong><br />
consolidated income statements, statements of comprehensive income, balance sheets and statement of changes in<br />
equity.<br />
In April 2010, <strong>InterOil</strong> Shipping Pte Ltd. was incorporated in Singapore as a 100% subsidiary of <strong>InterOil</strong> <strong>Corporation</strong> <strong>to</strong><br />
provide shipping services <strong>to</strong> domestic cus<strong>to</strong>mers within PNG and also <strong>to</strong> export cus<strong>to</strong>mers from PNG.<br />
In May 2010, SPI CSP Holdings Limited was incorporated in PNG as a 100% subsidiary of SPI Exploration &<br />
Production <strong>Corporation</strong> <strong>to</strong> hold <strong>InterOil</strong>’s interest in <strong>the</strong> proposed condensate stripping facilities, including ga<strong>the</strong>ring<br />
condensate pipeline, condensate s<strong>to</strong>rage and associated facilities being progressed in joint venture with Mitsui & Co.<br />
Ltd. (“CS Project”).<br />
In May 2010, SPI Holdings No.1 Limited was incorporated in PNG as a 100% subsidiary of SPI (208) Limited <strong>to</strong> hold an<br />
interest in PRL15. There have been no transactions in this entity as of December 31, 2011.<br />
In May 2010, SPI Holdings No.2 Limited was incorporated in PNG as a 100% subsidiary of SPI (208) Limited <strong>to</strong> hold an<br />
interest in PRL15. There have been no transactions in this entity as of December 31, 2011.<br />
In June 2010, Champion No. 50 Limited was incorporated in PNG as a 100% subsidiary of Liquid Niugini Gas Limited.<br />
In January 2011, this company underwent a change of name <strong>to</strong> LNG Train 1 Limited and <strong>the</strong>n a fur<strong>the</strong>r name change<br />
in February 2011 <strong>to</strong> LNGL Train 1 Limited. The purpose of LNGL Train 1 Limited is <strong>to</strong> be <strong>the</strong> owner and opera<strong>to</strong>r of a<br />
modular LNG plant <strong>to</strong> be acquired from Energy World <strong>Corporation</strong>. There have been no transactions in this entity as of<br />
December 31, 2011.<br />
In May 2011, SPI Holdings No.3 Limited was incorporated in PNG as a 100% subsidiary of SPI (208) Limited <strong>to</strong> hold an<br />
interest in PRL15. There have been no transactions in this entity as of December 31, 2011.<br />
71
• Proportionate consolidation of Joint Venture interests: The Company’s interests in PNG LNG Inc. is governed by a<br />
Shareholders’ Agreement signed on July 30, 2007 between <strong>the</strong> Joint Ventures’. Guidance under IAS 31 – ‘Interest<br />
in Joint Ventures’ is followed and <strong>the</strong> entity has been proportionately consolidated in <strong>InterOil</strong>’s consolidated financial<br />
statements. The consolidated results of <strong>InterOil</strong>’s proportionate shareholding in <strong>the</strong> LNG Project has been disclosed<br />
separately within <strong>the</strong> segment notes under Midstream - Liquefaction, refer <strong>to</strong> note 5.<br />
(e) Segment Reporting<br />
An operating segment is a component of an enterprise:<br />
• that engages in business activities from which it may earn revenues and incur expenses (including revenues and<br />
expenses relating <strong>to</strong> transactions with o<strong>the</strong>r segments of <strong>the</strong> same enterprise),<br />
• whose operating results are regularly reviewed by <strong>the</strong> chief operating decision maker <strong>to</strong> make decisions about<br />
resources <strong>to</strong> be allocated <strong>to</strong> <strong>the</strong> segment and assess its performance, and<br />
• for which discrete financial information is available.<br />
Segment capital expenditure is <strong>the</strong> <strong>to</strong>tal cost incurred during <strong>the</strong> period <strong>to</strong> acquire property, plant and equipment, and<br />
intangible assets o<strong>the</strong>r than goodwill. Refer <strong>to</strong> note 1 for <strong>the</strong> management’s organization of <strong>the</strong> Company by <strong>report</strong>ing segment.<br />
(f) Foreign Currency<br />
• Functional and presentation currency: These consolidated financial statements are presented in United States Dollars<br />
(“USD”) which is <strong>InterOil</strong>’s functional and presentation currency.<br />
• Foreign currency transactions: Transactions in foreign currencies are translated <strong>to</strong> <strong>the</strong> respective functional currencies<br />
of Company entities at exchange rates at <strong>the</strong> dates of <strong>the</strong> transactions. Monetary assets and liabilities denominated<br />
in foreign currencies at <strong>the</strong> <strong>report</strong>ing date are retranslated <strong>to</strong> <strong>the</strong> functional currency at <strong>the</strong> exchange rate at that date.<br />
The foreign currency gain or loss on monetary items is <strong>the</strong> difference between amortized cost in <strong>the</strong> functional currency<br />
at <strong>the</strong> beginning of <strong>the</strong> period, adjusted for effective interest and payments during <strong>the</strong> period, and <strong>the</strong> amortized cost in<br />
foreign currency translated at <strong>the</strong> exchange rate at <strong>the</strong> end of <strong>the</strong> period.<br />
Non-monetary assets and liabilities denominated in foreign currencies that are measured at fair value are retranslated<br />
<strong>to</strong> <strong>the</strong> functional currency at <strong>the</strong> exchange rate at <strong>the</strong> date that <strong>the</strong> fair value was determined. Non-monetary items in a<br />
foreign currency that are measured in terms of his<strong>to</strong>rical cost are translated using <strong>the</strong> exchange rate at <strong>the</strong> date of <strong>the</strong><br />
transaction. Foreign currency differences arising on retranslation are recognized in profit or loss.<br />
• Foreign operations: For subsidiaries considered <strong>to</strong> be foreign operations, all assets and liabilities denominated in<br />
foreign currency are translated <strong>to</strong> USD at exchange rates in effect at <strong>the</strong> balance sheet date and all revenue and<br />
expense items are translated at <strong>the</strong> rates of exchange in effect at <strong>the</strong> time of <strong>the</strong> transactions. Foreign exchange gains<br />
or losses are recognized and presented in o<strong>the</strong>r comprehensive income and in <strong>the</strong> foreign currency translation reserve<br />
in equity. Goodwill and fair value adjustments arising on <strong>the</strong> acquisition of a foreign operation are treated as assets and<br />
liabilities of <strong>the</strong> foreign operation and translated at <strong>the</strong> closing rate.<br />
(g) Financial Instruments<br />
(i) Non-derivative financial assets<br />
The Company initially recognizes loans and receivables and deposits on <strong>the</strong> date that <strong>the</strong>y are originated. All o<strong>the</strong>r financial<br />
assets (including assets designated at fair value through profit or loss) are recognized initially on <strong>the</strong> trade date at which <strong>the</strong><br />
Company becomes a party <strong>to</strong> <strong>the</strong> contractual provisions of <strong>the</strong> instrument. The Company derecognizes a financial asset when<br />
<strong>the</strong> contractual rights <strong>to</strong> <strong>the</strong> cash flows from <strong>the</strong> asset expire, or it transfers <strong>the</strong> rights <strong>to</strong> receive <strong>the</strong> contractual cash flows<br />
on <strong>the</strong> financial asset in a transaction in which substantially all <strong>the</strong> risks and rewards of ownership of <strong>the</strong> financial asset are<br />
transferred. Any interest in transferred financial assets that is created or retained by <strong>the</strong> Company is recognized as a separate<br />
asset or liability. Financial assets and liabilities are offset and <strong>the</strong> net amount presented in <strong>the</strong> balance sheet when, and only<br />
when, <strong>the</strong> Company has a legal right <strong>to</strong> offset <strong>the</strong> amounts and intends <strong>to</strong> ei<strong>the</strong>r settle on a net basis or <strong>to</strong> realize <strong>the</strong> asset<br />
and settle <strong>the</strong> liability simultaneously. The Company classifies non-derivative financial assets in<strong>to</strong> <strong>the</strong> following categories:<br />
financial assets at fair value through profit or loss, loans or receivables, held <strong>to</strong> maturity financial assets and available-for-sale<br />
financial assets.<br />
• Loans and receivables: Loans and receivables are financial assets with fixed or determinable payments that are not<br />
quoted in an active market. Such assets are recognized initially at fair value plus any directly attributable transaction<br />
costs. Subsequent <strong>to</strong> initial recognition loans and receivables are measured at amortized cost using <strong>the</strong> effective<br />
interest method, less any impairment losses. Loans and receivables comprise of trade and o<strong>the</strong>r receivables.<br />
72
• Held-<strong>to</strong>-maturity: Held-<strong>to</strong>-maturity investments are non-derivative financial assets with fixed or determinable payments<br />
and fixed maturities that <strong>the</strong> Company’s management has <strong>the</strong> positive intention and ability <strong>to</strong> hold <strong>to</strong> maturity.<br />
Held-<strong>to</strong>-maturity financial assets are recognized initially at fair value plus any directly attributable transaction costs.<br />
Subsequent <strong>to</strong> initial recognition, held-<strong>to</strong>-maturity financial assets are measured at amortized cost using <strong>the</strong> effective<br />
interest method, less any impairment losses. If <strong>the</strong> Company were <strong>to</strong> sell o<strong>the</strong>r than an insignificant amount of<br />
held-<strong>to</strong>-maturity financial assets, <strong>the</strong> whole category would be tainted and reclassified as available-for-sale.<br />
Held-<strong>to</strong>-maturity financial assets are included in non-current assets, except for those with maturities less than 12<br />
months from <strong>the</strong> end of <strong>the</strong> <strong>report</strong>ing period, which are classified as current assets.<br />
• Available-for-sale: Available-for-sale financial assets are non-derivative financial assets that are designated as available<br />
for sale or are not classified in any of <strong>the</strong> o<strong>the</strong>r categories. The Company’s investments in equity securities are<br />
classified as available-for-sale financial assets. Subsequent <strong>to</strong> initial recognition, <strong>the</strong>y are measured at fair value and<br />
changes <strong>the</strong>rein, o<strong>the</strong>r than impairment losses, are recognized in o<strong>the</strong>r comprehensive income. When an investment is<br />
derecognized, <strong>the</strong> gain or loss accumulated in equity is reclassified <strong>to</strong> profit or loss.<br />
(ii) Non-derivative financial liabilities<br />
The Company initially recognizes debt securities issued and subordinated liabilities on <strong>the</strong> date that <strong>the</strong>y originated. All o<strong>the</strong>r<br />
financial liabilities (including liabilities designated at fair value through profit or loss) are recognized initially on <strong>the</strong> trade date at<br />
which <strong>the</strong> Company becomes a party <strong>to</strong> <strong>the</strong> contractual provisions of <strong>the</strong> instrument. The Company derecognizes a financial<br />
liability when its contractual obligations are discharged or cancelled or expire. Financial assets and liabilities are offset and <strong>the</strong><br />
net amount presented in <strong>the</strong> balance sheet when, and only when, <strong>the</strong> Company has a legal right <strong>to</strong> offset <strong>the</strong> amounts and<br />
intends <strong>to</strong> ei<strong>the</strong>r settle on a net basis or <strong>to</strong> realize <strong>the</strong> asset and settle <strong>the</strong> liability simultaneously.<br />
The Company classifies non-derivative financial liabilities in<strong>to</strong> <strong>the</strong> o<strong>the</strong>r financial liabilities category. Financial liabilities not<br />
designated at fair value through profit or loss are recognized initially at fair value plus any directly attributable transaction<br />
costs. Subsequent <strong>to</strong> initial recognition, <strong>the</strong>se financial liabilities are measured at amortized cost using <strong>the</strong> effective interest<br />
method. O<strong>the</strong>r financial liabilities comprise secured and unsecured loans, bank overdrafts, and trade and o<strong>the</strong>r payables.<br />
Trades and o<strong>the</strong>r payables represent liabilities for goods and services provided <strong>to</strong> <strong>the</strong> Company prior <strong>to</strong> <strong>the</strong> end of financial<br />
period which are unpaid. These amounts are unsecured and are usually paid within 30 days of recognition.<br />
(iii) Derivative financial instruments<br />
Derivative financial instruments are utilized by <strong>the</strong> Company in <strong>the</strong> management of its crude purchase cost exposures, its<br />
finished products sales price exposures and its foreign exchange management. The Company’s policy is not <strong>to</strong> utilize<br />
derivative financial instruments for trading or speculative purposes. The Company may choose <strong>to</strong> designate derivative<br />
financial instruments as hedges.<br />
When applicable, at <strong>the</strong> inception of <strong>the</strong> hedge, <strong>the</strong> Company formally documents all relationships between hedging<br />
instruments and <strong>the</strong> hedged items, as well as its risk management objective and strategy for undertaking various hedge<br />
transactions, <strong>the</strong> nature of <strong>the</strong> risk being hedged, how <strong>the</strong> hedging instruments’ effectiveness in offsetting <strong>the</strong> hedged risk will<br />
be assessed and a description of <strong>the</strong> method for measuring effectiveness. This process includes linking all derivatives <strong>to</strong> specific<br />
assets and liabilities on <strong>the</strong> balance sheet or <strong>to</strong> specific firm commitments or anticipated transactions. The Company also<br />
assesses whe<strong>the</strong>r <strong>the</strong> derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or<br />
cash flows of hedged items at inception and on an ongoing basis.<br />
Changes in <strong>the</strong> fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are<br />
recorded as a component of O<strong>the</strong>r Comprehensive Income until earnings are affected by <strong>the</strong> variability in cash flows of <strong>the</strong><br />
designated hedged item. For cash flow hedges that have been terminated or cease <strong>to</strong> be effective, prospective gains or<br />
losses on <strong>the</strong> derivative are recognized in earnings. Any gain or loss that has been included in accumulated o<strong>the</strong>r<br />
comprehensive income at <strong>the</strong> time <strong>the</strong> hedge is discontinued continues <strong>to</strong> be deferred in accumulated o<strong>the</strong>r comprehensive<br />
income until <strong>the</strong> original hedged transaction is recognized in earnings. If <strong>the</strong> likelihood of <strong>the</strong> original hedged transaction<br />
occurring is no longer probable, <strong>the</strong> entire gain or loss in accumulated o<strong>the</strong>r comprehensive income related <strong>to</strong> this transaction<br />
is immediately reclassified <strong>to</strong> earnings.<br />
The Company discontinues hedge accounting prospectively when it is determined that <strong>the</strong> derivative is no longer effective in<br />
offsetting changes in cash flows of <strong>the</strong> hedged item, <strong>the</strong> derivative expires or is sold, terminated or exercised, <strong>the</strong> derivative<br />
is no longer designated as a hedging instrument because it is unlikely that a forecasted transaction will occur, a hedged firm<br />
commitment no longer meets <strong>the</strong> definition of a firm commitment or management determines that designation of <strong>the</strong><br />
derivative as a hedging instrument is no longer appropriate.<br />
73
(iv) Compound financial instruments<br />
Compound financial instruments issued by <strong>the</strong> Company comprise convertible notes that can be converted <strong>to</strong> share capital<br />
at <strong>the</strong> option of <strong>the</strong> holder, when <strong>the</strong> number of shares <strong>to</strong> be issued does not vary with changes in <strong>the</strong>ir fair value. The liability<br />
component of a compound financial instrument is recognized initially at fair value of a similar liability that does not have an<br />
equity conversion option. The equity component is recognized initially at <strong>the</strong> difference between <strong>the</strong> fair value of <strong>the</strong><br />
compound financial instrument as a whole and <strong>the</strong> fair value of <strong>the</strong> liability component. Any directly attributable transaction<br />
costs are allocated <strong>to</strong> <strong>the</strong> liability and equity components in proportion <strong>to</strong> <strong>the</strong>ir initial carrying amounts.<br />
Subsequent <strong>to</strong> initial recognition, <strong>the</strong> liability component of a compound financial instrument is measured at amortized cost<br />
using <strong>the</strong> effective interest method. The equity component of a compound financial instrument is not remeasured subsequent<br />
<strong>to</strong> initial recognition. Interest and losses and gains relating <strong>to</strong> <strong>the</strong> financial liability are recognized in profit or loss. On<br />
conversion, <strong>the</strong> financial liability is reclassified <strong>to</strong> equity and no gain or loss is recognized on conversion.<br />
(h) Cash and cash equivalents<br />
Cash and cash equivalents includes cash on hand, deposits held at call with financial institutions, o<strong>the</strong>r short-term, highly<br />
liquid investments with original maturities of three months or less that are readily convertible <strong>to</strong> known amounts of cash and<br />
which are subject <strong>to</strong> insignificant risk of changes in value.<br />
(i) Cash restricted<br />
Cash restricted consists of cash on deposit which is restricted from being used in daily operations. Cash restricted is carried<br />
at cost and any accrued interest is classified under o<strong>the</strong>r assets.<br />
(j) Inven<strong>to</strong>ry<br />
• Raw materials and parts inven<strong>to</strong>ry: Raw materials and parts inven<strong>to</strong>ry are stated at <strong>the</strong> lower of costs and net<br />
realizable value. Costs comprise direct materials, direct labor and an appropriate proportion of variable and fixed<br />
overhead expenditure. Net realizable value is <strong>the</strong> estimated selling price in <strong>the</strong> ordinary course of <strong>the</strong> business less <strong>the</strong><br />
estimated costs of completion and <strong>the</strong> estimated costs necessary <strong>to</strong> make <strong>the</strong> sale.<br />
• Crude oil and refined petroleum products: Crude oil and refined petroleum products are recorded on a first-in, first-out<br />
basis and <strong>the</strong> net realizable value test for crude oil and refined petroleum products are performed separately. The cost<br />
of Midstream Refining petroleum products consist of raw material, labor, direct overheads and transportation costs.<br />
The cost of Downstream petroleum products includes <strong>the</strong> cost of <strong>the</strong> product plus related freight, wharfage and<br />
insurance.<br />
(k) Deferred financing costs<br />
Deferred financing costs represent <strong>the</strong> unamortized financing costs paid <strong>to</strong> secure borrowings. Amortization is provided on an<br />
effective yield basis over <strong>the</strong> term of <strong>the</strong> related debt and is included in expenses for <strong>the</strong> period. Unamortized deferred<br />
financing costs are offset against <strong>the</strong> respective liability accounts.<br />
(l) Plant and equipment<br />
• Refinery assets: The Company’s most significant item of plant and equipment is <strong>the</strong> oil refinery in PNG which is<br />
included within Midstream Refining assets. The pre-operating stage of <strong>the</strong> refinery ceased on January 1, 2005. Project<br />
costs, net of any recoveries, incurred during <strong>the</strong> pre-operating stage were capitalized as part of plant and equipment.<br />
Development costs and <strong>the</strong> costs of acquiring or constructing support facilities and equipment are also capitalized.<br />
Interest costs relating <strong>to</strong> <strong>the</strong> construction and pre-operating stage of <strong>the</strong> development project prior <strong>to</strong> commencement<br />
of commercial operations were capitalized as part of <strong>the</strong> cost of such plant and equipment.<br />
The refinery assets are recorded at cost less accumulated depreciation and accumulated impairment losses, if any.<br />
Refinery related assets are depreciated on straight line basis over <strong>the</strong>ir useful lives, at an average rate of 4% per<br />
annum. The refinery is built on land leased from <strong>the</strong> State. The lease expires on July 26, 2097.<br />
Repairs and maintenance costs, o<strong>the</strong>r than major turnaround costs, are expensed as incurred. Major turnaround costs<br />
will be capitalized when incurred and amortized over <strong>the</strong> estimated period of time <strong>to</strong> <strong>the</strong> next scheduled turnaround.<br />
Major turnaround work commenced at <strong>the</strong> refinery on Oc<strong>to</strong>ber 1, 2010 and was <strong>complete</strong>d on November 2, 2010 with<br />
<strong>the</strong> refinery being shut down during <strong>the</strong> turnaround period. Turnaround costs of approximately $2.5 million had been<br />
incurred during <strong>the</strong> year ended December 31, 2010, and no major turnaround costs have been incurred since.<br />
74
• O<strong>the</strong>r assets: Property, plant and equipment are recorded at amortized cost. Depreciation of assets begins when <strong>the</strong><br />
asset is in place and ready for its intended use. Assets under construction and deferred project costs are not<br />
depreciated. Depreciation of plant and equipment is calculated using <strong>the</strong> straight line method, based on <strong>the</strong> estimated<br />
service life of <strong>the</strong> asset. Maintenance and repair costs are expensed as incurred. Improvements that increase <strong>the</strong><br />
capacity or prolong <strong>the</strong> service life of an asset are capitalized.<br />
Land is not depreciated. Depreciation on o<strong>the</strong>r assets is calculated using <strong>the</strong> straight-line method <strong>to</strong> allocate <strong>the</strong>ir cost<br />
or revalued amounts, net of <strong>the</strong>ir residual values, over <strong>the</strong>ir estimated useful lives as follows:<br />
Leasehold land improvements<br />
Refinery<br />
Buildings<br />
Plant and equipment<br />
Mo<strong>to</strong>r vehicles<br />
Shorter of 100 years or lease period<br />
25 – 33 years<br />
20 – 40 years<br />
3 – 15 years<br />
4 – 5 years<br />
• Leased assets (accounting as lessee): Leases of property, plant and equipment where <strong>the</strong> Company has substantially<br />
all <strong>the</strong> risks and rewards of ownership are classified as finance leases. Finance leases are classified at <strong>the</strong> inception of<br />
<strong>the</strong> lease at <strong>the</strong> lower of <strong>the</strong> fair value of <strong>the</strong> leased property and <strong>the</strong> present value of <strong>the</strong> minimum lease payments.<br />
The corresponding rental obligations, net of finance charges, are included in o<strong>the</strong>r long term payables. Each lease<br />
payment is allocated between <strong>the</strong> liability and <strong>the</strong> finance charges so as <strong>to</strong> achieve a constant rate on <strong>the</strong> finance<br />
balance outstanding. The interest element of <strong>the</strong> finance cost is charged <strong>to</strong> <strong>the</strong> comprehensive income statement over<br />
<strong>the</strong> lease period so as <strong>to</strong> produce a constant periodic rate of interest on <strong>the</strong> remaining balance of <strong>the</strong> liability for each<br />
period. The property, plant and equipment acquired under finance leases are depreciated over <strong>the</strong> shorter of <strong>the</strong><br />
asset’s useful life and <strong>the</strong> lease term.<br />
Leases in which a significant portion of <strong>the</strong> risks and rewards of ownership are retained by <strong>the</strong> lessor are classified as<br />
operating leases. Operating lease payments are representative of <strong>the</strong> pattern of benefit derived from <strong>the</strong> leased asset<br />
and accordingly are included in expenses on a straight line basis over <strong>the</strong> period of <strong>the</strong> lease.<br />
• Leased assets (accounting as lessor): Assets are leased out under an operating lease. The asset is included in <strong>the</strong><br />
balance sheet based on <strong>the</strong> nature of <strong>the</strong> asset. Lease income is recognized over <strong>the</strong> term of <strong>the</strong> lease on a<br />
straight-line basis.<br />
• Asset retirement obligations: A liability is recognized for future legal or constructive retirement obligations associated<br />
with <strong>the</strong> Company’s property, plant and equipment. The amount recognized is <strong>the</strong> net present value of <strong>the</strong> estimated<br />
costs of future dismantlement, site res<strong>to</strong>ration and abandonment of properties based upon current regulations and<br />
economic circumstances at period end. During <strong>the</strong> quarter ended June 30, 2011, Management received <strong>the</strong> results of<br />
an independent assessment of <strong>the</strong> potential asset retirement obligations of <strong>the</strong> refinery. As a result of this assessment,<br />
Management has recognized an asset retirement obligation at December 31, 2011 of $4,562,269 (refer <strong>to</strong> note 23 for<br />
fur<strong>the</strong>r details). No asset retirement obligations had been recognized at December 31, 2010.<br />
• Environmental remediation: Remediation costs are accrued based on estimates of known environmental remediation<br />
exposure. Ongoing environmental compliance costs, including maintenance and moni<strong>to</strong>ring costs, are expensed as<br />
incurred. Provisions are determined on an assessment of current costs, current legal requirements and current<br />
technology. Changes in estimates are dealt with on a prospective basis.<br />
• Disposal of property, plant and equipment: At <strong>the</strong> time of disposal of plant and equipment, <strong>the</strong> carrying values of <strong>the</strong><br />
assets are written off along with accumulated depreciation and any resulting gain or loss is included in <strong>the</strong> income<br />
statement. Gains and losses on disposals are determined by comparing proceeds with carrying amounts.<br />
• IT Development and software: Costs incurred in development products or systems and costs incurred in acquiring<br />
software and licenses that will contribute <strong>to</strong> future period financial benefits through revenue generation and/or cost<br />
reduction are capitalized. Costs capitalized include external direct costs of materials and service, direct payroll and<br />
payroll related costs of employees’ time spent on <strong>the</strong> project. Amortization is calculated on a straight line basis over<br />
periods generally ranging from 3 <strong>to</strong> 5 years. IT development costs include only those costs directly attributable <strong>to</strong> <strong>the</strong><br />
development phase and are only recognized following completion of technical feasibility and where <strong>the</strong> Company has<br />
an intention and ability <strong>to</strong> use <strong>the</strong> asset. These amounts are capitalized as part of property, plant and equipment in <strong>the</strong><br />
Corporate segment.<br />
75
(m) Oil and gas properties<br />
The Company uses <strong>the</strong> successful-efforts method <strong>to</strong> account for its oil and gas exploration and development activities. Under<br />
this method, costs are accumulated on a field-by-field basis with certain explora<strong>to</strong>ry expenditures and explora<strong>to</strong>ry dry holes<br />
being expensed as incurred. The Company continues <strong>to</strong> carry as an asset <strong>the</strong> cost of drilling explora<strong>to</strong>ry wells if <strong>the</strong><br />
required capital expenditure is made and drilling of additional explora<strong>to</strong>ry wells is underway or firmly planned for <strong>the</strong> near<br />
future or when exploration and evaluation activities have not yet reached a stage <strong>to</strong> allow reasonable assessment regarding<br />
<strong>the</strong> existence of economic reserves. Capitalized costs for producing wells will be subject <strong>to</strong> depletion using <strong>the</strong> units of<br />
production method.<br />
Geological and geophysical costs are expensed as incurred, except when <strong>the</strong>y have been incurred <strong>to</strong> facilitate production<br />
techniques, <strong>to</strong> increase <strong>to</strong>tal recoverability and <strong>to</strong> determine <strong>the</strong> desirability of drilling additional development wells within a<br />
proved area. Geological and geophysical costs capitalized would be included as part of <strong>the</strong> cost of producing wells and be<br />
subject <strong>to</strong> depletion using <strong>the</strong> units-of-production method.<br />
(n) Impairment<br />
• Non-derivative financial assets: A financial asset not carried at fair value through profit or loss is assessed at each<br />
<strong>report</strong>ing date <strong>to</strong> determine whe<strong>the</strong>r <strong>the</strong>re is any objective evidence that it is impaired. A financial asset is considered <strong>to</strong><br />
be impaired if objective evidence indicates that one or more events have had a negative effect on <strong>the</strong> estimated future<br />
cash flows of that asset.<br />
An impairment loss in respect of a financial asset measured at amortized cost is calculated as <strong>the</strong> difference between<br />
its carrying amount, and <strong>the</strong> present value of <strong>the</strong> estimated future cash flows discounted at <strong>the</strong> original effective interest<br />
rate. An impairment loss in respect of an available-for-sale financial asset is calculated by reference <strong>to</strong> its fair value.<br />
Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets<br />
are assessed collectively in groups that share similar credit risk characteristics.<br />
All impairment losses are recognized in <strong>the</strong> consolidated income statement. An impairment loss, o<strong>the</strong>r than relating <strong>to</strong><br />
available-for-sale equity instruments, is reversed through profit and loss if <strong>the</strong> reversal can be related objectively <strong>to</strong> an<br />
event occurring after <strong>the</strong> impairment loss was recognized. The reversal of an impairment loss relating <strong>to</strong> available for<br />
sale equity instruments is through o<strong>the</strong>r comprehensive income.<br />
Trade receivables<br />
The collectability of trade receivables is assessed on an ongoing basis. Debts which are known <strong>to</strong> be uncollectible are<br />
written off by reducing <strong>the</strong> carrying amount directly. An allowance account (provision for impairment of trade<br />
receivables) is used when <strong>the</strong>re is objective evidence that <strong>the</strong> company will not be able <strong>to</strong> collect all amounts due<br />
according <strong>to</strong> <strong>the</strong> original terms of <strong>the</strong> receivables. Significant financial difficulties of <strong>the</strong> deb<strong>to</strong>r, probability that <strong>the</strong><br />
deb<strong>to</strong>r will enter bankruptcy or financial reorganization, and default or delinquency in payments are considered<br />
indica<strong>to</strong>rs that <strong>the</strong> trade receivable is impaired. The amount of <strong>the</strong> impairment allowance is <strong>the</strong> difference between <strong>the</strong><br />
asset’s carrying amount and <strong>the</strong> present value of estimated future cash flows, discounted at <strong>the</strong> original effective<br />
interest rate. Cash flows relating <strong>to</strong> short-term receivables are not discounted if <strong>the</strong> effect of discounting is immaterial.<br />
The amount of <strong>the</strong> impairment loss is recognized in <strong>the</strong> income statement. When a trade receivable for which an<br />
impairment allowance had been recognized becomes uncollectible in a subsequent period, it is written off against <strong>the</strong><br />
allowance account. Subsequent recoveries of amounts previously written off are credited against <strong>the</strong> income<br />
statement.<br />
The Company sells certain trade receivables with recourse <strong>to</strong> BNP Paribas under its working capital facility. The<br />
receivables are retained on <strong>the</strong> balance sheet as <strong>the</strong> Company retains <strong>the</strong> credit risk and control over <strong>the</strong>se receivables.<br />
• Non-financial assets: The carrying amounts of <strong>the</strong> Company’s non-financial assets, o<strong>the</strong>r than inven<strong>to</strong>ries and deferred<br />
tax assets, are reviewed at each <strong>report</strong>ing date <strong>to</strong> determine whe<strong>the</strong>r <strong>the</strong>re is any indication of impairment. If any such<br />
indication exists <strong>the</strong>n <strong>the</strong> asset’s recoverable amount is estimated. For goodwill, and intangible assets that have<br />
indefinite useful lives or that are not yet available for use, <strong>the</strong> recoverable amount is estimated each period at <strong>the</strong> same<br />
time.<br />
The recoverable amount of an asset is <strong>the</strong> greater of its value in use and its fair value less costs <strong>to</strong> sell and is<br />
determined for an individual asset, unless <strong>the</strong> asset does not generate cash inflows that are largely independent of<br />
76
those from o<strong>the</strong>r assets or groups of assets. In that situation, <strong>the</strong> assets are tested as part of a cash-generating unit<br />
(“CGU”), which is <strong>the</strong> smallest identifiable group of assets, liabilities and associated goodwill that generates cash<br />
inflows that are largely independent of <strong>the</strong> cash inflows from o<strong>the</strong>r assets or groups of assets.<br />
Fair value is <strong>the</strong> amount of <strong>the</strong> consideration that would be agreed upon in an arm’s length transaction between<br />
knowledgeable, willing parties who are under no compulsion <strong>to</strong> act. Value in use is determined as <strong>the</strong> net present value<br />
of <strong>the</strong> estimated future cash flows expected <strong>to</strong> arise from <strong>the</strong> continued use of <strong>the</strong> asset in its present form and its<br />
eventual disposal, discounted at <strong>the</strong> risk free rate of interest plus a risk premium. If an impairment loss is<br />
recognized, <strong>the</strong> adjusted carrying amount becomes <strong>the</strong> new cost basis.<br />
An impairment loss is recognized if <strong>the</strong> carrying amount of an asset or its CGU exceeds its recoverable amount.<br />
Impairment losses are recognized in respect of CGUs are allocated first <strong>to</strong> reduce <strong>the</strong> carrying amount of any goodwill<br />
allocated <strong>to</strong> <strong>the</strong> CGU and <strong>the</strong>n <strong>to</strong> reduce <strong>the</strong> carrying amounts of <strong>the</strong> o<strong>the</strong>r assets in <strong>the</strong> CGU on a pro rata basis.<br />
Impairment losses are recognized in profit or loss.<br />
Impairment losses recognized in prior periods are assessed at each <strong>report</strong>ing date for any indications that <strong>the</strong> loss<br />
has decreased or no longer exists. An impairment loss is reversed if <strong>the</strong>re has been a change in <strong>the</strong> estimates used <strong>to</strong><br />
determine <strong>the</strong> recoverable amount. An impairment loss is reversed only <strong>to</strong> <strong>the</strong> extent that <strong>the</strong> asset’s carrying amount<br />
does not exceed <strong>the</strong> carrying amount that would have been determined, net of depreciation or amortization, if no<br />
impairment loss had been recognized.<br />
There has been no impairment of assets or goodwill based on <strong>the</strong> assessments performed during <strong>the</strong> period.<br />
(o) Revenue recognition<br />
Revenue is measured at <strong>the</strong> fair value of <strong>the</strong> consideration received or receivable. Amounts disclosed as revenue are net of<br />
returns, trade allowances and duties and taxes paid. The following particular accounting policies, which significantly affect <strong>the</strong><br />
measurement of results, have been applied.<br />
• Revenue from Midstream Refining operations: Revenue from sales of products is recognized when products are<br />
shipped and <strong>the</strong> cus<strong>to</strong>mer takes ownership and assumes risk of loss, collection of <strong>the</strong> relevant receivable is probable<br />
and when <strong>the</strong> amount of revenue can be reliably measured. Sales between <strong>the</strong> operating segments of <strong>the</strong> Company<br />
have been eliminated from sales and operating revenues and cost of sales.<br />
• Revenue from Downstream operations: Sales of goods are recognized when <strong>the</strong> Company has delivered products <strong>to</strong><br />
<strong>the</strong> cus<strong>to</strong>mer, <strong>the</strong> cus<strong>to</strong>mer takes ownership and assumes risk of loss, collection of <strong>the</strong> receivable is probable, and<br />
when <strong>the</strong> amount of revenue can be reliably measured. It is not <strong>the</strong> Company’s policy <strong>to</strong> sell products with a right of<br />
return.<br />
• Revenue from Upstream operations: Revenue from rig and constructions services are recognized in <strong>the</strong> accounting<br />
period in with <strong>the</strong> services are rendered.<br />
• Interest revenue: Interest revenue is recognized as <strong>the</strong> interest accrues using <strong>the</strong> effective interest rate.<br />
(p) Income tax<br />
Income tax comprises current and deferred tax. Income tax is recognized in <strong>the</strong> income statement except <strong>to</strong> <strong>the</strong> extent that<br />
it relates <strong>to</strong> items recognized directly in o<strong>the</strong>r comprehensive income or directly in equity, in which case <strong>the</strong> income tax is also<br />
recognized directly in o<strong>the</strong>r comprehensive income or equity respectively.<br />
The income tax expense or benefit for <strong>the</strong> period is <strong>the</strong> tax payable on <strong>the</strong> current period’s taxable income based on <strong>the</strong><br />
national income tax rate for each jurisdiction; adjusted by changes in deferred tax assets and liabilities attributable <strong>to</strong><br />
temporary differences between <strong>the</strong> tax bases of assets and liabilities and <strong>the</strong>ir carrying amounts in <strong>the</strong> financial statements<br />
and <strong>to</strong> unused tax losses.<br />
Management periodically evaluates positions taken in tax returns with respect <strong>to</strong> situations in which applicable tax regulation<br />
is subject <strong>to</strong> interpretation.<br />
Deferred tax assets and liabilities are recognized for temporary differences at <strong>the</strong> tax rates expected <strong>to</strong> apply when <strong>the</strong> assets<br />
are recovered or liabilities are settled, based on those tax rates which are enacted or substantively enacted for each<br />
77
jurisdiction. The relevant tax rates are applied <strong>to</strong> <strong>the</strong> cumulative amounts of deductible and taxable temporary differences <strong>to</strong><br />
measure <strong>the</strong> deferred tax asset or liability. Deferred income tax assets and liabilities are presented as non-current.<br />
Deferred tax assets and liabilities are offset when <strong>the</strong>re is a legally enforceable right <strong>to</strong> offset current tax assets and liabilities<br />
and when <strong>the</strong> deferred tax balances relate <strong>to</strong> <strong>the</strong> same taxation authority. Current tax assets and tax liabilities are offset where<br />
<strong>the</strong> entity has a legally enforceable right <strong>to</strong> offset and intends ei<strong>the</strong>r <strong>to</strong> settle on a net basis, or <strong>to</strong> realize <strong>the</strong> asset and settle<br />
<strong>the</strong> liability simultaneously.<br />
Deferred tax assets are recognized for deductible temporary differences and unused tax losses only if it is probable that future<br />
taxable amounts will be available <strong>to</strong> utilize those temporary differences and losses. Deferred tax assets are reviewed at each<br />
<strong>report</strong>ing date and are reduced <strong>to</strong> <strong>the</strong> extent that it is no longer probable that <strong>the</strong> related tax benefit will be realized.<br />
The Refinery Project Agreement gave “pioneer” status <strong>to</strong> <strong>InterOil</strong> Limited (”IOL”). This status gave IOL a tax holiday beginning<br />
upon <strong>the</strong> date of <strong>the</strong> commencement of commercial production, January 1, 2005 and ended December 31, 2010.<br />
In addition <strong>to</strong> income taxes, <strong>InterOil</strong> is subject <strong>to</strong> Goods and Services Tax, Excise Duty and o<strong>the</strong>r taxes in PNG, Australia,<br />
Singapore and Canada. The consolidated financial statements are prepared on a net of Goods and Services Tax basis.<br />
(q) Employee entitlements<br />
• Wages and salaries, and annual leave: Liabilities for wages and salaries, including annual leave expected <strong>to</strong> be settled<br />
within 12 months of <strong>the</strong> <strong>report</strong>ing date are recognized in accounts payable and accrued liabilities in respect of<br />
employees’ services up <strong>to</strong> <strong>the</strong> <strong>report</strong>ing date and are measured at <strong>the</strong> amounts expected <strong>to</strong> be paid when liabilities are<br />
settled.<br />
• Long service leave: The liability for long service leave is recognized in <strong>the</strong> provision for employee benefits and<br />
measured as <strong>the</strong> present value of expected future payments <strong>to</strong> be made in respect of services provided by employees<br />
up <strong>to</strong> <strong>the</strong> <strong>report</strong>ing date. Consideration is given <strong>to</strong> expected future wage and salary levels, experience of employee<br />
departures, periods of service and statu<strong>to</strong>ry obligations.<br />
• Post-employment obligations: The Company contributed <strong>to</strong> a defined contribution plan and <strong>the</strong> Company’s legal or<br />
constructive obligation is limited <strong>to</strong> <strong>the</strong>se contributions. Contributions <strong>to</strong> <strong>the</strong> defined contribution fund are recognized<br />
as an expense as <strong>the</strong>y become payable.<br />
• Share-based payments: S<strong>to</strong>ck-based compensation benefits are provided <strong>to</strong> employees and direc<strong>to</strong>rs pursuant <strong>to</strong> <strong>the</strong><br />
2009 S<strong>to</strong>ck Incentive Plan (with options still in existence having been granted under <strong>the</strong> now superseded 2006 S<strong>to</strong>ck<br />
Incentive Plan). The Company currently issues s<strong>to</strong>ck options and restricted s<strong>to</strong>ck units as part of its s<strong>to</strong>ck-based<br />
compensation plan. The fair value of s<strong>to</strong>ck options at grant date is determined using a Black-Scholes option pricing<br />
model that takes in<strong>to</strong> account <strong>the</strong> exercise price, <strong>the</strong> terms of <strong>the</strong> option, <strong>the</strong> vesting criteria, <strong>the</strong> share price at grant<br />
date and expected price volatility of <strong>the</strong> underlying share, <strong>the</strong> expected yield and risk-free interest rate for <strong>the</strong> term of<br />
<strong>the</strong> option. Upon exercise of options, <strong>the</strong> balance of <strong>the</strong> contributed surplus relating <strong>to</strong> those options is transferred <strong>to</strong><br />
share capital. The fair value of restricted s<strong>to</strong>ck units on grant date is <strong>the</strong> market value of <strong>the</strong> s<strong>to</strong>ck.<br />
The Company uses <strong>the</strong> fair value based method <strong>to</strong> account for employee s<strong>to</strong>ck based compensation benefits. Under<br />
<strong>the</strong> fair value based method, compensation expense is measured at fair value at <strong>the</strong> date of grant and is expensed over<br />
<strong>the</strong> award’s vesting period.<br />
• Profit-sharing and bonus plans: The Company recognizes a provision where contractually obliged or where <strong>the</strong>re is a<br />
past practice that has created a constructive obligation.<br />
(r) Earnings per share<br />
• Basic earnings per share: Basic common shares outstanding are <strong>the</strong> weighted average number of common shares<br />
outstanding for each period. Basic earnings per share is calculated by dividing <strong>the</strong> profit or loss attributable <strong>to</strong><br />
shareholders of <strong>the</strong> Company by <strong>the</strong> weighted average number of common shares outstanding during <strong>the</strong> period.<br />
• Diluted earnings per share: Diluted earnings per share is determined by adjusting <strong>the</strong> profit or loss attributable <strong>to</strong><br />
shareholders and <strong>the</strong> weighted average number of common shares outstanding, for <strong>the</strong> effects of all dilutive potential<br />
ordinary shares, which comprise convertible notes and share options granted <strong>to</strong> employees.<br />
78
3. Transition <strong>to</strong> International Financial Reporting Standards (“IFRS”)<br />
(a) Basis of transition <strong>to</strong> IFRS<br />
(i) Application of IFRS 1<br />
The Company’s financial statements for <strong>the</strong> year ending December 31, 2011, are <strong>the</strong> first annual financial statements that<br />
comply with IFRS as disclosed in Note 2(a). The Company has applied IFRS 1 in preparing <strong>the</strong>se consolidated financial<br />
statements.<br />
The Company’s transition date is January 1, 2010. The Company prepared its opening IFRS balance sheet at that date. The<br />
<strong>report</strong>ing date of <strong>the</strong>se consolidated financial statements is December 31, 2011. In preparing <strong>the</strong>se consolidated financial<br />
statements in accordance with IFRS 1, <strong>the</strong> Company has applied <strong>the</strong> relevant manda<strong>to</strong>ry exceptions and certain optional<br />
exemptions from full retrospective application of IFRS.<br />
(ii) Exemptions from full retrospective application – elected by <strong>the</strong> Company<br />
The Company has elected <strong>to</strong> apply <strong>the</strong> following optional exemptions from full retrospective application.<br />
• Business combinations exemption: A first-time adopter may elect not <strong>to</strong> apply IFRS 3 - ‘Business Combinations’ (as<br />
revised in 2008) retrospectively <strong>to</strong> past business combinations (business combinations that occurred before <strong>the</strong> date<br />
of transition <strong>to</strong> IFRSs). However, if a first-time adopter restates any business combination <strong>to</strong> comply with IFRS 3 (as<br />
revised in 2008), it shall restate all later business combinations and shall also apply IAS 27 (as amended in 2008) from<br />
that same date. <strong>InterOil</strong> has made <strong>the</strong> election not <strong>to</strong> apply IFRS 3 retrospectively <strong>to</strong> past business combinations.<br />
• Fair value as deemed cost exemption: An entity may elect <strong>to</strong> measure an item of property, plant and equipment at <strong>the</strong><br />
date of transition <strong>to</strong> IFRSs at its fair value and use that fair value as its deemed cost at that date. <strong>InterOil</strong> has made <strong>the</strong><br />
election not <strong>to</strong> use deemed cost. His<strong>to</strong>rical cost will be maintained as plant and equipment cost base on transition.<br />
• Cumulative translation differences exemption: Consistent with <strong>the</strong> Company’s Canadian GAAP treatment in prior<br />
periods, IAS 21 requires an entity: (a) <strong>to</strong> recognize some translation differences in o<strong>the</strong>r comprehensive income and<br />
accumulate <strong>the</strong>se in a separate component of equity; and (b) on disposal of a foreign operation, <strong>to</strong> reclassify <strong>the</strong><br />
cumulative translation difference for that foreign operation (including, if applicable, gains and losses on related hedges)<br />
from equity <strong>to</strong> profit or loss as part of <strong>the</strong> gain or loss on disposal. An election can be made <strong>to</strong> be exempted from this<br />
requirement on transition and start with ‘zero’ translation differences. <strong>InterOil</strong> has not made <strong>the</strong> election <strong>to</strong> restate its<br />
cumulative translation differences balance <strong>to</strong> zero, and has elected <strong>to</strong> continue with <strong>the</strong> current translation differences<br />
in comprehensive income as <strong>the</strong>se are already in compliance with IAS 21.<br />
• Oil and Gas assets exemption: Oil and Gas industry specific accounting under IFRS or Canadian GAAP is currently not<br />
as comprehensive as <strong>the</strong> guidance provided under U.S. GAAP accounting for industry specific oil and gas transactions.<br />
Para D8A of IFRS 1 provides an exemption in relation <strong>to</strong> Oil and Gas assets by allowing Companies <strong>to</strong> continue<br />
using <strong>the</strong> same policies as used under <strong>the</strong> previous GAAP and carrying forward <strong>the</strong> carrying amounts of <strong>the</strong> Oil and<br />
Gas assets under Canadian GAAP in<strong>to</strong> IFRS. <strong>InterOil</strong> has availed this exemption and elected <strong>to</strong> maintain <strong>the</strong><br />
Company’s Oil and Gas assets at carrying amount under Canadian GAAP treatment in prior periods, which will be <strong>the</strong><br />
deemed cost under IFRS.<br />
• Interests in Joint Ventures entities exemption: Superseded CICA Section 3055 differs from IAS 31 as IAS 31 permits<br />
<strong>the</strong> use of ei<strong>the</strong>r <strong>the</strong> proportionate consolidation method or <strong>the</strong> equity method <strong>to</strong> account for joint venture entities. IAS<br />
31 recommends <strong>the</strong> use of proportionate consolidation as it better reflects <strong>the</strong> substance and economic reality,<br />
however, it does permit <strong>the</strong> use of equity method. Superseded CICA Section 3055 only allows <strong>the</strong> use of proportionate<br />
consolidation method <strong>to</strong> account for joint venture entities. <strong>InterOil</strong> has elected <strong>to</strong> maintain its joint venture accounting<br />
under <strong>the</strong> proportionate consolidation model for both its incorporated and unincorporated joint venture interests.<br />
The remaining optional exemptions are not applicable <strong>to</strong> <strong>the</strong> Company.<br />
(iii) Exceptions from full retrospective application followed by <strong>the</strong> Company<br />
All manda<strong>to</strong>ry exceptions in IFRS 1 were not applicable because <strong>the</strong>re were no significant differences in management’s<br />
application of Canadian GAAP in <strong>the</strong>se areas.<br />
79
(b) Reconciliations between IFRS and Canadian GAAP<br />
The following reconciliations provide a quantification of <strong>the</strong> effect of <strong>the</strong> transition <strong>to</strong> IFRS. The first reconciliation provides an<br />
overview of <strong>the</strong> impact on equity of <strong>the</strong> transition at January 1, 2010 and December 31, 2010. The second reconciliation<br />
provides an overview of <strong>the</strong> impact of <strong>the</strong> transition on comprehensive income for <strong>the</strong> year ended December 31, 2010. There<br />
are no material differences between <strong>the</strong> statement of cash flows presented in accordance with IFRSs and <strong>the</strong> statement of<br />
cash flows presented in accordance with Canadian GAAP.<br />
(i) Reconciliation of equity<br />
Assets<br />
Current assets:<br />
Candian GAAP<br />
January 2, 2010<br />
$<br />
Effect of transition<br />
<strong>to</strong> IFRSs<br />
$<br />
IFRS<br />
January 1, 2010<br />
Candian GAAP<br />
December 31,<br />
2010<br />
$<br />
Effect of transition<br />
<strong>to</strong> IFRSs<br />
$<br />
IFRS<br />
December 31, 2010<br />
Cash and cash equivalents 46,449,819 - 46,449,819 233,576,821 - 233,576,821<br />
Cash restricted 22,698,829 - 22,698,829 40,664,995 - 40,664,995<br />
Trade receivables 61,194,136 - 61,194,136 48,047,496 - 48,047,496<br />
O<strong>the</strong>r assets 639,646 - 639,646 505,059 - 505,059<br />
Inven<strong>to</strong>ries 70,127,049 - 70,127,049 127,137,360 - 127,137,360<br />
Prepaid expenses 6,964,950 - 6,964,950 3,593,574 - 3,593,574<br />
Total current assets 208,074,429 - 208,074,429 453,525,305 - 453,525,305<br />
Non-current assets:<br />
Cash restricted 6,609,746 - 6,609,746 6,613,074 - 6,613,074<br />
Goodwill 6,626,317 - 6,626,317 6,626,317 - 6,626,317<br />
Plant and equipment (1) 221,046,709 (2,252,060) 218,794,649 229,331,842 (4,126,415) 225,205,427<br />
Oil and gas properties 172,483,562 - 172,483,562 255,294,738 - 255,294,738<br />
Deferred tax assets (2) 16,912,969 13,406,194 30,319,163 14,098,128 14,379,562 28,477,690<br />
Total non-current assets 423,679,303 11,154,134 434,833,437 511,964,099 10,253,147 522,217,246<br />
Total assets 631,753,732 11,154,134 642,907,866 965,489,404 10,253,147 975,742,551<br />
Liabilities and shareholders' equity<br />
Current liabilities:<br />
Accounts payable and accrued<br />
liabilities<br />
59,372,354 - 59,372,354 76,087,954 - 76,087,954<br />
Derivative contracts - - - 178,578 - 178,578<br />
Working capital facilities 24,626,419 - 24,626,419 51,254,326 - 51,254,326<br />
Current portion of secured and<br />
unsecured loans<br />
Current portion of Indirect<br />
participation interest<br />
9,000,000 - 9,000,000 14,456,757 - 14,456,757<br />
540,002 - 540,002 540,002 - 540,002<br />
Total current liabilities 93,538,775 - 93,538,775 142,517,617 - 142,517,617<br />
Non-current liabilities:<br />
Secured loan 43,589,278 - 43,589,278 34,813,222 - 34,813,222<br />
2.75% convertible notes liability - - - 52,425,489 - 52,425,489<br />
Deferred gain on contributions <strong>to</strong><br />
LNG project (1)<br />
13,076,272 (2,252,060) 10,824,212 13,076,272 (4,126,415) 8,949,857<br />
Indirect participation interest 39,559,718 - 39,559,718 34,134,387 - 34,134,387<br />
Total non-current liabilities 96,225,268 (2,252,060) 93,973,208 134,449,370 (4,126,415) 130,322,955<br />
Total liabilities 189,764,043 (2,252,060) 187,511,983 276,966,987 (4,126,415) 272,840,572<br />
Non-controlling interest 13,596 - 13,596 20,099 - 20,099<br />
Shareholders' equity:<br />
Share capital 613,361,363 - 613,361,363 895,651,052 - 895,651,052<br />
2.75% convertible notes - - - 14,298,036 - 14,298,036<br />
Contributed surplus 21,297,177 - 21,297,177 16,738,417 - 16,738,417<br />
Accumulated O<strong>the</strong>r Comprehensive<br />
Income<br />
8,150,976 - 8,150,976 9,261,177 - 9,261,177<br />
Conversion options 13,270,880 - 13,270,880 12,150,880 - 12,150,880<br />
Accumulated deficit (2) (214,104,303) 13,406,194 (200,698,109) (259,597,244) 14,379,562 (245,217,682)<br />
Total shareholders' equity 441,976,093 13,406,194 455,382,287 688,502,318 14,379,562 702,881,880<br />
Total liabilities and shareholders'<br />
equity<br />
631,753,732 11,154,134 642,907,866 965,489,404 10,253,147 975,742,551<br />
80
(ii) Reconciliation of <strong>to</strong>tal comprehensive income<br />
Canadian<br />
GAAP<br />
December 31,<br />
2010<br />
$<br />
Year ended<br />
Effect of transition<br />
<strong>to</strong> IFRSs<br />
$<br />
IFRS<br />
December 31,<br />
2010<br />
$<br />
Loss for <strong>the</strong> period (2) (45,486,439) 973,368 (44,513,071)<br />
O<strong>the</strong>r comprehensive income/(loss):<br />
Exchange difference on translation of foreign operations, net of tax 1,110,201 - 1,110,201<br />
O<strong>the</strong>r comprehensive income/(loss) for <strong>the</strong> period, net of tax 1,110,201 - 1,110,201<br />
Total comprehensive income/(loss) for <strong>the</strong> period (44,376,238) 973,368 (43,402,870)<br />
(iii) Notes <strong>to</strong> <strong>the</strong> reconciliations<br />
• In September 2009, as part of acquisition by Pacific LNG of a 2.5% direct working interest in <strong>the</strong> Elk and Antelope<br />
fields, Pacific LNG transferred <strong>to</strong> <strong>InterOil</strong> 2.5% of Pacific LNG’s unexercised economic interest in <strong>the</strong> joint venture<br />
LNG Project. Based on this transaction, as at December 31, 2011, <strong>InterOil</strong> and Pacific LNG hold 52.5% and 47.5%<br />
economic interest respectively in <strong>the</strong> LNG project, subject <strong>to</strong> <strong>the</strong> exercise of all <strong>the</strong>ir rights <strong>to</strong> <strong>the</strong> ‘B’ Class shares on<br />
payment of cash calls.<br />
To date <strong>InterOil</strong> has a recognized deferred gain on its contributions <strong>to</strong> <strong>the</strong> Joint Venture based on <strong>the</strong> share of o<strong>the</strong>r<br />
joint venture partners in <strong>the</strong> project. As <strong>InterOil</strong>’s shareholding within <strong>the</strong> Joint Venture Company as at December 31,<br />
2011 is 84.582% (Dec 2010 – 86.66%), <strong>the</strong> gain on contribution of non cash assets <strong>to</strong> <strong>the</strong> project by <strong>InterOil</strong> relating<br />
<strong>to</strong> o<strong>the</strong>r joint venture partners’ shareholding (15.418% - amounting <strong>to</strong> $15,113,190) has been recognized by <strong>InterOil</strong><br />
in its balance sheet as a deferred gain. This deferred gain will increase/decrease as <strong>the</strong> o<strong>the</strong>r Joint Venture partners<br />
decrease/increase <strong>the</strong>ir shareholding in <strong>the</strong> project. Previously under Canadian GAAP, <strong>the</strong> amount was recognized as<br />
a deferred gain in full. However, under IFRS, unrealized gains or losses on non-monetary assets contributed <strong>to</strong> joint<br />
ventures shall be eliminated against <strong>the</strong> underlying assets under <strong>the</strong> proportionate consolidation method. Such<br />
unrealized gains or losses shall not be presented as deferred gains or losses in <strong>the</strong> venturer’s consolidated balance<br />
sheet.<br />
As such, <strong>the</strong> deferred gain has been recorded as a reduction of deferred LNG project costs of $9,302,415 at<br />
December 31, 2011 (Dec 31, 2010 - $4,126,415, Jan 1, 2010 - $2,252,060), which has reduced <strong>the</strong> LNG project<br />
costs <strong>to</strong> nil at December 31, 2011, with <strong>the</strong> remaining balance of $5,810,775 (Dec 31, 2010 - $8,949,857, Jan 1, 2010<br />
- $10,824,212) being recorded as a deferred gain. The deferred gain will be recognized in <strong>the</strong> consolidated income<br />
statement when <strong>the</strong> risks and rewards have considered <strong>to</strong> be passed. The intangible assets of <strong>the</strong> Joint Venture<br />
Company, contributed by <strong>InterOil</strong>, have been eliminated on proportionate consolidation of <strong>the</strong> joint venture balances.<br />
• In accordance with guidance under IFRS, deferred tax assets have been recognized for temporary differences that<br />
arise on translation of <strong>the</strong> nonmonetary assets held by Midstream refining operations that are translated from <strong>the</strong><br />
functional currency of <strong>the</strong> tax return (PGK) <strong>to</strong> <strong>the</strong> <strong>report</strong>ing currency (USD) using period end rates. Previously under<br />
Canadian GAAP, <strong>the</strong>se temporary differences in relation <strong>to</strong> functional currency translation of nonmonetary assets were<br />
specifically disallowed from recognition.<br />
4. Financial Risk Management<br />
The Company’s activities expose it <strong>to</strong> a variety of financial risks; market risk, credit risk, liquidity risk and geographic risk. The<br />
Company’s overall risk management program focuses on <strong>the</strong> unpredictability of markets and seeks <strong>to</strong> minimize potential<br />
adverse effects on <strong>the</strong> financial performance of <strong>the</strong> Company. The Company uses derivative financial instruments <strong>to</strong> hedge<br />
certain price risk exposures.<br />
Risk Management is carried out under policies approved by <strong>the</strong> Board of Direc<strong>to</strong>rs. The Finance Department identifies,<br />
evaluates and hedges financial risks in close cooperation with <strong>the</strong> Company’s operating units. The product pricing risks are<br />
managed by <strong>the</strong> Supply and Trading Department under <strong>the</strong> guidance of <strong>the</strong> Risk Management Committee. The Board<br />
provides written principles for overall risk management, as well as written policies covering specific areas, such as use of<br />
derivative financial instruments. The Company’s overall risk management program seeks <strong>to</strong> minimize potential adverse effects<br />
on <strong>the</strong> Company’s financial performance.<br />
81
(a) Market risk<br />
(i) Foreign exchange risk<br />
Foreign exchange risk arises when future commercial transactions and recognized assets and liabilities are denominated in a<br />
currency that is not <strong>the</strong> Company’s functional currency. The Company operates internationally and is exposed <strong>to</strong> foreign<br />
exchange risk arising from currency exposures <strong>to</strong> <strong>the</strong> USD. The consolidated financial statements are presented in USD which<br />
is <strong>the</strong> Company’s functional and <strong>report</strong>ing currency. Most of <strong>the</strong> Company’s transactions are undertaken in USD, PGK,<br />
Australian Dollars (“AUD”) and Singapore Dollars (“SGD”).<br />
The PGK exposures mainly relate <strong>to</strong> <strong>the</strong> exchange rates achieved from <strong>the</strong> banks on transfer of PGK sale proceeds <strong>to</strong> USD <strong>to</strong><br />
repay <strong>the</strong> Company’s crude cargo borrowings. The rates achieved fluctuate significantly based on o<strong>the</strong>r exporters /<br />
importers looking <strong>to</strong> convert <strong>the</strong>ir USD in<strong>to</strong> PGK, and is also impacted by seasonality based farm produce exports from PNG.<br />
The Company is unable <strong>to</strong> do any hedging due <strong>to</strong> PGK illiquidity and small size of <strong>the</strong> market. The translation of PGK<br />
denominated balances in <strong>the</strong> Company’s operating entities in<strong>to</strong> USD at period ends can also result in material impact on <strong>the</strong><br />
foreign exchange gains/losses on consolidation.<br />
Changes in <strong>the</strong> PGK <strong>to</strong> USD exchange rate can affect <strong>the</strong> Company’s Midstream Refining results as <strong>the</strong>re is a timing<br />
difference between <strong>the</strong> foreign exchange rates utilized when setting <strong>the</strong> monthly PGK IPP price and <strong>the</strong> foreign exchange<br />
rate used <strong>to</strong> convert <strong>the</strong> subsequent receipt of PGK proceeds <strong>to</strong> USD <strong>to</strong> repay <strong>the</strong> Company’s crude cargo borrowings. The<br />
foreign exchange movement also impacts equity as translation gains/losses of <strong>the</strong> Company’s Downstream operations from<br />
PGK <strong>to</strong> USD is included in o<strong>the</strong>r comprehensive income. The PGK streng<strong>the</strong>ned against <strong>the</strong> USD during <strong>the</strong> year ended<br />
December 31, 2011 (from 0.3785 <strong>to</strong> 0.4665).<br />
The financial instruments denominated in PGK and translated <strong>to</strong> USD as at December 31, 2011 are as follows:<br />
Financial assets<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Cash and cash equivalents 42,669,762 11,789,931<br />
Cash restricted 161,801 130,486<br />
Short term treasury bills 11,832,110 -<br />
Receivables 96,322,533 42,006,504<br />
O<strong>the</strong>r financial assets 3,289,791 1,771,866<br />
Financial liabilities<br />
Payables 30,866,291 16,980,909<br />
Working capital facility 6,450,372 1,230,767<br />
The following table summarizes <strong>the</strong> sensitivity of financial instruments held at balance sheet date <strong>to</strong> movement in <strong>the</strong><br />
exchange rate of <strong>the</strong> USD <strong>to</strong> <strong>the</strong> PGK, with all o<strong>the</strong>r variables held constant. Certain USD debt and o<strong>the</strong>r financial assets and<br />
liabilities are not held in <strong>the</strong> functional currency of <strong>the</strong> relevant subsidiary. This results in an accounting exposure <strong>to</strong> exchange<br />
gains and losses as <strong>the</strong> financial assets and liabilities are translated in<strong>to</strong> <strong>the</strong> functional currency of <strong>the</strong> subsidiary that accounts<br />
for those assets and liabilities. These exchange gains and losses are recorded in <strong>the</strong> consolidated income statement except<br />
<strong>to</strong> <strong>the</strong> extent that <strong>the</strong>y can be taken <strong>to</strong> equity under <strong>the</strong> Company’s accounting policy. If PGK appreciates/(depreciates) by 5%<br />
against <strong>the</strong> USD, it will result in a gain/(loss) as per <strong>the</strong> table below.<br />
Post-tax gain/(loss)<br />
Impact on profit<br />
$<br />
December 31, 2011<br />
$<br />
Impact on equity<br />
- excluding profit<br />
impact<br />
$<br />
Year ended<br />
Impact on profit<br />
$<br />
December 31, 2010<br />
$<br />
Impact on equity<br />
- excluding profit<br />
impact<br />
$<br />
Effect of 5% appreciation of PGK 2,386,925 3,474,679 212,281 1,662,074<br />
82
The changes in AUD and SGD <strong>to</strong> USD exchange rate can affect <strong>the</strong> Company’s Corporate results as <strong>the</strong> expenses of <strong>the</strong><br />
Corporate offices in Australia and Singapore are incurred in <strong>the</strong> respective local currencies. The AUD and SGD exposures<br />
are minimal currently as funds are transferred <strong>to</strong> AUD and SGD from USD as required. No material balances are held in AUD<br />
or SGD. However, <strong>the</strong> Company is exposed <strong>to</strong> translation risks resulting from AUD and SGD fluctuations as in country costs<br />
are being incurred in AUD and SGD and <strong>report</strong>ing for those costs being in USD. The Company has entered in<strong>to</strong> AUD <strong>to</strong> USD<br />
foreign currency forward contracts <strong>to</strong> manage <strong>the</strong> foreign exchange risk in relation <strong>to</strong> <strong>the</strong> expenses <strong>to</strong> be incurred in AUD.<br />
(ii) Price risk<br />
Product Price Risk<br />
The Midstream Refining operations of <strong>the</strong> Company are largely exposed <strong>to</strong> price fluctuations during <strong>the</strong> period between <strong>the</strong><br />
crude purchases and <strong>the</strong> refined products leaving <strong>the</strong> refinery when sold <strong>to</strong> Downstream operations and o<strong>the</strong>r distribu<strong>to</strong>rs.<br />
The Company actively tries <strong>to</strong> manage <strong>the</strong> price risk by entering in<strong>to</strong> derivative contracts <strong>to</strong> buy and sell crude and finished<br />
products.<br />
The derivative contracts are entered in<strong>to</strong> by Management based on documented risk management strategies which have<br />
been approved by <strong>the</strong> Risk Management Committee. All derivative contracts entered in<strong>to</strong> are reviewed by <strong>the</strong> Risk<br />
Management Committee as part of <strong>the</strong> meetings of <strong>the</strong> Committee.<br />
The following table summarizes <strong>the</strong> sensitivity of derivative financial instruments held at balance sheet date <strong>to</strong> $10.0<br />
movement in benchmark pricing, with all o<strong>the</strong>r variables held constant. If <strong>the</strong> pricing increases/(declines) by $10.0, it will result<br />
in a (loss)/gain as per <strong>the</strong> table below.<br />
Post-tax gain/(loss)<br />
$10 increase in benchmark pricing of derivative<br />
contracts<br />
Impact on profit<br />
$<br />
December 31, 2011<br />
$<br />
Impact on equity<br />
- excluding profit<br />
impact<br />
$<br />
Year ended<br />
Impact on profit<br />
$<br />
December 31, 2010<br />
$<br />
Impact on equity<br />
- excluding profit<br />
impact<br />
$<br />
(6,550,000) - (540,000) -<br />
Securities Price Risk<br />
The Company is also exposed <strong>to</strong> equity securities price risk. This arises from investments held by <strong>the</strong> Company and<br />
classified in <strong>the</strong> balance sheet as available-for-sale. The Company’s equity investments are publicly traded and are quoted on<br />
<strong>the</strong> Oslo s<strong>to</strong>ck exchange Axess. Refer <strong>to</strong> note 14 for fur<strong>the</strong>r details of this investment.<br />
The following table summarizes <strong>the</strong> sensitivity of <strong>the</strong>se investments held at balance sheet date <strong>to</strong> 10% movement in<br />
benchmark pricing, with all o<strong>the</strong>r variables held constant. If <strong>the</strong> pricing increases/(declines) by 10%, it will result in a (loss)/gain<br />
as per <strong>the</strong> table below.<br />
Post-tax gain/(loss)<br />
10% increase in benchmark pricing of equity investments<br />
10% decrease in benchmark pricing of equity<br />
investments<br />
Impact on profit<br />
$<br />
(365,079)<br />
December 31, 2011<br />
$<br />
Impact on equity<br />
- excluding profit<br />
impact<br />
$<br />
Year ended<br />
Impact on profit<br />
$<br />
December 31, 2010<br />
$<br />
Impact on equity<br />
- excluding profit<br />
impact<br />
$<br />
365,079 - -<br />
(iii) Interest rate risk<br />
Interest rate risk is <strong>the</strong> risk that <strong>the</strong> Company’s financial position will be adversely affected by movements in interest rates that<br />
will increase <strong>the</strong> cost of floating rate debt or opportunity losses that may arise on fixed rate borrowings in a falling interest rate<br />
environment. As <strong>the</strong> Company has no significant interest-bearing assets o<strong>the</strong>r than cash and cash equivalents, <strong>the</strong><br />
Company’s income and operating cash flows are substantially independent of changes in market interest rates.<br />
83
The Company’s interest-rate risk arises from cash and cash equivalent balances, borrowings and working capital financing<br />
facilities. Deposits/borrowings at variable rates expose <strong>the</strong> Company <strong>to</strong> cash flow interest-rate risk. Deposits/borrowings<br />
at fixed rates expose <strong>the</strong> Company <strong>to</strong> fair value interest-rate risk. The Company is actively seeking <strong>to</strong> manage its cash flow<br />
interest-rate risks by holding some cash, cash equivalents and borrowings in fixed rate instruments and o<strong>the</strong>rs in variable rate<br />
instruments.<br />
The financial instruments exposed <strong>to</strong> cash flow and fair value interest rate risk are as follows:<br />
Financial assets<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
“Cash flow/fair value<br />
interest rate risk”<br />
Cash and cash equivalents 37,891,187 1,205,304 fair value interest rate risk<br />
Cash and cash equivalents 30,955,254 232,371,517 cash flow interest rate risk<br />
Cash restricted 365,281 309,926 fair value interest rate risk<br />
Cash restricted 38,885,482 46,968,143 cash flow interest rate risk<br />
Short term treasury bills 11,832,110 - fair value interest rate risk<br />
Financial liabilities<br />
OPIC secured loan 35,500,000 44,500,000 fair value interest rate risk<br />
Mitsui unsecured loan 10,393,023 5,456,757 cash flow interest rate risk<br />
BNP working capital facility 10,030,131 50,023,559 cash flow interest rate risk<br />
Westpac working capital facility 6,450,372 1,230,767 cash flow interest rate risk<br />
2.75% convertible notes 70,000,000 70,000,000 fair value interest rate risk<br />
The following table summarizes <strong>the</strong> sensitivity of <strong>the</strong> cash flow interest-rate risk of financial instruments held at balance date,<br />
following a movement <strong>to</strong> LIBOR, with all o<strong>the</strong>r variables held constant. Increase in LIBOR rates will result in a higher expense<br />
for <strong>the</strong> Company.<br />
Post-tax loss/(gain)<br />
Impact on profit<br />
$<br />
December 31, 2011<br />
$<br />
Impact on equity<br />
- excluding profit<br />
impact<br />
$<br />
Year ended<br />
Impact on profit<br />
$<br />
December 31, 2010<br />
$<br />
Impact on equity<br />
- excluding profit<br />
impact<br />
$<br />
LIBOR Increase by 1% 507,666 - 338,291 -<br />
(iv) Product risk<br />
The composition of <strong>the</strong> crude feeds<strong>to</strong>ck will vary <strong>the</strong> refinery output of products. The 2011 year <strong>to</strong> date output achieved<br />
includes gasoline and distillates fuels (which includes diesel and jet fuels) 58% (Dec 2010 – 53%), and naphtha and low<br />
sulphur waxy residue 37% (Dec 2010 – 42%). The product yields obtained will vary based on <strong>the</strong> type of crude feeds<strong>to</strong>ck<br />
used.<br />
Management endeavors <strong>to</strong> manage <strong>the</strong> product risk by actively reviewing <strong>the</strong> market for demand and supply, trying <strong>to</strong><br />
maximize <strong>the</strong> production of <strong>the</strong> higher margin products and also renegotiating <strong>the</strong> selling prices for <strong>the</strong> lower margin products.<br />
(b) Liquidity risk<br />
Liquidity risk is <strong>the</strong> risk that <strong>InterOil</strong> will not meet its financial obligations as <strong>the</strong>y fall due. Prudent liquidity risk management<br />
<strong>the</strong>refore implies that, under both normal and stressed conditions, <strong>the</strong> Company maintains:<br />
•<br />
•<br />
•<br />
sufficient cash and marketable securities;<br />
access <strong>to</strong>, or availability of, funding through an adequate amount of committed credit facilities and<br />
<strong>the</strong> ability <strong>to</strong> close-out any open market positions.<br />
The Company manages liquidity risk by continuously moni<strong>to</strong>ring forecast and actual cash flows; matching maturity profiles of<br />
financial assets and liabilities; and by maintaining flexibility in funding including ensuring that surplus funds are generally only<br />
invested in instruments that are tradable in highly liquid markets or that can be relinquished with minimal risk of loss.<br />
84
(i) Financing arrangements<br />
The Company had <strong>the</strong> following established undrawn borrowing facilities at <strong>the</strong> <strong>report</strong>ing date:<br />
Facility<br />
Total Facility<br />
Undrawn Amount<br />
December 31, 2011<br />
$<br />
OPIC secured loan 35,500,000 -<br />
Mitsui unsecured loan 10,393,023 -<br />
2.75% convertible notes 70,000,000 -<br />
BNP Paribas working capital facility 1* 200,000,000 35,090,000<br />
BNP Paribas working capital facility 2 60,000,000 49,969,869<br />
Westpac working capital facility (PGK denominated) 37,320,000 30,869,628<br />
BSP working capital facility (PGK denominated) 23,325,000 23,325,000<br />
* Includes <strong>the</strong> temporary increase of $30.0 million that expires on January 31, 2012.<br />
436,538,023 139,254,497<br />
(ii) Maturities of financial liabilities<br />
The tables below analyses <strong>the</strong> Company’s financial liabilities, net and gross settled derivative financial instruments in<strong>to</strong> relevant<br />
maturity groupings based on <strong>the</strong> remaining period at <strong>the</strong> <strong>report</strong>ing date <strong>to</strong> <strong>the</strong> contractual maturity date. The amounts<br />
disclosed in <strong>the</strong> table are <strong>the</strong> contractual undiscounted cash flows.<br />
Non-derivatives<br />
Less than 1 year<br />
Between 1 and 5<br />
years<br />
More than 5 years<br />
"Total contractual<br />
cash flow<br />
Trade and o<strong>the</strong>r payables (note 16) 159,882,177 - - 159,882,177<br />
Working capital facility (note 18) 16,480,503 - - 16,480,503<br />
Secured and unsecured loans (note 20) 21,727,400 29,859,050 - 51,586,450<br />
2.75% convertible notes (note 26) 1,925,000 75,614,583 - 77,539,583<br />
Total non-derivatives 200,015,080 105,473,633 - 305,488,713<br />
Derivatives<br />
Derivative financial instruments (note 9) 11,457 - - 11,457<br />
Total derivatives 11,457 - - 11,457<br />
The ageing of trade and o<strong>the</strong>r payables are as follows:<br />
Trade and o<strong>the</strong>r payables<br />
200,026,537 105,473,633 - 305,500,170<br />
Total<br />
$<br />
Payable ageing between<br />
60 days<br />
$<br />
December 31, 2011 159,882,177 157,758,605 979,728 1,143,844<br />
December 31, 2010 75,132,880 70,788,064 1,766,354 2,578,462<br />
(c) Credit risk<br />
Credit risk is <strong>the</strong> risk that a contracting entity will not <strong>complete</strong> its obligation under a financial instrument that will result in a<br />
financial loss <strong>to</strong> <strong>the</strong> Company. The carrying amount of financial assets represents <strong>the</strong> maximum credit exposure.<br />
The Company’s credit risk is limited <strong>to</strong> <strong>the</strong> carrying value of its financial assets. A significant amount of <strong>the</strong> Company’s export<br />
sales are made <strong>to</strong> two cus<strong>to</strong>mers which represented $260,468,514 (Dec 2010 - $211,864,290) or 24% (Dec 2010 – 26%)<br />
of <strong>to</strong>tal sales in <strong>the</strong> year ended December 31, 2011. The Company’s domestic sales for <strong>the</strong> year ended December 31, 2011<br />
were not dependent on a single cus<strong>to</strong>mer or geographic region within PNG. The export sales <strong>to</strong> two cus<strong>to</strong>mers is not<br />
considered a key risk as <strong>the</strong>re is a ready market for <strong>InterOil</strong> export products and <strong>the</strong> prices are quoted on active markets.<br />
The receivables from <strong>the</strong>se cus<strong>to</strong>mers are current as at December 31, 2011. The Company actively manages credit risk by<br />
routinely moni<strong>to</strong>ring <strong>the</strong> credit ratings of <strong>the</strong> Company’s export cus<strong>to</strong>mers and by moni<strong>to</strong>ring <strong>the</strong> ageing of trade receivables<br />
of <strong>the</strong> Company’s domestic cus<strong>to</strong>mers. The credit terms provided <strong>to</strong> cus<strong>to</strong>mers are revised if any changes are noted <strong>to</strong><br />
cus<strong>to</strong>mer ratings or payment cycles.<br />
85
Credit risk on cash, cash equivalents and short term treasury bills held directly by <strong>the</strong> Company are minimized as all cash<br />
amounts, certificates of deposit and treasury bills are held with banks which have acceptable credit ratings.<br />
The maximum exposure <strong>to</strong> credit risk at <strong>the</strong> <strong>report</strong>ing date was as follows:<br />
Current<br />
December 31,<br />
2011<br />
$<br />
December 31,<br />
2010<br />
$<br />
Cash and cash equivalents 68,846,441 233,576,821<br />
Cash restricted 32,982,001 40,664,995<br />
Short term treasury bills 11,832,110 -<br />
Trade and o<strong>the</strong>r receivables 135,273,600 48,047,496<br />
Commodity derivative contracts 595,440 -<br />
Non-current<br />
Cash restricted 6,268,762 6,613,074<br />
The ageing of trade receivables at <strong>the</strong> <strong>report</strong>ing date was as follows (<strong>the</strong> ageing days relates <strong>to</strong> balances past due):<br />
Net trade receivables<br />
Total<br />
$<br />
Current<br />
$<br />
Receivable ageing<br />
60 days<br />
$<br />
December 31, 2011 112,239,803 51,026,962 40,875,467 13,076,371 7,261,003<br />
December 31, 2010 45,428,435 20,344,957 19,239,373 3,198,155 2,645,950<br />
The impairment of trade receivables at <strong>the</strong> <strong>report</strong>ing date was as follows:<br />
Total<br />
$<br />
Current<br />
$<br />
Overdue<br />
(not impared)<br />
$<br />
Overdue<br />
(impared)<br />
$<br />
December 31, 2011 113,761,948 51,026,961 61,212,842 1,522,145<br />
December 31, 2010 47,934,378 20,344,957 25,083,478 2,505,943<br />
Impairment is assessed by <strong>the</strong> Company on an individual cus<strong>to</strong>mer basis, based on cus<strong>to</strong>mer ratings and payment cycles of<br />
<strong>the</strong> cus<strong>to</strong>mers. An impairment provision is taken for all receivables where objective evidence of impairment exists. The<br />
movement in impairment is also influenced by <strong>the</strong> translation rates used <strong>to</strong> convert <strong>the</strong>se amounts from local currency <strong>to</strong><br />
USD.<br />
O<strong>the</strong>r receivables as at December 31, 2011 of $23,033,797 (Dec 2010 - $2,619,061) were not impaired.<br />
The movement in impaired trade receivables for <strong>the</strong> year ended December 31, 2011 was as follows:<br />
Trade receivables - Impairment provisions<br />
December 31,<br />
2011<br />
$<br />
Year ended<br />
December 31,<br />
2010<br />
$<br />
Opening balance 2,505,943 3,603,342<br />
Foreign exchange impact on opening balance 582,623 82,779<br />
Amounts written off during <strong>the</strong> year (1,078,455) (666,034)<br />
Movement in provisions, net of reversals made (487,966) (514,144)<br />
Closing balance 1,522,145 2,505,943<br />
(d) Geographic risk<br />
The operations of <strong>InterOil</strong> are concentrated in PNG.<br />
(e) Financing facilities<br />
As at December 31, 2011, <strong>the</strong> Company had drawn down against <strong>the</strong> following financing facilities:<br />
86
•<br />
•<br />
•<br />
•<br />
•<br />
BNP working capital facility (refer note 18)<br />
Westpac working capital facility (refer note 18)<br />
OPIC secured loan facility (refer note 20)<br />
Mitsui unsecured loan facility (refer note 20)<br />
2.75% convertible notes (refer note 26)<br />
Repayment obligations in respect of <strong>the</strong> amount of <strong>the</strong> facilities utilized are as follows:<br />
Due:<br />
December 31,<br />
2011<br />
$<br />
December 31,<br />
2010<br />
$<br />
No later than one year 35,873,526 65,711,083<br />
Later than one year but not later than two years 9,000,000 9,000,000<br />
Later than two years but not later than three years 9,000,000 9,000,000<br />
Later than three years but not later than four years 78,500,000 9,000,000<br />
Later than four years but not later than five years - 78,500,000<br />
Later than five years - -<br />
(f) Effective interest rates and maturity profile<br />
December 31, 2011<br />
Financial assets<br />
Floating<br />
interest rate<br />
$<br />
1 year or<br />
less<br />
$<br />
1-2<br />
$<br />
Fixed interest maturing between<br />
2-3<br />
$<br />
132,373,526 171,211,083<br />
Noninterest<br />
bearing<br />
$<br />
Cash and cash equivalents 30,955,254 37,891,187 - - - - - - 68,846,441 0.23%<br />
Cash restricted 38,885,482 365,281 - - - - - - 39,250,763 2.86%<br />
Short term treasury bills - 11,832,110 - - - - - - 11,832,110 4.32%<br />
Receivables - - - - - - - 135,273,600 135,273,600 -<br />
Investments - - - - - - - 3,650,786 3,650,786 -<br />
O<strong>the</strong>r financial assets - - - - - - - 6,073,036 6,073,036 -<br />
Financial liabilities<br />
3-4<br />
$<br />
4-5<br />
$<br />
More<br />
than<br />
5<br />
years<br />
$<br />
69,840,736 50,088,578 - - - - - 144,997,422 264,926,736<br />
Payables - - - - - - - 159,882,177 159,882,177 -<br />
Interest bearing liabilities 26,873,526 9,000,000 9,000,000 9,000,000 8,500,000 - - - 62,373,526 6.93%<br />
Convertible notes liability - - - - 70,000,000 - - - 70,000,000 7.91%<br />
O<strong>the</strong>r financial liabilities - - - - - - - 11,457 11,457 -<br />
26,873,526 9,000,000 9,000,000 9,000,000 78,500,000 - - 159,893,634 292,267,160<br />
Total<br />
$<br />
Effective<br />
interest<br />
rate<br />
%<br />
December 31, 2010<br />
Financial assets<br />
Floating<br />
interest rate<br />
$<br />
1 year or<br />
less<br />
$<br />
1-2<br />
$<br />
Fixed interest maturing between<br />
2-3<br />
$<br />
Noninterest<br />
bearing<br />
$<br />
Cash and cash equivalents 232,371,517 1,205,304 - - - - - - 233,576,821 0.21%<br />
Cash restricted 46,968,143 309,926 - - - - - - 47,278,069 2.89%<br />
Receivables - - - - - - - 48,047,496 48,047,496 -<br />
O<strong>the</strong>r financial assets - - - - - - - 3,593,574 3,593,574 -<br />
Financial liabilities<br />
3-4<br />
$<br />
4-5<br />
$<br />
More<br />
than<br />
5<br />
years<br />
$<br />
279,339,660 1,515,230 - - - - - 51,641,070 332,495,960<br />
Payables - - - - - - - 76,087,954 76,087,954 -<br />
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%<br />
Convertible notes liability - - - - - 70,000,000 - - 70,000,000 7.91%<br />
O<strong>the</strong>r financial liabilities - - - - - - - 178,578 178,578 -<br />
56,711,083 9,000,000 9,000,000 9,000,000 9,000,000 78,500,000 - 76,266,532 247,477,615<br />
Total<br />
$<br />
Effective<br />
interest<br />
rate<br />
%<br />
87
(g) Fair values<br />
December 31, 2011 December 31, 2010<br />
Carrying<br />
Amount<br />
$<br />
Fair Value<br />
$<br />
Carrying<br />
Amount<br />
$<br />
Fair Value<br />
$<br />
Fair value hierarchy<br />
level<br />
(as required)*<br />
Method of measurement<br />
Financial instruments<br />
Financial assets<br />
Loans and receivables<br />
Cash and cash equivalents (note 6) 68,846,441 68,846,441 233,576,821 233,576,821 Amortized Cost<br />
Cash restricted (note 9) 39,250,763 39,250,763 47,278,069 47,278,069 Amortized Cost<br />
Short term treasury bills (note 8) 11,832,110 11,832,110 - - Amortized Cost<br />
Receivables (note 10) 135,273,600 135,273,600 48,047,496 48,047,496 Amortized Cost<br />
Available-for-sale<br />
Investments (note 14) 3,650,786 3,650,786 - - Level 1 Fair Value - See (i) below<br />
Held for trading<br />
Derivative contracts (note 9) 583,983 583,983 (178,578) (178,578) Level 2 Fair Value - See (ii) below<br />
Financial liabilities<br />
Current liabilities:<br />
Accounts payable and accrued liabilities (note 16) 159,882,177 159,882,177 76,087,954 76,087,954 Amortized Cost<br />
Working capital facility (note 18) 16,480,503 16,480,503 51,254,326 51,254,326 Amortized Cost<br />
"Current portion of secured and unsecured loans 34,813,222 38,879,426 43,589,278 47,696,040<br />
(note 20)" 19,393,023 19,638,921 14,456,757 14,583,922<br />
Non-current liabilities<br />
Secured loan (note 20) 26,037,166 28,911,667 34,813,222 38,879,426<br />
Amortized cost See (2)<br />
below<br />
Amortized cost See (iii)<br />
below<br />
Amortized cost See (iii)<br />
below<br />
2.75% Convertible notes liability (note 26) 55,637,630 55,637,630 52,425,489 52,425,489 Amortized Cost<br />
* Where fair value of financial assets or liabilities is approximated by its carrying value, designation under <strong>the</strong> fair value hierarchy is not required.<br />
The net fair value of cash and cash equivalents and non-interest bearing financial assets and financial liabilities of <strong>the</strong><br />
Company approximates <strong>the</strong>ir carrying amounts.<br />
The carrying values (less impairment provision if provided) of trade receivables and payables are assumed <strong>to</strong> approximate<br />
<strong>the</strong>ir fair values due <strong>to</strong> <strong>the</strong>ir short-term nature. The carrying value of financial liabilities approximates <strong>the</strong>ir fair values which, for<br />
disclosure purposes, are estimated by discounting <strong>the</strong> future contractual cash flows at <strong>the</strong> current market interest rate that is<br />
available <strong>to</strong> <strong>the</strong> Company for similar financial instruments.<br />
Commodity derivative contracts’ and available-for-sale investments are <strong>the</strong> only items from <strong>the</strong> above table that are measured<br />
at fair value on a recurring basis. All <strong>the</strong> remaining financial assets and financial liabilities are measured at a fair value on a<br />
non-recurring basis and are maintained at his<strong>to</strong>rical amortized cost.<br />
The fair value of financial assets and financial liabilities must be estimated for recognition and measurement or for disclosure<br />
purposes. The Company has classified <strong>the</strong> fair value measurements using a fair value hierarchy that reflects <strong>the</strong> significance of<br />
<strong>the</strong> inputs used in making <strong>the</strong> measurements. The fair value hierarchy shall have <strong>the</strong> following levels:<br />
Level 1<br />
Level 2<br />
Level 3<br />
quoted prices (unadjusted) in active markets for identical assets or liabilities<br />
inputs o<strong>the</strong>r than quoted prices included in Level 1 that are observable for <strong>the</strong> asset or liability, ei<strong>the</strong>r<br />
directly (i.e., as prices) or indirectly (i.e., derived from prices); and<br />
inputs for <strong>the</strong> asset or liability that are not based on observable market data (unobservable inputs).<br />
(i) Investments classified as being available-for-sale are fair valued by using quoted prices on Oslo s<strong>to</strong>ck exchange Axess.<br />
(ii) Derivative contracts classified as being at fair value through profit and loss are fair valued by comparing <strong>the</strong> contracted rate<br />
<strong>to</strong> <strong>the</strong> current market rate for a contract with <strong>the</strong> same remaining period <strong>to</strong> maturity. The fair value of <strong>the</strong> Company’s<br />
derivative contracts are based on price indications provided <strong>to</strong> us by an external brokerage who enter in<strong>to</strong> derivative<br />
transactions with counter parties on <strong>the</strong> Company’s behalf.<br />
88
(iii) The fair value of <strong>the</strong> secured loan is based on discounted cash flow analysis using a current market interest rate applicable<br />
for <strong>the</strong> loan arrangement, being <strong>the</strong> current interest rate on a U.S. treasury note with <strong>the</strong> same approximate maturity profile<br />
plus <strong>the</strong> OPIC spread (3%).<br />
(h) Capital management<br />
The finance department of <strong>the</strong> Company is responsible for capital management. This involves <strong>the</strong> use of operating and<br />
development economic forecasting models which facilitates analysis of <strong>the</strong> Company’s financial position including cash flow<br />
forecasts <strong>to</strong> determine <strong>the</strong> future capital management strategy. Capital management is undertaken <strong>to</strong> ensure a secure,<br />
cost-effective and flexible supply of funds is available <strong>to</strong> meet <strong>the</strong> Company’s expenditure requirements and safeguard its<br />
abilities <strong>to</strong> continue as a going concern.<br />
The Company is actively managing <strong>the</strong> gearing levels and raising equity/debt as required for optimizing shareholder returns.<br />
The Company is managing its gearing levels by maintaining <strong>the</strong> debt-<strong>to</strong>-capital ratio (debt/(shareholders’ equity + debt)) at<br />
50% or less. The gearing levels were 12% in December 2011 (13% in December 2010). The optimum gearing levels for <strong>the</strong><br />
Company are overseen by <strong>the</strong> Board of Direc<strong>to</strong>rs based on recommendations by Management. Recommendations are based<br />
on operating cash flows, future cash needs for development, capital market conditions, economic conditions, and will be<br />
reassessed as situations change.<br />
On February 2, 2011, <strong>the</strong> Company and Liquid Niugini Gas Limited, <strong>the</strong> Company’s joint venture liquefied natural gas project<br />
company with Pacific LNG Operations Ltd, signed a Project Funding and Construction Agreement (“PFCA”) and a<br />
Shareholder Agreement with Energy World <strong>Corporation</strong> Ltd (“EWC”) governing <strong>the</strong> parameters in respect of <strong>the</strong> development,<br />
construction, financing and operation of a planned three million <strong>to</strong>nne per annum land-based modular LNG plant in PNG. In<br />
return for its commitment <strong>to</strong> fully fund <strong>the</strong> development and construction of <strong>the</strong> LNG plant, <strong>the</strong> agreements provide that EWC<br />
will be entitled <strong>to</strong> a fee of 14.5% of <strong>the</strong> proceeds from <strong>the</strong> sale of LNG from <strong>the</strong> plant, less agreed deductions and financing<br />
costs, and that EWC will also own a 14.5% interest in <strong>the</strong> operating company of <strong>the</strong> LNG plant. The PFCA and Shareholder<br />
Agreement with EWC are conditional on reaching final investment decision <strong>to</strong> proceed with <strong>the</strong> LNG plant no later than March<br />
31, 2012.<br />
On April 11, 2011, <strong>the</strong> Company and Pac LNG executed a conditional framework agreement with FLEX LNG and Samsung<br />
Heavy Industries related <strong>to</strong> <strong>the</strong> construction and operation of a two mtpa floating LNG processing vessel. The project is<br />
intended <strong>to</strong> integrate with and augment proposed infrastructure <strong>to</strong> LNG from <strong>the</strong> onshore Elk and Antelope fields in <strong>the</strong> Gulf<br />
Province of Papua New Guinea pursuant <strong>to</strong> arrangements with EWC and Mitsui. FLEX LNG will be responsible for <strong>the</strong> design,<br />
engineering, construction and commissioning of <strong>the</strong> FLNG vessel. Construction of <strong>the</strong> FLNG vessel will be fully financed by<br />
FLEX LNG and Samsung Heavy Industries. The framework agreements provided that <strong>the</strong> parties were <strong>to</strong> undertake project<br />
specific FEED work and negotiate final binding agreements in time for a FID decision in mid-December 2011. Project specific<br />
FEED work was carried out. However, as FID was reached by mid-December 2011, <strong>the</strong>se framework agreements with FLEX<br />
LNG and Samsung lapsed and were not extended. The Company is continuing <strong>to</strong> negotiate with FLEX LNG.<br />
In September 2011, <strong>the</strong> Company retained financial advisors <strong>to</strong> help solicit and evaluate proposals from potential strategic<br />
partners <strong>to</strong>, amongst o<strong>the</strong>r things, obtain an interest in, operate and help finance <strong>the</strong> development of <strong>the</strong> Gulf LNG Project.<br />
The Company believes that it has sufficient funds for <strong>the</strong> Midstream Refinery and Downstream operations; however, existing<br />
cash balances and ongoing cash generated from <strong>the</strong>se operations will not be sufficient <strong>to</strong> facilitate fur<strong>the</strong>r necessary<br />
development of <strong>the</strong> Elk and Antelope fields, condensate stripping and liquefaction facilities. Therefore <strong>the</strong> Company must<br />
extend or secure sufficient funding through renewed or additional borrowings, equity raising and or asset sales <strong>to</strong> enable<br />
sufficient cash <strong>to</strong> be available <strong>to</strong> fur<strong>the</strong>r its development plans. Management expects that <strong>the</strong> Company will be able <strong>to</strong> secure<br />
<strong>the</strong> necessary financing through one, or a combination of, <strong>the</strong> aforementioned alternatives.<br />
5. Segmented financial information<br />
As stated in note 1, management has identified four major <strong>report</strong>ing segments - Upstream, Midstream, Downstream and<br />
Corporate. Midstream consists of both Midstream Refining and Midstream Liquefaction. The Corporate segment includes<br />
assets and liabilities that do not specifically relate <strong>to</strong> <strong>the</strong> o<strong>the</strong>r <strong>report</strong>ing segments. Results in this segment primarily include<br />
management expenses. Consolidation adjustments relating <strong>to</strong> <strong>to</strong>tal assets relates <strong>to</strong> <strong>the</strong> elimination of intercompany loans<br />
and investments in subsidiaries.<br />
Notes <strong>to</strong> and forming part of <strong>the</strong> segment information<br />
Segment information is prepared in conformity with <strong>the</strong> accounting policies of <strong>the</strong> entity. Segment revenues, expenses and<br />
<strong>to</strong>tal assets are those that are directly attributable <strong>to</strong> a segment and <strong>the</strong> relevant portion that can be allocated <strong>to</strong> <strong>the</strong> segment<br />
89
on a reasonable basis. Upstream, Midstream and Downstream include costs allocated from <strong>the</strong> Corporate activities based on<br />
a fee for services provided. The eliminations relate <strong>to</strong> sales and operating revenues between segments recorded at transfer<br />
prices based on current market prices and <strong>to</strong> unrealized intersegment profits in inven<strong>to</strong>ries. The majority of <strong>the</strong> Company’s<br />
operations are located in Papua New Guinea, with <strong>the</strong> exception of <strong>the</strong> Corporate segment which also has operations in <strong>the</strong><br />
United States, Australia and Singapore.<br />
Included in <strong>the</strong> Company’s revenues from external cus<strong>to</strong>mers for <strong>the</strong> year ended December 31, 2011 is revenue from exports<br />
<strong>to</strong> foreign countries of $273,827,525 (Dec 2010 - $227,932,775). The Midstream – Refining segment derives <strong>the</strong>ir revenue<br />
from <strong>the</strong> sale of refined petroleum product <strong>to</strong> <strong>the</strong> domestic market in PNG and for export. The Downstream segment derives<br />
<strong>the</strong>ir revenue from <strong>the</strong> sale of refined petroleum product <strong>to</strong> <strong>the</strong> domestic market in PNG on a wholesale and retail basis. The<br />
Corporate segment derives <strong>the</strong>ir revenue from <strong>the</strong> shipping business which currently operates two vessels transporting<br />
petroleum products for our Downstream segment and external cus<strong>to</strong>mers, both within PNG and for export in <strong>the</strong> South<br />
Pacific region.<br />
Year ended December 31, 2011<br />
Upstream<br />
Midstream -<br />
Refining<br />
Midstream -<br />
Liquefaction<br />
Downstream<br />
Corporate<br />
Consolidation<br />
adjustments<br />
Revenues from external cus<strong>to</strong>mers - 362,605,718 - 743,662,499 265,636 - 1,106,533,853<br />
Intersegment revenues - 585,513,409 - 196,988 53,362,401 (639,072,798) -<br />
Interest revenue 15,146 830,795 2 7,968 38,511,774 (38,009,561) 1,356,124<br />
O<strong>the</strong>r revenue 9,826,126 - - 1,255,434 (23,470) - 11,058,090<br />
Total segment revenue 9,841,272 948,949,922 2 745,122,889 92,116,341 (677,082,359) 1,118,948,067<br />
Cost of sales and operating expenses - 897,824,569 - 704,213,086 11,420,968 (592,526,701) 1,020,931,922<br />
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<br />
Derivative (gain)/loss - (2,017,778) - - 11,457 - (2,006,321)<br />
Foreign exchange loss/(gain) 2,152,675 (26,458,424) 13,127 229,042 (955,081) - (25,018,661)<br />
Loss on Flex LNG investment - - - - 3,420,406 - 3,420,406<br />
Exploration costs, excluding exploration<br />
impairment<br />
18,435,150 - - - - - 18,435,150<br />
Depreciation and amortisation 3,254,672 11,253,854 25,632 4,026,422 1,706,037 (129,968) 20,136,649<br />
Interest expense 30,012,655 9,664,482 1,307,901 4,346,081 6,011,916 (38,009,561) 13,333,474<br />
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<br />
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<br />
Income tax benefit/(expense) - 6,945,518 - (4,962,288) (1,247,563) - 735,667<br />
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<br />
Segment assets 390,448,139 444,687,129 7,925,856 201,906,476 69,624,747 (62,202,814) 1,052,389,533<br />
Unallocated:<br />
Deferred tax (note 15) 35,965,273<br />
Total assets per <strong>the</strong> balance sheet 1,088,354,806<br />
Segment liabilities 79,730,935 139,105,842 8,759,273 85,110,349 74,025,870 (60,157,290) 326,574,979<br />
Unallocated:<br />
Deferred tax (note 15) 1,889,391<br />
Total liabilities per <strong>the</strong> balance sheet 328,464,370<br />
Capital expenditure (net of cash calls) 107,558,028 15,861,056 5,173,603 10,240,083 3,118,687 - 141,951,457<br />
Total<br />
90
Year ended December 31, 2010<br />
Upstream<br />
Midstream -<br />
Refining<br />
Midstream -<br />
Liquefaction<br />
Downstream<br />
Corporate<br />
Consolidation<br />
adjustments<br />
Revenues from external cus<strong>to</strong>mers - 298,070,718 - 504,303,681 - - 802,374,399<br />
Intersegment revenues - 379,343,999 - 483,134 32,563,686 (412,390,819) -<br />
Interest revenue 14,757 58,229 643 23,490 24,334,629 (24,280,932) 150,816<br />
O<strong>the</strong>r revenue 3,290,721 107,714 - 1,048,251 23,362 - 4,470,048<br />
Total segment revenue 3,305,478 677,580,660 643 505,858,556 56,921,677 (436,671,751) 806,995,263<br />
Cost of sales and operating expenses - 605,602,656 - 470,771,827 - (374,817,833) 701,556,650<br />
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<br />
Derivative loss/(gain) - 1,591,878 - - (526,690) - 1,065,188<br />
Foreign exchange loss/(gain) 3,043,907 7,517,961 90,367 1,175,894 (1,051,306) - 10,776,823<br />
Gain on sale of exploration assets (2,140,783) - - - - - (2,140,783)<br />
Loss on extinguishment of IPI liability 30,568,710 - - - - - 30,568,710<br />
Litigation settlement expense - - - - 12,000,000 - 12,000,000<br />
Exploration costs, excluding exploration<br />
impairment<br />
16,981,929 - - - - - 16,981,929<br />
Depreciation and amortisation 1,132,118 10,355,057 25,227 2,786,500 105,988 (129,968) 14,274,922<br />
Interest expense 18,527,881 6,584,584 1,252,796 3,739,297 1,540,594 (24,280,932) 7,364,220<br />
Total segment expenses 81,859,981 643,591,636 8,391,034 494,449,400 52,360,071 (435,553,511) 845,098,611<br />
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)<br />
Income tax (expense)/benefit - (504,387) 35,905 (4,701,386) (1,239,855) - (6,409,723)<br />
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)<br />
Segment assets 266,169,785 325,089,253 7,823,600 117,708,440 265,233,362 (34,759,579) 947,264,861<br />
Unallocated:<br />
Deferred tax (note 15) 28,477,690<br />
Total assets per <strong>the</strong> balance sheet 975,742,551<br />
Segment liabilities 81,193,873 109,332,954 11,561,364 35,055,512 66,139,037 (30,442,168) 272,840,572<br />
Capital expenditure (net of cash calls) 82,811,176 6,972,505 1,876,736 7,623,024 3,661,267 - 102,944,708<br />
6. Cash and cash equivalents<br />
The components of cash and cash equivalents are as follows:<br />
December 31, 2011<br />
$<br />
Total<br />
December 31, 2010<br />
$<br />
Cash on deposit 45,970,047 233,576,821<br />
Bank term deposits - Papua New Guinea kina deposits 22,876,394 -<br />
68,846,441 233,576,821<br />
91
In 2011, cash and cash equivalents earned an average interest rate of 0.23% per annum (2010 – 0.21%).<br />
7. Supplemental cash flow information<br />
Cash paid during <strong>the</strong> year<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Interest 7,238,610 5,827,959<br />
Income taxes 1,450,341 3,254,382<br />
Interest received 1,008,407 143,315<br />
Non-cash investing activities:<br />
Fair value of Flex LNG option received 4,214,258 -<br />
Increase in share capital from:<br />
buyback of non-controlling interest 243,850 -<br />
Non-cash financing activities:<br />
Increase in share capital from:<br />
<strong>the</strong> exercise of share options and vesting of restricted s<strong>to</strong>ck 5,598,009 8,454,758<br />
buyback of IPI #3 inves<strong>to</strong>r rights - 50,687,368<br />
litigation settlement settled in shares - 12,000,000<br />
8. Short term treasury bills<br />
During <strong>the</strong> quarter ended September 30, 2011, <strong>the</strong> Company purchased two treasury bills from <strong>the</strong> Bank of Papua New<br />
Guinea <strong>to</strong>taling approximately $11,832,110 (PGK 25,363,312). Both of <strong>the</strong>se treasury bills have a 182 day term and will<br />
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<br />
<strong>the</strong> second treasury bill for approximately $9,134,260 (PGK 19,580,200) has an interest rate of 4.3%.<br />
Based on <strong>the</strong> guidance under IAS 39 ‘Financial Instruments Recognition and Measurement’, <strong>the</strong>se investments have been<br />
classified as held-<strong>to</strong>-maturity financial assets and are <strong>the</strong>refore recorded at amortized cost using <strong>the</strong> effective interest method.<br />
9. Financial instruments<br />
(a) Cash and cash equivalents<br />
With <strong>the</strong> exception of cash and cash equivalents, restricted cash and short term treasury bills, all financial assets are<br />
non-interest bearing. In 2011, <strong>the</strong> Company earned nil interest (2010 – nil) on <strong>the</strong> cash on deposit which related <strong>to</strong> <strong>the</strong><br />
working capital facility. However, <strong>the</strong> cash deposit relating <strong>to</strong> <strong>the</strong> BNP working capital facility reduced <strong>the</strong> interest costs<br />
relating <strong>to</strong> <strong>the</strong> facility usage in 2011 by 3.38% (2010 – 3.33%).<br />
Cash restricted, which mainly relates <strong>to</strong> <strong>the</strong> working capital facility, is comprised of <strong>the</strong> following:<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Cash deposit on working capital facility (0.0%) 32,982,001 40,664,995<br />
Cash restricted - Current 32,982,001 40,664,995<br />
Bank term deposits on Petroleum Prospecting Licenses (1.6%) 161,801 130,486<br />
Cash deposit on office premises (5.3%) 203,480 179,440<br />
Cash deposit on secured loan (0.1%) 5,903,481 6,303,148<br />
Cash restricted - Non-current 6,268,762 6,613,074<br />
39,250,763 47,278,069<br />
Cash held as deposit on <strong>the</strong> BNP working capital facility supports <strong>the</strong> Company’s working capital facility with BNP<br />
Paribas. The balance is based on 20% of <strong>the</strong> outstanding balance of <strong>the</strong> BNP working capital facility 1 (refer note 18) plus any<br />
amounts that are fully cash secured. The cash deposit on this facility did not receive interest during <strong>the</strong> year as <strong>the</strong>se deposit<br />
amounts reduced <strong>the</strong> interest being charged by BNP on <strong>the</strong> facility utilization.<br />
92
The cash held as deposit on secured loan is used <strong>to</strong> support <strong>the</strong> Company’s secured loan borrowings with <strong>the</strong> Overseas<br />
Private Investment <strong>Corporation</strong> (“OPIC”) and relates <strong>to</strong> one half yearly installment of $4.5 million and <strong>the</strong> related interest that<br />
will be payable with <strong>the</strong> next installment.<br />
Bank term deposits on PPL’s are unavailable for use while PPL 236, 237 and 238 are being utilized by <strong>the</strong> Company.<br />
(b) Commodity derivative contracts<br />
<strong>InterOil</strong> uses derivative commodity instruments <strong>to</strong> manage its exposure <strong>to</strong> price volatility on a portion of its refined product and<br />
crude inven<strong>to</strong>ries in accordance with risk management policy described in note 4.<br />
At December 31, 2011, <strong>InterOil</strong> had a net receivable of $595,440 (Dec 2010 – payable of $178,578) relating <strong>to</strong> outstanding<br />
derivative contracts for which hedge accounting was not applied or had been discontinued.<br />
The Company had no outstanding hedge accounted derivative contracts as at December 31, 2011 and December 31, 2010.<br />
As at December 31, 2011, <strong>the</strong> Company had <strong>the</strong> following open non-hedge accounted derivative contracts outstanding.<br />
Derivative<br />
Type<br />
Notional Volumes<br />
(bbls)<br />
Expiry<br />
Brent Swap Sell Brent 70,000 Q1 2012<br />
Gasoil Crack<br />
Swap<br />
Gasoil Crack<br />
Swap<br />
Gasoil Crack<br />
Swap<br />
Sell Gasoil<br />
Crack<br />
Sell Gasoil<br />
Crack<br />
Sell Gasoil<br />
Crack<br />
195,000 Q1 2012<br />
195,000 Q2 2012<br />
195,000 Q3 2012<br />
Derivative type<br />
Cash flow hedge - Manages <strong>the</strong> export price risk of<br />
naphtha<br />
Cash flow hedge - Manages <strong>the</strong> sales price risk of gasoil<br />
(diesel)<br />
Cash flow hedge - Manages <strong>the</strong> sales price risk of gasoil<br />
(diesel)<br />
Cash flow hedge - Manages <strong>the</strong> sales price risk of gasoil<br />
(diesel)<br />
Fair Value<br />
December 31, 2011<br />
$<br />
(63,681)<br />
154,516<br />
185,495<br />
221,160<br />
497,490<br />
Add: Priced out non-hedge accounted contracts as at December 31, 2011 97,950<br />
595,440<br />
As at December 31, 2010, <strong>the</strong> Company had <strong>the</strong> following open non-hedge accounted derivative contracts outstanding.<br />
Derivative<br />
Naphtha<br />
Swap<br />
Type<br />
Notional Volumes<br />
(bbls)<br />
Expiry<br />
Sell Naphtha 54,000 Q1 2011<br />
Brent Swap Buy Brent 54,000 Q1 2011<br />
Naphtha/<br />
Brent Swap<br />
Sell Naphtha/ Buy<br />
Brent<br />
54,000 Q1 2011<br />
Derivative type<br />
Cash flow hedge - Manages <strong>the</strong> export price risk of<br />
naphtha<br />
Cash flow hedge - Manages <strong>the</strong> export price risk of<br />
naphtha<br />
Cash flow hedge - Manages <strong>the</strong> export price risk of<br />
naphtha<br />
Add: Priced out non-hedge accounted contracts as at December 31, 2010 -<br />
Fair Value<br />
December 31, 2010<br />
$<br />
(275,958)<br />
179,118<br />
(81,738)<br />
(178,578)<br />
(178,578)<br />
A gain of $2,017,778 was recognized on <strong>the</strong> non-hedge accounted derivative contracts for <strong>the</strong> year ended December 31,<br />
2011 (Dec 2010 – loss of $1,591,878). This gain is included in derivative gain/(loss) in <strong>the</strong> consolidated income statement.<br />
(c) Currency derivative contracts<br />
During <strong>the</strong> year ended December 31, 2010, <strong>the</strong> Company started <strong>to</strong> enter in<strong>to</strong> AUD <strong>to</strong> USD foreign currency forward<br />
contracts <strong>to</strong> minimize <strong>the</strong> foreign exchange risk in relation <strong>to</strong> <strong>the</strong> expenses <strong>to</strong> be incurred in AUD. As at December 31, 2011,<br />
<strong>the</strong> Company had a net payable of $11,457 (Dec 2010 - $nil) in relation <strong>to</strong> outstanding non-hedge accounted currency<br />
derivative contracts.<br />
A loss of $11,457 was recognized on <strong>the</strong> non-hedge accounted currency derivative contracts for <strong>the</strong> year ended December<br />
31, 2011 (Dec 2010 – gain of $526,690). This loss is included in derivative gain/(loss) in <strong>the</strong> consolidated income statement.<br />
93
10. Trade and o<strong>the</strong>r receivables<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Trade receivables 112,239,803 45,428,435<br />
O<strong>the</strong>r receivables 23,033,797 2,619,061<br />
Total 135,273,600 48,047,496<br />
<strong>InterOil</strong> has a discounting facility with BNP Paribas on specific monetary receivables under which <strong>the</strong> Company is able <strong>to</strong> sell,<br />
on a revolving basis, trade receivables up <strong>to</strong> $60,000,000 (refer <strong>to</strong> note 18). As at December 31, 2011, $10,030,131 (Dec<br />
2010 - $nil) in outstanding trade receivables had been sold with recourse under <strong>the</strong> facility. As <strong>the</strong> sale is with recourse, <strong>the</strong><br />
discounted trade receivables, if any, are retained on <strong>the</strong> balance sheet and included in <strong>the</strong> accounts receivable and <strong>the</strong> sale<br />
proceeds are recognized in <strong>the</strong> working capital facility. The Company has retained <strong>the</strong> responsibility for administering and<br />
collecting accounts receivable sold. The discounted trade receivables are usually settled within a month of <strong>the</strong>ir discounting<br />
and <strong>the</strong>re have not been any collection issues relating <strong>to</strong> <strong>the</strong>se discounted trade receivables.<br />
At December 31, 2011, $74,265,832 (Dec 2010 - $26,884,664) of <strong>the</strong> trade receivables secures <strong>the</strong> BNP Paribas working<br />
capital facility disclosed in note 18. This balance includes $53,815,857 (Dec 2010 - $21,797,631) of intercompany<br />
receivables which were eliminated on consolidation.<br />
11. Inven<strong>to</strong>ries<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Midstream - Refining (crude oil feeds<strong>to</strong>ck) 40,311,108 23,004,883<br />
Midstream - Refining (refined petroleum product) 70,267,854 67,006,941<br />
Midstream - Refining (parts inven<strong>to</strong>ry) 2,721,147 673,283<br />
Downstream (refined petroleum product) 57,771,690 36,452,253<br />
171,071,799 127,137,360<br />
As at December 31, 2011, inven<strong>to</strong>ry had been written down <strong>to</strong> its net realizable value. The write down of $259,406 at<br />
December 31, 2011 relating <strong>to</strong> refined petroleum products is included in ‘Changes in inven<strong>to</strong>ries of finished goods and work<br />
in progress’ within <strong>the</strong> consolidated income statement. As at December 31, 2010 no net realizable value write down was<br />
necessary. At December 31, 2011, $113,300,109 (Dec 2010 - $90,685,107) of <strong>the</strong> Midstream Refining inven<strong>to</strong>ry balance<br />
secures <strong>the</strong> BNP Paribas working capital facility disclosed in note 18.<br />
94
12. Plant and equipment<br />
At January 1, 2010:<br />
Refinery<br />
Land and<br />
Buildings<br />
Plant and<br />
Equipment<br />
Mo<strong>to</strong>r Vehicles<br />
Deferred<br />
Project Costs<br />
and Work in<br />
Progress<br />
Cost 242,397,179 15,932,657 31,842,143 3,224,542 8,615,638 302,012,159<br />
Accumulated depreciation (51,718,661) (8,859,006) (20,323,035) (2,316,808) - (83,217,510)<br />
Net book value 190,678,518 7,073,651 11,519,108 907,734 8,615,638 218,794,649<br />
Year ended December 31, 2010:<br />
Opening net book value 190,678,518 7,073,651 11,519,108 907,734 8,615,638 218,794,649<br />
Additions 1,371,819 69,375 706,503 766,235 16,137,409 19,051,341<br />
Disposals - (5,678) (13,248) (28,388) - (47,314)<br />
Transfers from work in progress 2,832,316 1,780,516 3,812,781 541,703 (8,967,316) -<br />
Reclassification <strong>to</strong> o<strong>the</strong>r asset categories (3,082,278) 2,982,970 141,614 (42,306) - -<br />
Depreciation for <strong>the</strong> period (9,525,893) (947,248) (2,223,661) (446,279) - (13,143,081)<br />
Exchange differences - 157,005 313,345 (42,460) 121,942 549,832<br />
Closing net book value 182,274,482 11,110,591 14,256,442 1,656,239 15,907,673 225,205,427<br />
At December 31, 2010:<br />
Cost 243,519,036 20,042,453 36,563,947 4,046,294 15,907,673 320,079,403<br />
Accumulated depreciation (61,244,554) (8,931,862) (22,307,505) (2,390,055) - (94,873,976)<br />
Net book value 182,274,482 11,110,591 14,256,442 1,656,239 15,907,673 225,205,427<br />
Year ended December 31, 2011:<br />
Opening net book value 182,274,482 11,110,591 14,256,442 1,656,239 15,907,673 225,205,427<br />
Additions 4,624,888 4,297,395 4,614,370 1,547,508 14,467,925 29,552,086<br />
Disposals - (33,950) (395,961) (7,234) - (437,145)<br />
Transfers from work in progress 570,847 671,101 7,396,780 34,892 (8,673,620) -<br />
Reclassification <strong>to</strong> o<strong>the</strong>r asset categories - 6,493 (1,024,903) 1,018,410 - -<br />
Depreciation for <strong>the</strong> period (10,703,288) (981,574) (4,132,887) (1,064,228) - (16,881,977)<br />
Exchange differences - 1,713,531 2,918,193 650,839 3,322,994 8,605,557<br />
Closing net book value 176,766,929 16,783,587 23,632,034 3,836,426 25,024,972 246,043,948<br />
At December 31, 2011:<br />
Cost 248,714,771 28,419,395 53,076,624 8,325,671 25,024,972 363,561,433<br />
Accumulated depreciation (71,947,842) (11,635,808) (29,444,590) (4,489,245) - (117,517,485)<br />
Net book value 176,766,929 16,783,587 23,632,034 3,836,426 25,024,972 246,043,948<br />
13. Oil and gas properties<br />
Costs of oil and gas properties which are not subject <strong>to</strong> depletion are as follows:<br />
December 31, 2011<br />
$<br />
Totals<br />
December 31, 2010<br />
$<br />
Drilling and construction equipment 79,367,759 28,653,929<br />
Drilling consumables and spares 14,129,959 10,924,708<br />
Petroleum Prospecting License drilling programs (Unproved) 269,355,048 215,716,101<br />
Gross Capitalized Costs 362,852,766 255,294,738<br />
Accumulated depletion and amortization<br />
Unproved oil and gas properties - -<br />
Proved oil and gas properties - -<br />
Net Capitalized Costs 362,852,766 255,294,738<br />
The majority of <strong>the</strong> costs capitalized under ‘Petroleum Prospective License drilling programs (Unproved)’ above relates <strong>to</strong> <strong>the</strong><br />
exploration and development expenditure on <strong>the</strong> Elk and Antelope fields. The development and monetization efforts of <strong>the</strong>se<br />
fields are ongoing, and include <strong>the</strong> condensate stripping and associated facilities, <strong>the</strong> gas ga<strong>the</strong>ring and associated common<br />
facilities, and developing a liquefied natural gas plant and associated facilities in PNG.<br />
95
The majority of current year increase in <strong>the</strong> PPL drilling programs relates <strong>to</strong> <strong>the</strong> preparation and drilling activities on <strong>the</strong><br />
Tricera<strong>to</strong>ps field.<br />
The following table discloses a breakdown of <strong>the</strong> exploration costs incurred for <strong>the</strong> periods ended:<br />
Property Acquisition Costs<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Unproved - -<br />
Proved - -<br />
Total acquisition costs - -<br />
Exploration Costs - 207,054<br />
Development Costs 116,493,004 96,325,176<br />
Add: Amounts capitalized in relation <strong>to</strong> <strong>the</strong> appraisal program cash calls on IPI interest buyback<br />
transactions<br />
- 3,922,683<br />
Add: Premium paid on IPI buyback transactions - 1,550,020<br />
Less: Conveyance accounting offset against properties - (192,622)<br />
Less: Costs allocated against cash calls (8,934,976) (19,001,135)<br />
Total Costs capitalized 107,558,028 82,811,176<br />
Charged <strong>to</strong> expense<br />
Geophysical and o<strong>the</strong>r costs 18,435,150 16,981,929<br />
Total charged <strong>to</strong> expense 18,435,150 16,981,929<br />
Oil and Gas Property Additions (capitalized and expensed) 125,993,178 99,793,105<br />
14. Investments<br />
On April 11, 2011, <strong>the</strong> Company and Pacific LNG Operations Ltd. executed a framework agreement with Flex LNG Ltd<br />
related <strong>to</strong> <strong>the</strong> construction and operation of a two million <strong>to</strong>nnes per annum floating liquefied natural gas processing<br />
vessel. Under <strong>the</strong> framework agreement, an equity purchase option was issued <strong>to</strong> <strong>the</strong> Company and Pacific LNG Operations<br />
Ltd. <strong>to</strong> acquire up <strong>to</strong> 11,315,080 common shares in Flex LNG Ltd at an average strike price of 4.5909 Norwegian Kroner. On<br />
May 16, 2011, <strong>the</strong> Company and Pacific LNG Operations Ltd. exercised this option with <strong>the</strong> Company acquiring 8,938,913<br />
common shares of Flex LNG Ltd at a cost of $7,461,407 and Pacific LNG Operations Ltd acquiring <strong>the</strong> remaining 2,376,167<br />
common shares. Based on guidance under IAS 39, <strong>the</strong> Company recognized <strong>the</strong> financial asset, <strong>the</strong> Flex LNG Ltd options,<br />
on <strong>the</strong> date of grant of those options <strong>to</strong> <strong>the</strong> Company, April 11, 2011. Considering <strong>the</strong> various classification options available<br />
and managements intention <strong>to</strong> hold <strong>the</strong> options/shares after exercising for <strong>the</strong> medium term, <strong>the</strong> options were classified as a<br />
derivative financial instrument at initial recognition and <strong>the</strong>n reclassified as ‘available-for-sale’ when <strong>the</strong> options were exercised<br />
and <strong>the</strong> common shares acquired.<br />
Management used <strong>the</strong> Black Scholes pricing model <strong>to</strong> fair value <strong>the</strong> options at grant date and subsequently <strong>the</strong><br />
derivative through <strong>to</strong> <strong>the</strong> date of exercise. The option value on exercise date was $4,214,258 and <strong>the</strong> exercise price paid<br />
was $7,461,407. The cumulative fair value of <strong>the</strong> options received of $4,214,258 was recognized in <strong>the</strong> consolidated income<br />
statement under ‘Gain on Flex LNG options received’. Transaction costs of $17,350 were also incurred in relation <strong>to</strong> <strong>the</strong><br />
transaction and were allocated <strong>to</strong> <strong>the</strong> investment. Management has determined that recognition of this gain is appropriate as<br />
<strong>the</strong>re is no ongoing obligation or commitment that <strong>the</strong> Company needs <strong>to</strong> fulfill as a result of receiving <strong>the</strong>se options. The <strong>to</strong>tal<br />
amount recognized as <strong>the</strong> long term investment in relation <strong>to</strong> <strong>the</strong> Flex LNG shares in <strong>the</strong> balance sheet after <strong>the</strong> exercise of<br />
<strong>the</strong> options was $11,693,015.<br />
Based on guidance under IAS 39, changes in <strong>the</strong> fair value of <strong>the</strong> Flex LNG Ltd shares after initial recognition are <strong>to</strong> be<br />
recognized in o<strong>the</strong>r comprehensive income within shareholders equity, except for impairment losses which can be evidenced<br />
by a significant or prolonged decline in <strong>the</strong> fair value of an investment. The fair value at December 31, 2011 was $3,650,786<br />
and was calculated using quoted prices on Oslo s<strong>to</strong>ck exchange Axess. As at December 31, 2011, <strong>the</strong> decrease in <strong>the</strong> value<br />
of this investment from initial recognition was $8,042,229, with $407,565 of this amount being attributable <strong>to</strong> a reduction in<br />
<strong>the</strong> Norwegian Kroner exchange rates and $7,634,664 being attributable <strong>to</strong> a reduction in <strong>the</strong> share price of <strong>the</strong> investment.<br />
Based on <strong>the</strong> guidance on significant decline in fair value, Management has determined that <strong>the</strong> decrease in fair value<br />
attributable <strong>to</strong> <strong>the</strong> reduction in share price ($7,634,664) needs <strong>to</strong> be recognized in <strong>the</strong> consolidated income statement and <strong>the</strong><br />
decrease in fair value attributable <strong>to</strong> <strong>the</strong> reduction in exchange rates ($407,565) needs <strong>to</strong> be recognized in OCI for <strong>the</strong> year<br />
ended December 31, 2011. If <strong>the</strong> fair value of <strong>the</strong> investment increases in subsequent periods, this increase will be<br />
recognized through OCI, ra<strong>the</strong>r than through profit and loss statements in accordance with <strong>the</strong> guidance under <strong>the</strong> standards<br />
on reversal of prior impairment write offs relating <strong>to</strong> equity investments.<br />
96
15. Income taxes<br />
(a) Income tax expense<br />
The combined income tax expense in <strong>the</strong> consolidated income statements reflects an effective tax rate which differs from <strong>the</strong><br />
expected statu<strong>to</strong>ry rate (combined federal and provincial rates). Differences for <strong>the</strong> years ended were accounted for as<br />
follows:<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Profit/(loss) before income taxes and non controlling interest 16,922,995 (38,103,348)<br />
Statu<strong>to</strong>ry income tax rate 31.50% 33.00%<br />
Computed tax expense/(benefit) 5,330,743 (12,574,105)<br />
Effect on income tax of:<br />
Income/(losses) in foreign jurisdictions not assessable/(deductible) 3,236,314 2,073,636<br />
Non-deductible s<strong>to</strong>ck compensation expense 897,703 317,671<br />
Non-deductible pre-LNG Project Agreement costs 983,644 1,146,936<br />
Non-deductible premium paid on buyback of IPI interest - 10,087,674<br />
Non-taxable gain on sale of exploration assets - (706,458)<br />
Effect of currency translation on tax base (3,236,709) 202,029<br />
Tax rate differential in foreign jurisdictions (556,744) (726,664)<br />
Over provision for income tax in prior years 588,333 1,501,234<br />
Midstream - Refining tax exempt income as per Refinery Project Agreement - (8,423,607)<br />
Tax losses for which no future tax benefit has been brought <strong>to</strong> account 8,718,157 16,299,899<br />
Initial recognition of future tax assets/liabilities based on recoverability assessment (15,498,147) (973,368)<br />
O<strong>the</strong>r - net (1,198,961) (1,815,154)<br />
(b) Deferred income tax<br />
December 31, 2011<br />
$<br />
(735,667) 6,409,723<br />
December 31, 2010<br />
$<br />
Deferred tax assets 35,965,273 28,477,690<br />
Deferred tax liabilities (1,889,391) -<br />
Deferred tax assets (net) 34,075,882 28,477,690<br />
The gross movement on <strong>the</strong> deferred income tax account is as follows:<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
At January 1 28,477,690 30,319,163<br />
Charge <strong>to</strong> <strong>the</strong> income statement 6,248,509 (2,511,656)<br />
Exchange differences (650,317) 670,183<br />
At December 31 34,075,882 28,477,690<br />
The movement in deferred income tax assets and liabilities during <strong>the</strong> year, without taking in<strong>to</strong> consideration <strong>the</strong> offsetting of<br />
balances within <strong>the</strong> same tax jurisdiction, is as follows:<br />
Deferred tax assets and liabilities Tax losses O<strong>the</strong>r Tax depreciation<br />
Unrealized foreign<br />
exchange gains<br />
At January 1, 2010 23,800,726 2,620,198 5,535,521 (1,637,282) 30,319,163<br />
Charge <strong>to</strong> <strong>the</strong> income statement (21,663) (1,244,491) (1,168,649) (76,853) (2,511,656)<br />
Exchange differences 547,561 181,093 (216,347) 157,876 670,183<br />
At December 31, 2010 24,326,624 1,556,800 4,150,525 (1,556,259) 28,477,690<br />
Charge <strong>to</strong> <strong>the</strong> income statement (3,691,894) 389,142 14,252,367 (4,701,106) 6,248,509<br />
Exchange differences 4,136,543 262,241 (2,723,692) (2,325,408) (650,316)<br />
At December 31, 2011 24,771,273 2,208,183 15,679,200 (8,582,774) 34,075,882<br />
Total<br />
97
The deferred tax assets recorded in <strong>the</strong> consolidated balance sheet mainly relate <strong>to</strong> Midstream – Refining assets in PNG while<br />
<strong>the</strong> deferred tax liabilities relate <strong>to</strong> Downstream assets in PNG. The amounts are non-current as at December 31, 2011.<br />
In addition <strong>to</strong> <strong>the</strong> above, <strong>the</strong> Company has temporary differences and losses carried forward in relation <strong>to</strong> exploration<br />
expenditure incurred in PNG of $221,468,770 at December 31, 2011. No deferred tax assets have been recognized for <strong>the</strong><br />
exploration expenditure pending final investment decision on projects for monetization of resources from <strong>the</strong> licenses held.<br />
The ultimate realization of deferred tax assets is dependent upon <strong>the</strong> generation of future taxable income during <strong>the</strong> periods<br />
in which those temporary differences become deductible. Management considers <strong>the</strong> actual levels of past taxable income,<br />
scheduled reversal of deferred tax liabilities, projected future taxable income, projected tax rates and tax planning strategies<br />
in making this assessment. Management has determined that 100% of <strong>the</strong> deferred tax assets required in relation <strong>to</strong> <strong>the</strong> net<br />
operating loss carry-forwards of <strong>the</strong> Midstream – Refining segment should be recognized during <strong>the</strong> year ended 2010. This<br />
was based on <strong>the</strong> refinery generating consistent profits, and <strong>the</strong> view that any carry forward tax losses will be recouped in <strong>the</strong><br />
coming years.<br />
The Refinery Project Agreement gave “pioneer” status <strong>to</strong> <strong>InterOil</strong> Limited (”IOL”). This status gave IOL a tax holiday beginning<br />
upon <strong>the</strong> date of <strong>the</strong> commencement of commercial production, January 1, 2005 and ended December 31, 2010. In relation<br />
<strong>to</strong> <strong>the</strong> refinery, tax losses incurred prior <strong>to</strong> January 1, 2005 were frozen during <strong>the</strong> tax holiday and became available for use<br />
after <strong>the</strong> tax holiday ceased on December 31, 2010. Tax losses incurred during <strong>the</strong> tax holiday also became available for use<br />
after December 31, 2010. Tax losses carried forward <strong>to</strong> offset against future earnings <strong>to</strong>tal PGK 176,872,859 ($82,512,063)<br />
at December 31, 2011. All losses incurred by <strong>InterOil</strong> Limited have a twenty year carry forward period.<br />
16. Trades and o<strong>the</strong>r payables<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Trade payables - crude import 69,042,031 -<br />
Trade payables - product import 10,470,860 5,241,216<br />
O<strong>the</strong>r accounts payable and accrued liabilities 53,541,263 47,999,907<br />
Petromin cash calls received 15,435,000 15,435,000<br />
Mitsui cash calls received 11,393,023 6,456,757<br />
Total trade and o<strong>the</strong>r payables 159,882,177 75,132,880<br />
(a) Petromin participation in Elk and Antelope fields<br />
On Oc<strong>to</strong>ber 30, 2008, Petromin PNG Holdings Limited (”Petromin”), a government entity mandated <strong>to</strong> invest in resource<br />
projects on behalf of <strong>the</strong> State, entered in<strong>to</strong> an agreement <strong>to</strong> take a 20.5% direct interest in <strong>the</strong> Elk and Antelope fields if and<br />
once nominated by <strong>the</strong> State <strong>to</strong> take its legislative interest. Petromin contributed an initial deposit and agreed <strong>to</strong> conditionally<br />
fund 20.5% of <strong>the</strong> costs of developing <strong>the</strong>se fields. The State’s (and Petromin’s) right <strong>to</strong> take an interest arises upon issuance<br />
of <strong>the</strong> Prospecting Development License (”PDL”), which has not yet occurred. The obligation <strong>to</strong> fund its portion of <strong>the</strong> costs of<br />
developing <strong>the</strong> field, including sunk costs, also applies upon issuance of <strong>the</strong> PDL. As at December 31, 2011, $15,435,000 in<br />
advance payments received from Petromin has been held under ‘Petromin cash calls received’ above. At <strong>the</strong> end of <strong>the</strong> 2011<br />
year, <strong>the</strong> parties agreed that <strong>the</strong> Agreement’s intended operation had ended, and that it should terminate. Petromin remains<br />
<strong>the</strong> State’s nominee <strong>to</strong> acquire <strong>the</strong> State’s interest under relevant Papua New Guinean legislation, once a PDL is granted.<br />
<strong>InterOil</strong> has proposed that cash contributions made by Petromin <strong>to</strong> date <strong>to</strong> fund <strong>the</strong> development will be held and credited<br />
against <strong>the</strong> State’s obligation <strong>to</strong> contribute its portion of sunk costs upon grant of <strong>the</strong> PDL.<br />
(b) Mitsui & Co. participation in Condensate Stripping Plant<br />
On April 15, 2010, <strong>the</strong> Company entered in<strong>to</strong> a preliminary works joint venture and preliminary works financing agreement<br />
with Mitsui relating <strong>to</strong> <strong>the</strong> CS Project. The proposed joint venture is <strong>to</strong> be entered in<strong>to</strong> for equal shares between Mitsui and<br />
<strong>InterOil</strong>. Mitsui will be responsible for arranging or providing financing for <strong>the</strong> capital costs of <strong>the</strong> plant. On August 4, 2010, <strong>the</strong><br />
JVOA for <strong>the</strong> CS Project was finalized. Refer <strong>to</strong> note 20 for fur<strong>the</strong>r details in relation <strong>to</strong> this agreement.<br />
The portion of funding that relates <strong>to</strong> Mitsui’s share of <strong>the</strong> project as at December 31, 2011, amounting <strong>to</strong> $11,393,023 is<br />
held in current liabilities as <strong>the</strong> agreement requires repayment if FID is not reached. The portion of funding that relates <strong>to</strong><br />
<strong>InterOil</strong>’s share of <strong>the</strong> project, funded by Mitsui, is classified as an unsecured loan (refer <strong>to</strong> note 20).<br />
17. Goodwill<br />
(a) Acquisition of interest from Merrill Lynch<br />
On February 27, 2009, <strong>InterOil</strong> LNG Holdings Inc. acquired half of Merrill Lynch’s interest in <strong>the</strong> LNG Joint Venture Company<br />
98
for $11,250,000. As part of <strong>the</strong> acquisition, <strong>InterOil</strong> LNG Holdings Inc. was transferred 548,806 ‘B’ Class shares held by<br />
Merrill Lynch. The amount recognized as goodwill of $5,761,940 represents <strong>the</strong> amount of purchase consideration paid <strong>to</strong><br />
Merrill Lynch over and above <strong>the</strong> fair value of <strong>the</strong> identifiable net assets acquired.<br />
(b) Acquisition of interest from Pacific LNG<br />
During September 2009, <strong>InterOil</strong> also acquired a fur<strong>the</strong>r 2.5% of Pacific LNG’s economic interest in <strong>the</strong> joint venture LNG<br />
Project from Pacific LNG as part of <strong>the</strong> Elk and Antelope interest acquisition. The fair value of 2.5% of Pacific LNG’s<br />
economic interest in <strong>the</strong> joint venture LNG Project was valued at $864,377 based on <strong>the</strong> previous transaction with Merrill<br />
Lynch that was <strong>complete</strong>d in February 2009, being <strong>the</strong> most appropriate guide <strong>to</strong> <strong>the</strong> fair value of <strong>the</strong> interest acquired. This<br />
fair value has been recognized as goodwill on acquisition of <strong>the</strong> LNG interest in <strong>the</strong> Balance Sheet.<br />
(c) Impairment tests for goodwill<br />
Management reviews <strong>the</strong> business performance based on operating segments and goodwill is moni<strong>to</strong>red by <strong>the</strong> management<br />
at <strong>the</strong> operating segment level. The goodwill recognized at December 31, 2011 is allocated <strong>to</strong> <strong>the</strong> Midstream – Liquefaction<br />
segment.<br />
The recoverable amount of <strong>the</strong> Midstream – Liquefaction segment has been determined based on fair value less costs <strong>to</strong> sell<br />
calculations. These calculations use cash flow projections covering a twenty-year period and <strong>the</strong> key assumptions used in <strong>the</strong><br />
calculations include an oil price of $90/bbl and an annual inflation rate of 2%.<br />
18. Working capital facilities<br />
Amounts drawn down<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
BNP Paribas working capital facility - midstream 10,030,131 50,023,559<br />
Westpac working capital facility - downstream 6,450,372 1,230,767<br />
Total working capital facility 16,480,503 51,254,326<br />
(a) BNP Paribas working capital facility<br />
<strong>InterOil</strong> has a syndicated working capital credit facility led by BNP Paribas (Singapore branch) with a maximum availability of<br />
$230,000,000 (increased temporarily <strong>to</strong> $260,000,000 in November 2011, and reverting back <strong>to</strong> $230,000,000 on<br />
January 31, 2012). The <strong>to</strong>tal facility is split in<strong>to</strong> Facility 1 and Facility 2 as per <strong>the</strong> agreement with BNP Paribas. Facility 1<br />
is for $170,000,000 (increased temporarily <strong>to</strong> $200,000,000) and finances purchases of hydrocarbons via <strong>the</strong> issuance of<br />
documentary letters of credit and or standby letters of credit, short term advances, advances on merchandise, freight loans,<br />
and includes a sublimit of Euro 18,000,000 or USD equivalent for hedging transactions via BNP Paribas Commodity Indexed<br />
Transaction Group or o<strong>the</strong>r acceptable counter parties.<br />
Facility 2 is for $60,000,000 partly cash-secured short term advances and for discounting of any monetary receivables<br />
acceptable <strong>to</strong> BNP Paribas in order <strong>to</strong> reduce Facility 1 balances. The facility is secured by sales contracts, purchase<br />
contracts, certain cash accounts associated with <strong>the</strong> refinery, all crude and refined products of <strong>the</strong> refinery and trade<br />
receivables.<br />
The <strong>to</strong>tal facility is renewable annually and during <strong>the</strong> prior year renewal process, <strong>the</strong> facility was renewed until January<br />
31, 2012 with an increase in Facility 1 limit by an additional $30,000,000 <strong>to</strong> $160,000,000, and a maximum availability of<br />
$220,000,000 for <strong>the</strong> combined facility. In June 2011, <strong>the</strong>re was an additional increase in Facility 1 limit by $10,000,000 <strong>to</strong><br />
$170,000,000, and a maximum availability of $230,000,000 for <strong>the</strong> combined facility. In November 2011, <strong>the</strong> limit of Facility<br />
1 was fur<strong>the</strong>r increased temporarily by $30,000,000 <strong>to</strong> $200,000,000, and a maximum availability of $260,000,000 for <strong>the</strong><br />
combined facility. The combined facility reverted back <strong>to</strong> a maximum availability of $230,000,000 at <strong>the</strong> end of January 2012.<br />
As part of <strong>the</strong> current year renewal process, <strong>the</strong> facility was renewed in February 2012 with an increase in Facility 1 limit by an<br />
additional $10,000,000 <strong>to</strong> $180,000,000, and a maximum availability of $240,000,000 for <strong>the</strong> combined facility until January<br />
31, 2013.<br />
The facility bears interest at LIBOR + 3.5% on <strong>the</strong> short term advances. During <strong>the</strong> year <strong>the</strong> weighted average interest rate<br />
was 2.96% (2010 – 2.69%) after considering <strong>the</strong> reduction in interest due <strong>to</strong> <strong>the</strong> deposit amounts maintained which reduces<br />
<strong>the</strong> interest being charged on <strong>the</strong> facility utilization (refer section ‘Cash and cash equivalents’ under note 9).<br />
The following table outlines <strong>the</strong> facility and <strong>the</strong> amount available for use at year end:<br />
99
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Working capital credit facility 260,000,000 190,000,000<br />
Less amounts included in <strong>the</strong> working capital facility liability:<br />
Short term advances/facilities drawn down - (50,023,559)<br />
Discounted receivables (10,030,131) -<br />
Less: o<strong>the</strong>r amounts outstanding under <strong>the</strong> facility:<br />
(10,030,131) (50,023,559)<br />
Letters of credit outstanding (164,910,000) (93,710,000)<br />
Working capital credit facility available for use 85,059,869 46,266,441<br />
At December 31, 2011, <strong>the</strong> company had six letters of credit outstanding <strong>to</strong>taling $164,910,000. The first letter of credit for<br />
$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<br />
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<br />
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<br />
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<br />
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,<br />
2012.<br />
The cash deposit on working capital facility, as separately disclosed in note 9, included restricted cash of $32,982,001 (2010<br />
- $40,664,995) which is being maintained as a security margin for <strong>the</strong> facility. In addition, inven<strong>to</strong>ry of $113,300,109 (2010<br />
- $90,685,107) and trade receivables of $74,265,832 (2010 – $26,884,664) also secured <strong>the</strong> facility. The trade receivable<br />
balance securing <strong>the</strong> facility includes $53,815,857 (2010 - $21,797,631) of inter-company receivables which were eliminated<br />
on consolidation.<br />
(b) Westpac and Bank South Pacific working capital facility<br />
The Company has an approximately $60,645,000 (PGK 130,000,000) revolving working capital facility for its Downstream<br />
operations in PNG from BSP and Westpac. Westpac facility limit is approximately $37,320,000 (PGK 80,000,000) and <strong>the</strong><br />
initial BSP facility limit is approximately $23,325,000 (PGK 50,000,000). The Westpac facility is for an initial term of three years<br />
and was renewed in November 2011 through <strong>to</strong> November 2014. The Westpac facility was fur<strong>the</strong>r increased, subsequent <strong>to</strong><br />
year end in February 2012, by $4,665,000 (PGK 10,000,000) bringing <strong>the</strong> Westpac facility <strong>to</strong> $41,985,000 (PGK 90,000,000)<br />
and <strong>the</strong> combined facility <strong>to</strong> $65,310,000 (PGK 140,000,000). In addition, a secured loan of $15,000,000 was provided as<br />
part of this increased facility which is repayable in equal installments over 3.5 years with an interest rate of LIBOR + 4.4% per<br />
annum. The BSP facility is renewable annually and was renewed in August 2011 through <strong>to</strong> August 2012. As at December<br />
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<br />
this facility remains available for use. During <strong>the</strong> year <strong>the</strong> weighted average interest rate was 9.6%. These facilities are secured<br />
by a fixed and floating charge over <strong>the</strong> assets of Downstream operations.<br />
19. Related parties<br />
(a) Petroleum Independent and Exploration <strong>Corporation</strong> (“P.I.E”)<br />
P.I.E is controlled by Phil Mulacek, an officer and direc<strong>to</strong>r of <strong>InterOil</strong> and acted as a sponsor of <strong>the</strong> Company’s oil refinery<br />
project until late June 2011. Articles of association of SPI <strong>InterOil</strong> LDC (“SPI”) provide for <strong>the</strong> business and affairs of <strong>the</strong> entity<br />
<strong>to</strong> be managed by a general manager appointed by <strong>the</strong> shareholders of SPI. SPI does not have a Board of Direc<strong>to</strong>rs, instead<br />
P.I.E has been appointed as <strong>the</strong> general manager of SPI. Under <strong>the</strong> laws of <strong>the</strong> Commonwealth of The Bahamas, <strong>the</strong> general<br />
manager exercises all powers which would typically be exercised by a Board of Direc<strong>to</strong>rs, being those which are not required<br />
by laws or by SPI’s constituting documents <strong>to</strong> be exercised by <strong>the</strong> members (shareholders) of SPI. <strong>InterOil</strong> is <strong>the</strong> majority<br />
shareholder of SPI and <strong>the</strong>refore has <strong>the</strong> power <strong>to</strong> appoint <strong>the</strong> general manager.<br />
During <strong>the</strong> year ended December 31, 2011, $nil (Dec 2010 - $150,000) was expensed for <strong>the</strong> sponsor’s management fees in<br />
relation <strong>to</strong> legal, accounting and <strong>report</strong>ing costs. Of <strong>the</strong>se costs, $nil (Dec 2010 - $112,500) were included in accrued<br />
liabilities at December 31, 2011.<br />
In November of 2011, <strong>the</strong> Company elected <strong>to</strong> exchange <strong>the</strong> 5,000 shares held in SP <strong>InterOil</strong> LDC by PIE for 5,000 shares in<br />
<strong>InterOil</strong> <strong>Corporation</strong>. The sponsor agreements were terminated with PIE on exchange of <strong>the</strong> share holding interest in SPI LDC.<br />
Subsequent <strong>to</strong> year end, SPI LDC has been renamed South Pacific Refining Limited.<br />
100
(b) Breckland Limited<br />
This entity is controlled by Roger Grundy, a direc<strong>to</strong>r of <strong>InterOil</strong>, and provides technical and advisory services <strong>to</strong> <strong>the</strong> Company<br />
on normal commercial terms. Amounts paid or payable <strong>to</strong> Breckland for technical services during <strong>the</strong> year amounted <strong>to</strong> $nil<br />
(Dec 2010 - $21,923).<br />
(c) Key management compensation<br />
Key management includes direc<strong>to</strong>rs (executive and non-executive) and executive officers. The compensation paid or payable<br />
<strong>to</strong> key management for services is shown below:<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Salaries and o<strong>the</strong>r short-term employee benefits 3,985,427 2,653,219<br />
Post-employment benefits 94,732 83,277<br />
Share-based payments 9,341,730 6,328,176<br />
Total 13,421,889 9,064,672<br />
(d) Joint ventures<br />
The Company’s interests in PNG LNG Inc. is governed by a Shareholders’ Agreement signed on July 30, 2007 between <strong>the</strong><br />
Joint Ventures’. Guidance under IAS 31 – ‘Interest in Joint Ventures’ is followed and <strong>the</strong> entity has been proportionately<br />
consolidated in <strong>InterOil</strong>’s consolidated financial statements. The consolidated results of <strong>InterOil</strong>’s proportionate shareholding in<br />
<strong>the</strong> LNG Project has been disclosed separately within <strong>the</strong> segment notes under Midstream - Liquefaction, refer <strong>to</strong> note 5.<br />
20. Secured and unsecured loans<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Secured loan (OPIC) - current portion 9,000,000 9,000,000<br />
Unsecured loan (Mitsui) 10,393,023 5,456,757<br />
Total current portion of loans 19,393,023 14,456,757<br />
Secured loan (OPIC) - non current portion 26,500,000 35,500,000<br />
Secured loan (OPIC) - deferred financing costs (462,834) (686,778)<br />
Total non current secured loan 26,037,166 34,813,222<br />
Total secured and unsecured loans 45,430,189 49,269,979<br />
(a) OPIC Secured Loan<br />
On June 12, 2001, <strong>the</strong> Company entered in<strong>to</strong> a loan agreement with OPIC <strong>to</strong> secure a project financing facility of<br />
$85,000,000. The loan agreement stipulates half yearly principal payments of $4,500,000, due in June and December of<br />
each year, with <strong>the</strong> final repayment <strong>to</strong> be made in December 31, 2015. On June 20, 2011, <strong>the</strong> loan agreement was amended<br />
<strong>to</strong> release certain sponsor support collateral related <strong>to</strong> <strong>the</strong> loan agreement and <strong>to</strong> terminate various o<strong>the</strong>r sponsor support<br />
arrangements. OPIC released <strong>the</strong> common s<strong>to</strong>ck which was pledged by PIE Group LLC, and a parent guarantee originally<br />
provided by <strong>InterOil</strong> <strong>Corporation</strong> in 2001 will continue for <strong>the</strong> remaining life of <strong>the</strong> loan. The loan is secured over <strong>the</strong> assets of<br />
<strong>the</strong> refinery project which had a carrying value of $200,632,040 at December 31, 2011 (2010 - $196,024,838).<br />
The interest rate on <strong>the</strong> loan is equal <strong>to</strong> <strong>the</strong> treasury cost applicable <strong>to</strong> each promissory note (at <strong>the</strong> date of draw down)<br />
outstanding plus <strong>the</strong> OPIC spread (3.00%). During 2011 <strong>the</strong> weighted average interest rate was 6.93% (2010 – 6.80%) and<br />
<strong>the</strong> <strong>to</strong>tal interest expense included in long term borrowing costs was $2,901,250 (2010 - $3,461,800).<br />
As at December 31, 2011, two installment payments amounting <strong>to</strong> $4,500,000 each which will be due for payment on June<br />
30, 2012 and December 31, 2012 have been classified in<strong>to</strong> <strong>the</strong> current portion of <strong>the</strong> liability. The agreement contains certain<br />
financial covenants which include <strong>the</strong> maintenance of minimum levels of tangible net worth and limitations on <strong>the</strong> incurrence<br />
of additional indebtedness for <strong>the</strong> refining operations. A deposit is also required <strong>to</strong> be maintained <strong>to</strong> cover <strong>the</strong> next<br />
installment and interest payment. As of December 31, 2011, <strong>the</strong> company was in compliance with all applicable covenants.<br />
Deferred financing costs relating <strong>to</strong> <strong>the</strong> OPIC loan of $462,834 (2010 - $686,778) are being amortized over <strong>the</strong> period until<br />
December 2014 and has been offset against <strong>the</strong> long term liability and are being amortized using <strong>the</strong> effective interest<br />
method.<br />
Bank covenants under <strong>the</strong> above facility currently restrict <strong>the</strong> payment of dividends by <strong>the</strong> Company’s subsidiaries E.P. <strong>InterOil</strong><br />
Limited and <strong>InterOil</strong> Limited.<br />
101
(b) Mitsui Unsecured Loan<br />
On April 15, 2010, <strong>the</strong> Company entered in<strong>to</strong> preliminary joint venture and financing agreements with Mitsui relating <strong>to</strong> <strong>the</strong><br />
CS Project. The proposed joint venture is <strong>to</strong> be entered in<strong>to</strong> for equal shares between Mitsui and <strong>InterOil</strong>. On August 4, 2010,<br />
<strong>the</strong> JVOA for <strong>the</strong> CS Project was finalized. The amount financed by Mitsui for <strong>InterOil</strong>’s proportion of cash calls is treated as<br />
an unsecured loan with interest being accrued daily at LIBOR plus a margin of 6.00%. The portion of funding that relates <strong>to</strong><br />
Mitsui’s share of <strong>the</strong> project is held in current liabilities. In <strong>the</strong> event that a positive FID is not reached or made, <strong>InterOil</strong> will be<br />
required <strong>to</strong> refund Mitsui’s share of capital expenditure incurred and <strong>the</strong> unsecured loan within a specified period.<br />
21. Indirect participation interests<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Indirect participation interest (PNGDV) - current portion 540,002 540,002<br />
Total current indirect participation interest 540,002 540,002<br />
Indirect participation interest (PNGDV) - non current portion 844,490 844,490<br />
Indirect participation interest ("IPI") 33,290,350 33,289,897<br />
Total non current indirect participation interest 34,134,840 34,134,387<br />
Total indirect participation interest 34,674,842 34,674,389<br />
(a) Indirect participation interest (“IPI”)<br />
The IPI balance relates <strong>to</strong> $125,000,000 received by <strong>InterOil</strong> subject <strong>to</strong> <strong>the</strong> terms of <strong>the</strong> agreement dated February 25, 2005<br />
between <strong>the</strong> Company and a number of inves<strong>to</strong>rs. In exchange <strong>InterOil</strong> had provided <strong>the</strong> inves<strong>to</strong>rs with a 25% interest in an<br />
eight well drilling program <strong>to</strong> be conducted in <strong>InterOil</strong>’s PPL 236, 237 and 238.<br />
Under <strong>the</strong> IPI agreement, <strong>InterOil</strong> is responsible for drilling eight exploration wells, four of which will be in PPL 238, one in PPL<br />
236, and one in PPL 237. The location of <strong>the</strong> o<strong>the</strong>r two wells is yet <strong>to</strong> be determined. The inves<strong>to</strong>rs will be able <strong>to</strong> approve<br />
<strong>the</strong> location of <strong>the</strong> final two wells <strong>to</strong> be drilled. In <strong>the</strong> instance that <strong>InterOil</strong> proposes appraisal or completion of an exploration<br />
or development well, <strong>the</strong> inves<strong>to</strong>rs will be asked <strong>to</strong> contribute <strong>to</strong> <strong>the</strong> completion work in proportion <strong>to</strong> <strong>the</strong>ir IPI percentage and<br />
<strong>InterOil</strong> will bear <strong>the</strong> remaining cost.<br />
<strong>InterOil</strong> has made cash calls for <strong>the</strong> completion, appraisal and development programs performed on <strong>the</strong> exploration or<br />
development wells that form part of <strong>the</strong> IPI Agreement. These cash calls are shown as a liability when received and reduced<br />
as amounts are spent on <strong>the</strong> extended well programs. Should an inves<strong>to</strong>r choose not <strong>to</strong> participate in <strong>the</strong> completion works<br />
of an exploration well, <strong>the</strong> inves<strong>to</strong>r will forfeit certain rights <strong>to</strong> <strong>the</strong> well in question as well as <strong>the</strong>ir right <strong>to</strong> convert in<strong>to</strong> common<br />
shares. <strong>InterOil</strong> has drilled four exploration wells under <strong>the</strong> IPI agreement as at December 31, 2011.<br />
The funds of $125,000,000 were partly accounted for as a non-financial liability and partly as a conversion option. The<br />
non-financial liability was initially valued at $105,000,000, being <strong>the</strong> estimated expenditures <strong>to</strong> <strong>complete</strong> <strong>the</strong> eight well drilling<br />
program, and <strong>the</strong> residual value of $20,000,000 has been allocated <strong>to</strong> <strong>the</strong> conversion option presented under Shareholder’s<br />
equity. <strong>InterOil</strong> paid financing fees and transaction costs of $8,138,741 related <strong>to</strong> <strong>the</strong> indirect participation interest on behalf of<br />
<strong>the</strong> indirect participation interest inves<strong>to</strong>rs in 2005. These fees have been allocated against <strong>the</strong> non-financial liability,<br />
reducing <strong>the</strong> liability <strong>to</strong> $96,861,259. <strong>InterOil</strong> will maintain <strong>the</strong> liability at its initial value until conveyance is triggered on <strong>the</strong><br />
lapse of <strong>the</strong> conversion option available <strong>to</strong> <strong>the</strong> inves<strong>to</strong>rs, or <strong>the</strong>y elect <strong>to</strong> participate in <strong>the</strong> PDL for a successful well. <strong>InterOil</strong><br />
will account for <strong>the</strong> exploration costs relating <strong>to</strong> <strong>the</strong> eight well program under <strong>the</strong> successful efforts accounting policy adopted<br />
by <strong>the</strong> Company. All geological and geophysical costs relating <strong>to</strong> <strong>the</strong> exploration program will be expensed as incurred and all<br />
drilling costs will be capitalized and assessed for recovery at each period.<br />
When an inves<strong>to</strong>r elects <strong>to</strong> participate in a PDL or when <strong>the</strong> inves<strong>to</strong>r forfeits <strong>the</strong> conversion option, conveyance accounting<br />
will be applied. This entails determination of proceeds for <strong>the</strong> interests conveyed and <strong>the</strong> cost of that interest as represented<br />
in <strong>the</strong> ‘Oil and gas properties’ in <strong>the</strong> balance sheet. The difference between proceeds on conveyance and capitalized costs <strong>to</strong><br />
<strong>the</strong> interests conveyed will be recognized as gain or loss in <strong>the</strong> income statement.<br />
Under <strong>the</strong> agreement, all or part of <strong>the</strong> 25% initial indirect participation interest could have been converted <strong>to</strong> a maximum of<br />
3,333,334 common shares in <strong>the</strong> company, at a price of $37.50 per share, between June 15, 2006 and <strong>the</strong> later of<br />
December 15, 2006, or 90 days after <strong>the</strong> completion of <strong>the</strong> eighth well. Any partial conversion of an indirect participation<br />
interest in<strong>to</strong> common shares will result in a corresponding decrease in <strong>the</strong> inves<strong>to</strong>rs’ interest in <strong>the</strong> eight well drilling program.<br />
As at December 31, 2011, <strong>the</strong> balance of <strong>the</strong> indirect participation interest that may be converted in<strong>to</strong> shares is a maximum<br />
of 340,480 common shares (Dec 2010 – 340,480). Should <strong>the</strong> option <strong>to</strong> convert <strong>to</strong> shares not be exercised, <strong>the</strong> indirect<br />
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participation interest in <strong>the</strong> eight well drilling program will be maintained and distributions from success in <strong>the</strong>se wells will be<br />
paid in accordance with <strong>the</strong> agreement. From <strong>the</strong> date of <strong>the</strong> agreement up <strong>to</strong> December 31, 2011, <strong>the</strong> following transactions<br />
have occurred:<br />
(i) Increase in <strong>InterOil</strong>’s direct interest in <strong>the</strong> IPI program by 9.8614% due <strong>to</strong> <strong>the</strong> following:<br />
• Conversion of IPI interests: Certain IPI inves<strong>to</strong>rs representing a 3.575% interest in <strong>the</strong> IPI agreement have exercised<br />
<strong>the</strong>ir right <strong>to</strong> convert <strong>the</strong>ir interest in<strong>to</strong> common shares resulting in issuance of 476,667 <strong>InterOil</strong> common shares.<br />
These conversions reduced <strong>the</strong> initial IPI liability balance by $13,851,160 and <strong>the</strong> initial conversion option balance by<br />
$2,860,000.<br />
• Buyback of IPI interests by <strong>the</strong> Company: Certain IPI inves<strong>to</strong>rs representing a 6.2864% interest in <strong>the</strong> IPI agreement<br />
have sold <strong>the</strong>ir interest <strong>to</strong> <strong>the</strong> Company. Detailed disclosure of this transaction is provided in <strong>the</strong> section<br />
‘Extinguishment of IPI liability’ below.<br />
On April 15, 2010 one IPI inves<strong>to</strong>r representing 0.4% interest in <strong>the</strong> IPI agreement waived <strong>the</strong> conversion right <strong>to</strong><br />
convert <strong>the</strong>ir IPI percentage in<strong>to</strong> 53,333 shares. On July 19, 2010, <strong>the</strong> Company bought back this 0.4% interest in <strong>the</strong><br />
IPI Agreement from <strong>the</strong> inves<strong>to</strong>r for 208,281 common shares of <strong>the</strong> Company. The Company has not applied<br />
conveyance accounting on this portion of <strong>the</strong> IPI agreement, but has accounted for <strong>the</strong> buyback under <strong>the</strong><br />
‘Extinguishment of IPI liability’ model in <strong>the</strong> quarter ended September 30, 2010.<br />
As at December 31, 2011, <strong>InterOil</strong>’s direct interest in exploration licenses is 75.6114%, assuming that all remaining indirect<br />
participation interest inves<strong>to</strong>rs take up <strong>the</strong>ir working interest rights in such licenses, and excluding <strong>the</strong> 20.5% interest that <strong>the</strong><br />
State is able <strong>to</strong> take up under relevant legislation.<br />
(ii) Waiver of conversion rights resulting in conveyance accounting<br />
• Certain IPI inves<strong>to</strong>rs representing a 12.585% interest in <strong>the</strong> IPI agreement have waived <strong>the</strong>ir right <strong>to</strong> convert <strong>the</strong>ir IPI<br />
percentage in<strong>to</strong> 1,678,000 common shares. As a result, conveyance was triggered on this portion of <strong>the</strong> IPI<br />
agreement, which reduced <strong>the</strong> IPI liability by $25,363,405.<br />
• During December 2010, <strong>the</strong> Company bought a combined 1.05% interest in <strong>the</strong> IPI Agreement from two inves<strong>to</strong>rs, out<br />
of which 0.05% related <strong>to</strong> interests that had already been waived by <strong>the</strong> inves<strong>to</strong>r in <strong>the</strong> prior year, hence conveyance<br />
accounting was followed for this interest and any premium paid was capitalized <strong>to</strong> Oil and Gas properties. This 0.05%<br />
was bought for $1,881,959 which was settled through <strong>the</strong> issue of 25,805 <strong>InterOil</strong> common shares. The excess of this<br />
consideration over <strong>the</strong> book value of <strong>the</strong> IPI liability and <strong>the</strong> appraisal costs previously cash called from this inves<strong>to</strong>r<br />
was $1,550,020 and has been capitalized <strong>to</strong> Oil and Gas properties.<br />
• As at December 31, 2011, IPI inves<strong>to</strong>rs with a combined 2.5536% interest in <strong>the</strong> IPI agreement still have <strong>the</strong><br />
conversion rights outstanding resulting in a maximum of 340,480 common shares being issued if all <strong>the</strong>se IPI inves<strong>to</strong>rs<br />
choose <strong>to</strong> exercise <strong>the</strong>ir conversion options.<br />
(iii) Extinguishment of IPI liability<br />
During September 2009, <strong>the</strong> Company bought a combined 4.3364% interest in <strong>the</strong> IPI Agreement from two inves<strong>to</strong>rs for<br />
$56,479,615 which was settled in two tranches of <strong>InterOil</strong> common shares. The first tranche of common shares was for 35%<br />
of <strong>the</strong> <strong>to</strong>tal consideration and was issued on September 15, 2009. The second tranche of shares for <strong>the</strong> remaining 65% of<br />
<strong>the</strong> <strong>to</strong>tal consideration was issued on December 15, 2009 based on a ten day VWAP immediately prior <strong>to</strong> <strong>the</strong> date of issue.<br />
As part of this transaction a <strong>to</strong>tal number of 1,236,666 shares were issued.<br />
During December 2009, <strong>the</strong> Company bought a fur<strong>the</strong>r combined 0.5% interest in <strong>the</strong> IPI Agreement from two inves<strong>to</strong>rs for<br />
$6,500,546 which was settled in two tranches of <strong>InterOil</strong> common shares. The first tranche of common shares was for 35%<br />
of <strong>the</strong> <strong>to</strong>tal consideration and was issued on December 1, 2009. The second tranche of shares for <strong>the</strong> remaining 65% of <strong>the</strong><br />
<strong>to</strong>tal consideration was issued on December 15, 2009 based on a ten day VWAP immediately prior <strong>to</strong> <strong>the</strong> date of issue. As<br />
part of this transaction a <strong>to</strong>tal number of 108,044 shares were issued.<br />
During July 2010, <strong>the</strong> Company bought a fur<strong>the</strong>r 0.4% interest in <strong>the</strong> IPI Agreement from an inves<strong>to</strong>r for $10,830,612 which<br />
was settled in <strong>InterOil</strong> common shares. As part of this transaction a <strong>to</strong>tal number of 208,281 shares were issued.<br />
During December 2010, <strong>the</strong> Company bought a fur<strong>the</strong>r 1.0% interest in <strong>the</strong> IPI Agreement from one inves<strong>to</strong>r for $37,974,797<br />
which was settled in <strong>InterOil</strong> common shares. As part of this transaction a <strong>to</strong>tal number of 520,702 shares were issued.<br />
Management has adopted <strong>the</strong> extinguishment liability model. Under this model <strong>the</strong> consideration paid is allocated <strong>to</strong> <strong>the</strong><br />
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various components involved in <strong>the</strong> exchange transactions. These components include:<br />
• cash calls made from <strong>the</strong> IPI inves<strong>to</strong>rs in relation <strong>to</strong> <strong>the</strong> completion, appraisal and development program undertaken in<br />
Elk and Antelope fields as part of <strong>the</strong> IPI agreement. These cash call amounts were previously offset against <strong>the</strong><br />
capitalized oil and gas properties, and have been reinstated in <strong>the</strong> oil and gas properties asset <strong>to</strong> <strong>the</strong>ir full his<strong>to</strong>rical cost<br />
basis for those programs following this exchange transaction.<br />
• fair value of <strong>the</strong> conversion options extinguished as part of <strong>the</strong> exchange transactions.<br />
• IPI liability extinguished as part of <strong>the</strong> exchange transactions whereby <strong>the</strong> difference between <strong>the</strong> fair value of <strong>the</strong><br />
shares issued and <strong>the</strong> book value of <strong>the</strong> IPI liability post allocation <strong>to</strong> <strong>the</strong> o<strong>the</strong>r components mentioned above has been<br />
recorded as an expense in <strong>the</strong> statement of operations.<br />
The following table discloses a breakdown of <strong>the</strong> loss on extinguishment of IPI liability for <strong>the</strong> periods ended:<br />
Loss on extinguishment of IPI liability<br />
December 31, 2011<br />
$<br />
Year ended<br />
December 31, 2010<br />
$<br />
Consideration paid for exchange transactions - 48,805,409<br />
less amounts capitalized in relation <strong>to</strong> <strong>the</strong> appraisal program cash calls - (3,784,466)<br />
less book value of IPI liability extinguished - (5,424,231)<br />
less book value of conversion options extinguished - (1,120,000)<br />
less difference between book value and fair value of conversion options extinguished taken <strong>to</strong><br />
contributed surplus<br />
(b) Indirect participation interest – PNGDV<br />
- (7,908,002)<br />
- 30,568,710<br />
As at December 31, 2011, <strong>the</strong> balance of <strong>the</strong> PNG Drilling Ventures Limited (“PNGDV”) indirect participation interest in <strong>the</strong><br />
Company’s phase one exploration program within <strong>the</strong> area governed by PPL 236, 237 and 238 is $1,384,492 (Dec 2010 -<br />
$1,384,492). This balance is based on <strong>the</strong> initial liability recognized in 2006 of $3,588,560 relating <strong>to</strong> its obligation <strong>to</strong> drill <strong>the</strong><br />
four exploration wells on behalf of <strong>the</strong> inves<strong>to</strong>rs, being reduced by amounts already incurred in fulfilling <strong>the</strong> obligation. PNGDV<br />
has a 6.75% interest in <strong>the</strong> four exploration wells starting with Elk-1 (with an additional two exploration wells <strong>to</strong> be drilled after<br />
Elk-4/A). PNGDV also has <strong>the</strong> right <strong>to</strong> participate in <strong>the</strong> 16 wells that follow <strong>the</strong> first four mentioned above up <strong>to</strong> an interest of<br />
5.75% at a cost of $112,500 per 1% per well (with higher amounts <strong>to</strong> be paid if <strong>the</strong> depth exceed 3,500 meters and <strong>the</strong> cost<br />
exceeds $8,500,000).<br />
(c) PNG Energy Inves<strong>to</strong>rs<br />
PNG Energy Inves<strong>to</strong>rs (“PNGEI”), an indirect participation interest inves<strong>to</strong>r who converted all of its interest <strong>to</strong> common shares<br />
in fiscal year 2004, has <strong>the</strong> right <strong>to</strong> participate up <strong>to</strong> a 4.25% interest in 16 wells commencing from exploration wells<br />
numbered 9 <strong>to</strong> 24. As at <strong>the</strong> end of December 31, 2011 we have drilled 6 exploration wells since inception of <strong>the</strong> Company’s<br />
exploration program within PPL 236, 237 and 238 in PNG. In order <strong>to</strong> participate, PNGEI would be required <strong>to</strong> contribute for<br />
each exploration well, a) $112,500 per percentage point or b) where <strong>the</strong> well is planned <strong>to</strong> be drilled beyond 2,000 meters,<br />
$112,500 per percentage point plus actual cost over $1,000,000 charged pro-rata per percentage point.<br />
22. Deferred gain on contributions <strong>to</strong> LNG Project<br />
On July 30, 2007, a Shareholders’ Agreement was signed between <strong>InterOil</strong> LNG Holdings Inc., Pacific LNG Operations Ltd.,<br />
Merrill Lynch Commodities (Europe) Limited and PNG LNG Inc.. As part of <strong>the</strong> Shareholders’ Agreement, five ‘A’ Class shares<br />
were issued by PNG LNG Inc. with full voting rights with each share controlling one board position. Two ‘A’ Class shares were<br />
owned by <strong>InterOil</strong> LNG Holdings Inc., two by Merrill Lynch Commodities (Europe) Limited, and one by Pacific LNG Operations<br />
Ltd. All key operational matters require ‘Unanimous’ or ‘Super-majority’ Board resolution which confirms that none of <strong>the</strong> joint<br />
ventures are in a position <strong>to</strong> exercise unilateral control over <strong>the</strong> joint venture.<br />
On February 27, 2009, <strong>InterOil</strong> LNG Holdings Inc. and Pacific LNG Operations Ltd, acquired Merrill Lynch’s interest in <strong>the</strong><br />
Joint Venture Company. <strong>InterOil</strong> issued 499,834 common shares valued at $11,250,000 for its share of <strong>the</strong> settlement. After<br />
<strong>the</strong> completion of this transaction, Merrill Lynch did not retain any ownership or o<strong>the</strong>r interest in <strong>the</strong> PNG LNG project. The<br />
104
two ‘A’ Class shares held by Merrill Lynch have been transferred <strong>to</strong> <strong>InterOil</strong> LNG Holdings Inc. and Pacific LNG Operations<br />
Ltd respectively. A fur<strong>the</strong>r 172 ‘A’ Class shares have been issued <strong>to</strong> <strong>InterOil</strong> LNG Holdings Inc. and 173 ‘A’ Class shares have<br />
been issued <strong>to</strong> Pacific LNG Operations Ltd bringing <strong>the</strong> ‘A’ Class shareholding of both remaining joint venture partners <strong>to</strong> 175<br />
‘A’ Class shares each, giving equal voting rights and board positions in <strong>the</strong> joint venture.<br />
As part of <strong>the</strong> Shareholders’ Agreement on July 30, 2007, <strong>InterOil</strong> was also provided with ‘B’ Class shares in <strong>the</strong> Joint<br />
Venture Company with a fair value of $100,000,000 in recognition of its contribution <strong>to</strong> <strong>the</strong> LNG Project at <strong>the</strong> time of<br />
signing <strong>the</strong> Shareholders’ Agreement. The main items contributed by <strong>InterOil</strong> in<strong>to</strong> <strong>the</strong> Joint Venture Company were<br />
infrastructure developed by <strong>InterOil</strong> near <strong>the</strong> proposed LNG site at Napa Napa, stakeholder relations within Papua New<br />
Guinea, general supply agreements secured with landowners for supply of gas, advanced stage of project development, etc.<br />
Fair value was determined based on <strong>the</strong> agreement between <strong>the</strong> independent joint venture partners.<br />
The o<strong>the</strong>r Joint Venture partner is being issued ‘B’ Class shares as it contributes cash in<strong>to</strong> <strong>the</strong> Joint Venture Company by way<br />
of cash calls.<br />
During September 2009, as part of acquisition by Pacific LNG of a 2.5% direct working interest in <strong>the</strong> Elk and Antelope fields,<br />
Pacific LNG transferred <strong>to</strong> <strong>InterOil</strong> 2.5% of Pacific LNG’s unexercised economic interest in <strong>the</strong> joint venture LNG Project.<br />
Based on this transaction, as at December 31, 2010, <strong>InterOil</strong> and Pacific LNG hold 52.5% and 47.5% economic interest<br />
respectively in <strong>the</strong> LNG project, subject <strong>to</strong> <strong>the</strong> exercise of all <strong>the</strong>ir rights <strong>to</strong> <strong>the</strong> ‘B’ Class shares on payment of cash calls.<br />
To date <strong>InterOil</strong> has a recognized deferred gain on its contributions <strong>to</strong> <strong>the</strong> Joint Venture based on <strong>the</strong> share of o<strong>the</strong>r joint<br />
venture partners in <strong>the</strong> project. As <strong>InterOil</strong>’s shareholding within <strong>the</strong> Joint Venture Company as at December 31, 2011 is<br />
84.582% (Dec 2010 – 86.66%), <strong>the</strong> gain on contribution of non cash assets <strong>to</strong> <strong>the</strong> project by <strong>InterOil</strong> relating <strong>to</strong> o<strong>the</strong>r joint<br />
venture partners’ shareholding (15.418% - amounting <strong>to</strong> $15,113,190) has been recognized by <strong>InterOil</strong> in its balance sheet as<br />
a deferred gain. This deferred gain may increase/decrease as <strong>the</strong> o<strong>the</strong>r Joint Venture partners decrease/increase <strong>the</strong>ir<br />
shareholding in <strong>the</strong> project.<br />
This amount has been recorded as a reduction of deferred LNG project costs of $9,302,415 at December 31, 2011 (Dec 31,<br />
2010 - $4,126,415), which has reduced <strong>the</strong> LNG project costs <strong>to</strong> nil at December 31, 2011, with <strong>the</strong> remaining balance of<br />
$5,810,775 (Dec 31, 2010 - $8,949,857) being recorded as a deferred gain. Any deferred gain will be recognized in <strong>the</strong><br />
consolidated income statement when/if <strong>the</strong> risks and rewards have considered <strong>to</strong> be passed. The intangible assets of <strong>the</strong><br />
Joint Venture Company, contributed by <strong>InterOil</strong>, have been eliminated on proportionate consolidation of <strong>the</strong> joint venture<br />
balances.<br />
23. Asset retirement obligations<br />
The Company plans <strong>to</strong> dismantle <strong>the</strong> refinery and res<strong>to</strong>re <strong>the</strong> site when <strong>the</strong> refinery is decommissioned. During <strong>the</strong> quarter<br />
ended June 30, 2011, Management received <strong>the</strong> final results of an independent assessment of <strong>the</strong> potential asset retirement<br />
obligations of <strong>the</strong> refinery at <strong>the</strong> time of decommissioning and a provision of $4,100,735 was recognized for <strong>the</strong> present value<br />
of <strong>the</strong> estimated expenditure required <strong>to</strong> <strong>complete</strong> this obligation. The fair value of <strong>the</strong> best estimate was derived based on<br />
discounting <strong>the</strong> obligation <strong>to</strong> <strong>the</strong> current period end using a discount rate of 7.78%. These costs have been capitalized as<br />
part of <strong>the</strong> cost of <strong>the</strong> refinery and are depreciated over <strong>the</strong> life of <strong>the</strong> asset. The provision will be accreted over <strong>the</strong><br />
remaining useful life of <strong>the</strong> refinery <strong>to</strong> bring <strong>the</strong> provision <strong>to</strong> <strong>the</strong> estimated expenditure required at <strong>the</strong> time of<br />
decommissioning. The accretion expense for <strong>the</strong> year ended December 31, 2011 was $159,356 (Dec 2010 - $nil).<br />
24. Non controlling interest<br />
The non controlling interest as at December 31, 2010 related <strong>to</strong> Petroleum Independent and Exploration <strong>Corporation</strong>’s (“PIE<br />
Corp.”) 0.01% minority shareholding in SPI <strong>InterOil</strong> LDC. <strong>InterOil</strong> had entered in<strong>to</strong> an agreement with PIE Corp. under which<br />
<strong>the</strong> remaining 5,000 shares of SPI <strong>InterOil</strong> LDC held by PIE Corp. may be exchanged, at <strong>InterOil</strong>’s election, for Common<br />
Shares on a one-for-one basis. On September 30, 2011, <strong>the</strong> Company elected <strong>to</strong> exchange <strong>the</strong> 5,000 shares of SPI <strong>InterOil</strong><br />
LDC held by PIE Corp. with <strong>the</strong> issue of 5,000 Common Shares of <strong>InterOil</strong> <strong>Corporation</strong>. The 5,000 Common Shares issued by<br />
<strong>InterOil</strong> <strong>Corporation</strong> were valued at $243,850. The Company now holds 100% of <strong>the</strong> equity share capital of SPI <strong>InterOil</strong> LDC.<br />
The carrying amount of <strong>the</strong> non-controlling interest in <strong>the</strong> Company on <strong>the</strong> date of acquisition was $26,300. The Company<br />
derecognized non-controlling interests of $26,300 and recorded a decrease in equity attributable <strong>to</strong> owners of <strong>the</strong> Company<br />
of $217,550. The effect of changes in <strong>the</strong> ownership interest of SPI <strong>InterOil</strong> LDC on <strong>the</strong> equity attributable <strong>to</strong><br />
owners of <strong>the</strong> Company during <strong>the</strong> year is summarized as follows:<br />
105
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Carrying amount of non-controlling interests acquired 26,300 -<br />
Consideration paid <strong>to</strong> non-controlling interests (243,850) -<br />
Excess of consideration paid recognised in Company's equity (217,550) -<br />
25. Share capital and reserves<br />
The authorized share capital of <strong>the</strong> Company consists of an unlimited number of common shares with no par value. Each<br />
common share entitles <strong>the</strong> holder <strong>to</strong> one vote.<br />
(a) Common shares - Changes <strong>to</strong> issued share capital were as follows:<br />
Number of shares $<br />
January 1, 2010 43,545,654 613,361,363<br />
Shares issued on exercise of options under S<strong>to</strong>ck Incentive Plan 479,733 19,310,657<br />
Shares issued on vesting of restricted s<strong>to</strong>ck units under S<strong>to</strong>ck Incentive Plan 20,700 1,418,985<br />
Shares issued on buyback of IPI#3 Interest 754,788 50,687,368<br />
Shares issued on litigation settlement 199,677 12,000,000<br />
Shares issued on public offering 2,800,000 198,872,679<br />
December 31, 2010 47,800,552 895,651,052<br />
Shares issued on exercise of options under S<strong>to</strong>ck Incentive Plan 265,440 7,087,574<br />
Shares issued on vesting of restricted s<strong>to</strong>ck units under S<strong>to</strong>ck Incentive Plan 50,079 2,999,138<br />
Shares issued on buyback of non-controlling interest 5,000 243,850<br />
December 31, 2011 48,121,071 905,981,614<br />
Settlement of litigation - The Company’s Chief Executive Officer, Phil Mulacek, and his controlled entities Petroleum<br />
Independent & Exploration <strong>Corporation</strong> and P.I.E. Group, LLC, <strong>to</strong>ge<strong>the</strong>r with <strong>the</strong> Company and certain of its subsidiaries,<br />
were defendants in Todd Peters, et. al. v. Phil Mulacek et. al.; Cause No. 05-040-03592-CV; in <strong>the</strong> 284th District Court of<br />
Montgomery County, Texas. The plaintiffs are members of a partnership that bought a modular oil refinery that was<br />
subsequently, through a series of transactions, sold <strong>to</strong> a subsidiary of <strong>the</strong> Company. We entered in<strong>to</strong> an agreement in August<br />
2010 <strong>to</strong> settle and release all claims against us and our subsidiaries. Pursuant <strong>to</strong> <strong>the</strong> agreed settlement, which was approved<br />
by <strong>the</strong> Court in September, we issued 199,677 common shares <strong>to</strong> <strong>the</strong> plaintiffs during Oc<strong>to</strong>ber, valued at $12 million based<br />
on a volume weighted average price calculated over <strong>the</strong> ten trading days prior <strong>to</strong> execution of <strong>the</strong> settlement agreement.<br />
(b) Nature and purpose of reserves<br />
• Foreign currency translation reserve: Exchange differences arising on translation of <strong>the</strong> foreign controlled entity<br />
are recognized in o<strong>the</strong>r comprehensive income and accumulated in a separate reserve within equity. The cumulative<br />
amount is reclassified <strong>to</strong> profit or loss when <strong>the</strong> net investment is disposed of.<br />
• Available-for-sale financial assets: Changes in <strong>the</strong> fair value and exchange differences arising on translation of<br />
investments, such as equities classified as available-for-sale financial assets, are recognized in o<strong>the</strong>r comprehensive<br />
income and accumulated in a separate reserve within equity. Amounts are reclassified <strong>to</strong> profit or loss when <strong>the</strong><br />
associated assets are sold or impaired.<br />
• Conversion options: This reserve is used <strong>to</strong> recognize <strong>the</strong> value of <strong>the</strong> conversion option included in <strong>the</strong> agreement<br />
with IPI inves<strong>to</strong>rs (refer <strong>to</strong> note 21). This balance will reduce when IPI inves<strong>to</strong>rs sell <strong>the</strong>ir interest back <strong>to</strong> <strong>the</strong> Company.<br />
• Contributed surplus: The contributed surplus reserve is used <strong>to</strong> recognize <strong>the</strong> fair market value of employee s<strong>to</strong>ck<br />
options and restricted s<strong>to</strong>ck units that have not been forfeited or been exercised.<br />
26. 2.75% convertible notes<br />
On November 10, 2010, <strong>the</strong> Company <strong>complete</strong>d <strong>the</strong> issue of $70,000,000 unsecured 2.75% convertible notes with a<br />
maturity of five years. The note holders have <strong>the</strong> right <strong>to</strong> convert <strong>the</strong>ir note in<strong>to</strong> common shares at any time at a conversion<br />
rate of 10.4575 common shares per $1,000 principal amount of notes (which results in an effective initial conversion price of<br />
approximately $95.625 per share). The Company has <strong>the</strong> right <strong>to</strong> redeem <strong>the</strong> notes if <strong>the</strong> daily closing sale price of <strong>the</strong><br />
common shares has been at least 125% of <strong>the</strong> conversion price <strong>the</strong>n in effect for at least 15 trading days during any 20<br />
106
consecutive trading day period. Accrued interest on <strong>the</strong>se notes is <strong>to</strong> be paid semi-annually in arrears, in May and November<br />
of each year, commencing May 2011.<br />
The liability component on initial recognition after adjusting for <strong>the</strong> underwriting placement fee and transaction costs<br />
amounted <strong>to</strong> $51,992,857 and <strong>the</strong> equity component amounted <strong>to</strong> $14,298,036. The liability component will be accreted<br />
over <strong>the</strong> five year maturity period <strong>to</strong> bring <strong>the</strong> liability back <strong>to</strong> <strong>the</strong> carrying value. The accretion expense relating <strong>to</strong> <strong>the</strong> note<br />
liability for <strong>the</strong> year ended December 31, 2011 was $3,212,141 (Dec 2010 - $432,632). In addition <strong>to</strong> <strong>the</strong> accretion,<br />
interest at 2.75% per annum has been expensed for <strong>the</strong> year ended December 31, 2011 amounting <strong>to</strong> $1,925,000 (Dec<br />
2010 - $278,056). The interest payable up <strong>to</strong> November 2011 was paid in cash.<br />
27. S<strong>to</strong>ck compensation<br />
(a) S<strong>to</strong>ck options<br />
Options are issued at no less than market price <strong>to</strong> direc<strong>to</strong>rs, certain employees and <strong>to</strong> a limited number of contrac<strong>to</strong>r<br />
personnel. Options are exercisable for common shares on a 1:1 basis. Individuals are granted options which only vest if<br />
certain performance standards are met, with <strong>the</strong> vesting of <strong>the</strong> majority of options issued only being reliant on <strong>the</strong> individual<br />
remaining employed with <strong>the</strong> Company for a certain time period, while <strong>the</strong> vesting of some options granted are reliant on<br />
various performance conditions. Options vest at various dates in accordance with <strong>the</strong> applicable individual option<br />
agreements, vesting generally between one <strong>to</strong> four years after <strong>the</strong> date of grant, have an exercise period of three <strong>to</strong> five years<br />
after <strong>the</strong> date of grant, and are subject <strong>to</strong> <strong>the</strong> option plan rules. Upon resignation or retirement, vested options must generally<br />
be exercised within 90 days or before expiry of <strong>the</strong> options if this occurs earlier.<br />
S<strong>to</strong>ck options outstanding Number of options Weighted average<br />
exercise price $<br />
December 31, 2011 December 31, 2010<br />
Number of options<br />
Weighted average<br />
exercise price $<br />
Outstanding at beginning of period 1,688,267 27.31 1,838,500 22.07<br />
Granted 110,000 59.89 330,000 54.02<br />
Exercised (265,440) (16.91) (479,733) (25.59)<br />
Forfeited (45,000) (47.33) - -<br />
Expired - - (500) (28.68)<br />
Outstanding at end of period 1,487,827 30.97 1,688,267 27.31<br />
At December 31, 2011, in addition <strong>to</strong> <strong>the</strong> options outstanding as per <strong>the</strong> above table, <strong>the</strong>re were an additional 1,176,531<br />
(2010 – 1,315,617) common shares reserved for issuance under <strong>the</strong> Company’s 2009 s<strong>to</strong>ck incentive plan as approved on<br />
June 19, 2009.<br />
Range of exercise<br />
prices $<br />
Options issued and outstanding<br />
Number of options<br />
Weighted average exercise<br />
price $<br />
Weighted average<br />
remaining term (years)<br />
Options exercisable<br />
Number of options<br />
Weighted average exercise<br />
price $<br />
8.01 <strong>to</strong> 12.00 503,160 9.80 1.90 403,160 9.80<br />
12.01 <strong>to</strong> 24.00 135,000 16.90 1.78 95,000 17.37<br />
24.01 <strong>to</strong> 31.00 100,500 27.74 1.44 100,500 27.74<br />
31.01 <strong>to</strong> 41.00 234,167 35.46 1.20 180,833 35.94<br />
41.01 <strong>to</strong> 51.00 75,000 44.86 1.48 75,000 44.86<br />
51.01 <strong>to</strong> 61.00 380,000 53.08 3.72 - -<br />
61.01 <strong>to</strong> 71.00 30,000 66.58 3.63 15,000 66.58<br />
71.01 <strong>to</strong> 81.00 30,000 74.82 4.23 - -<br />
1,487,827 30.97 2.70 869,493 22.14<br />
Aggregate intrinsic value of <strong>the</strong> 1,487,827 options issued and outstanding as at December 31, 2011 is $27,993,610.<br />
Aggregate intrinsic value of 869,493 options exercisable as at December 31, 2011 is $12,123,867.<br />
The weighted-average grant-date fair value of options granted during 2011 was $37.46 (2010 - $32.26). The <strong>to</strong>tal intrinsic<br />
value of options exercised during <strong>the</strong> year ended December 31, 2011 was $2,598,871 (2010 - $7,035,772). Cash received<br />
from option exercise under all share-based payment arrangements for <strong>the</strong> year ended December 31, 2011 was $4,488,703<br />
(2010 - $12,274,885).<br />
107
The weighted-average share price at <strong>the</strong> date of exercise of options exercised during <strong>the</strong> year ended December 31, 2011 was<br />
$61.54 (2010 - $68.32).<br />
The fair value of <strong>the</strong> 110,000 (2010 – 330,000) options granted subsequent <strong>to</strong> January 1, 2011 has been estimated at<br />
<strong>the</strong> date of grant in <strong>the</strong> amount of $4,121,016 (2010 - $10,645,501) using a Black-Scholes pricing model. An amount of<br />
$9,839,824 (2010 - $7,628,017) has been recognized as compensation expense for <strong>the</strong> year ended December 31, 2011.<br />
The current year compensation expense of $9,839,824 (2010 - $7,628,017) was adjusted against contributed surplus under<br />
equity and $2,598,871 (2010 - $7,035,773) was transferred <strong>to</strong> share capital on exercise of options, leaving a net impact of<br />
$7,240,953 (2010 - $592,244) on contributed surplus.<br />
The assumptions contained in <strong>the</strong> Black Scholes pricing model are as follows:<br />
Year Period Risk free interest rate (%) Dividend yield Volatility (%) Weighted average expected life for options<br />
2011 Apr 1 <strong>to</strong> Dec 31 0.4 - 78 5.0<br />
2011 Jan 1 <strong>to</strong> Mar 31 1.2 - 79 5.0<br />
2010 Jul 1 <strong>to</strong> Dec 31 0.8 - 87 5.0<br />
2010 Jan 1 <strong>to</strong> Jun 30 1.2 - 87 5.0<br />
(b) Restricted s<strong>to</strong>ck<br />
Restricted s<strong>to</strong>ck may be issued <strong>to</strong> direc<strong>to</strong>rs, certain employees and <strong>to</strong> a limited number of contrac<strong>to</strong>r personnel under <strong>the</strong><br />
Company’s 2009 s<strong>to</strong>ck incentive plan. Restricted s<strong>to</strong>ck vests at various dates in accordance with <strong>the</strong> applicable restricted<br />
s<strong>to</strong>ck agreement, vesting generally between one <strong>to</strong> three years after <strong>the</strong> date of grant.<br />
Restricted s<strong>to</strong>ck units outstanding<br />
Number of<br />
restricted s<strong>to</strong>ck<br />
units<br />
December 31, 2011<br />
$<br />
Weighted Average<br />
Grant Date<br />
Fair Value per<br />
restricted s<strong>to</strong>ck<br />
unit $<br />
Number of<br />
restricted s<strong>to</strong>ck<br />
units<br />
December 31, 2010<br />
$<br />
Weighted Average<br />
Grant Date<br />
Fair Value per<br />
restricted s<strong>to</strong>ck<br />
unit $<br />
Outstanding at beginning of period 124,192 56.99 41,400 68.55<br />
Granted 97,069 67.06 107,483 54.73<br />
Exercised (50,079) (59.89) (20,700) (68.55)<br />
Forfeited (18,992) (64.34) (3,991) (56.13)<br />
Total 152,190 61.54 124,192 56.99<br />
An amount of $4,881,563 (2010 - $4,175,983) has been recognized as compensation expense for <strong>the</strong> year ended<br />
December 31, 2011. The current year compensation expense of $4,881,563 (2010 - $4,175,983) was adjusted against<br />
contributed surplus under equity and $2,999,138 (2010 - $1,418,985) was transferred <strong>to</strong> share capital on vesting of s<strong>to</strong>ck<br />
units, leaving a net impact of $1,882,425 (2010 - $2,756,998) on contributed surplus.<br />
28. Earnings/(Loss) per share<br />
Conversion options, convertible notes, s<strong>to</strong>ck options and restricted s<strong>to</strong>ck units <strong>to</strong>taling 2,712,522 common shares at prices<br />
ranging from $9.80 <strong>to</strong> $95.63 were outstanding as at December 31, 2011 and some of <strong>the</strong>se were included in <strong>the</strong><br />
computation of <strong>the</strong> diluted earnings per share for <strong>the</strong> year ended December 31, 2011. The dilutive instruments outstanding at<br />
December 31, 2010 were not included in <strong>the</strong> computation of <strong>the</strong> diluted loss per share in respective periods because <strong>the</strong>y<br />
caused <strong>the</strong> loss per share <strong>to</strong> be anti-dilutive.<br />
Potential dilutive instruments outstanding Number of shares December 31, 2011 Number of shares December 31, 2010<br />
Employee s<strong>to</strong>ck options 1,487,827 1,688,267<br />
Employee Restricted S<strong>to</strong>ck 152,190 124,192<br />
IPI Indirect Participation interest - conversion options 340,480 340,480<br />
2.75% Convertible notes 732,025 732,025<br />
O<strong>the</strong>rs - 5,000<br />
Total s<strong>to</strong>ck options/shares outstanding 2,712,522 2,889,964<br />
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The income available <strong>to</strong> <strong>the</strong> common shareholders and <strong>the</strong> income available <strong>to</strong> <strong>the</strong> dilutive holders, used in <strong>the</strong> calculation of<br />
<strong>the</strong> numera<strong>to</strong>r in <strong>the</strong> EPS calculation for <strong>the</strong> year ended December 31, 2011 and 2010 is <strong>the</strong> net profit/loss as per<br />
Consolidated Income Statement. This is due <strong>to</strong> <strong>the</strong> fact that <strong>the</strong> inclusion of convertible securities in <strong>the</strong> calculation would<br />
result in <strong>the</strong> EPS being anti-dilutive.<br />
The reconciliation between <strong>the</strong> ‘Basic’ and ‘Basic and Diluted’ shares, used in <strong>the</strong> calculation of <strong>the</strong> denomina<strong>to</strong>r in <strong>the</strong> EPS<br />
calculation is as follows:<br />
December 31, 2011<br />
$<br />
Year ended<br />
December 31, 2010<br />
$<br />
Basic 47,977,478 44,329,670<br />
Employee options 803,507 -<br />
Employee restricted s<strong>to</strong>ck 88,985 -<br />
Indirect participation interest 340,480 -<br />
O<strong>the</strong>r 3,740 -<br />
Diluted 49,214,190 44,329,670<br />
29. Commitments and contingencies<br />
(a) Exploration and debt commitments<br />
Payments due by period contractual obligations are as follows:<br />
Petroleum prospecting and retention<br />
licenses (a)<br />
Less than<br />
Total Less than 1 year 1-2 years 2-3 years 3-4 years 4-5 years More than 5 years<br />
'000 '000 '000 '000 '000 '000 '000<br />
134,900 44,400 36,350 44,050 9,900 200 -<br />
Secured and unsecured loans (b) 51,586 21,727 10,749 10,131 8,979 - -<br />
Convertible notes obligations 77,540 1,925 1,925 1,925 71,765 - -<br />
Indirect participation interest - PNGDV<br />
(note 21)<br />
1,384 540 844 - - - -<br />
265,410 68,592 49,868 56,106 90,644 200 -<br />
(a) The amount pertaining <strong>to</strong> <strong>the</strong> petroleum prospecting and retention licenses represents <strong>the</strong> amount <strong>InterOil</strong> has committed as a condition on renewal of<br />
<strong>the</strong>se licenses. Company is committed <strong>to</strong> spend a fur<strong>the</strong>r $61.9 million as a condition of renewal of our petroleum prospecting licenses up <strong>to</strong> 2014. Of this<br />
$61.9 million commitment, as at December 31, 2011, management estimates that satisfying this license commitment would also satisfy our commitments<br />
<strong>to</strong> <strong>the</strong> IPI inves<strong>to</strong>rs in relation <strong>to</strong> drilling <strong>the</strong> final four wells and satisfy <strong>the</strong> commitments in relation <strong>to</strong> <strong>the</strong> IPI agreement. In addition, <strong>the</strong> terms of grant of<br />
PRL15, requires <strong>the</strong> Company <strong>to</strong> spend a fur<strong>the</strong>r $73.0 million on <strong>the</strong> development of <strong>the</strong> Elk and Antelope fields by <strong>the</strong> end of 2014.<br />
(b) The effective interest rate on this loan for <strong>the</strong> year ended December 31, 2011 was 6.93%.<br />
(b) Operating lease commitments – Company as lessee<br />
The Company leases various retail service station premises, commercial office properties, residential apartments, mo<strong>to</strong>r<br />
vessels and office equipment under non-cancellable operating lease agreements. The remaining lease terms are between 1<br />
and 30 years, and <strong>the</strong> majority of lease agreements are renewable at <strong>the</strong> end of <strong>the</strong> lease period at market rate.<br />
The future aggregate minimum lease payments under non-cancellable operating leases are as follows:<br />
December 31, 2011<br />
$<br />
December 31, 2010<br />
$<br />
Not later than 1 year 6,983,149 6,257,276<br />
Later than 1 year and not later than 5 years 6,560,263 8,558,043<br />
Later than 5 years 2,957,605 458,071<br />
Total 16,501,017 15,273,390<br />
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(c) Contingencies<br />
From time <strong>to</strong> time <strong>the</strong> Company is involved in various claims and litigation arising in <strong>the</strong> course of its business. While <strong>the</strong><br />
outcome of <strong>the</strong>se matters is uncertain and <strong>the</strong>re can be no assurance that such matters will be resolved in <strong>the</strong> Company’s<br />
favor, <strong>the</strong> Company does not currently believe that <strong>the</strong> outcome of adverse decisions in any pending or threatened<br />
proceedings or any amount which it may be required <strong>to</strong> pay by reason <strong>the</strong>reof would have a material adverse impact on its<br />
financial position, results of operations or liquidity.<br />
Audit by PNG Cus<strong>to</strong>ms<br />
During <strong>the</strong> second half of 2011, <strong>the</strong> PNG Cus<strong>to</strong>ms Service commenced an audit of our petroleum product imports in<strong>to</strong> Papua<br />
New Guinea for <strong>the</strong> years 2007 <strong>to</strong> 2010. The Company received a letter in November 2011 from <strong>the</strong> <strong>the</strong>n Commissioner of<br />
Cus<strong>to</strong>ms setting out certain findings from <strong>the</strong> audit. This letter included comments alleging that payment of import GST was<br />
required and had not been made on imports of certain refined products. As well as requiring payment of GST, <strong>the</strong> letter noted<br />
that administrative penalties were able <strong>to</strong> be levied by Cus<strong>to</strong>ms in <strong>the</strong> range of 50% <strong>to</strong> 200% of <strong>the</strong> assessed amounts as per<br />
<strong>the</strong> Cus<strong>to</strong>ms Act. The Company has since met with <strong>the</strong> Cus<strong>to</strong>ms Service and provided it with supporting documentation <strong>to</strong><br />
demonstrate that <strong>the</strong> GST amounts claimed in <strong>the</strong>ir letter have all been paid. Management has included a provision in <strong>the</strong>se<br />
financial statements based on <strong>the</strong>ir best estimate in relation <strong>to</strong> this matter and is working closely with <strong>the</strong> authority <strong>to</strong> provide<br />
all requested information in order <strong>to</strong> finalize <strong>the</strong> audit.<br />
110
Glossary of Terms<br />
“2011 Annual Information Form” means <strong>the</strong> Annual Information Form for <strong>the</strong> year ended December 31, 2011.<br />
“2011 MD&A” means <strong>the</strong> Management’s Discussion and Analysis for <strong>the</strong> year ended December 31, 2011.<br />
“AUD” means Australian dollars.<br />
“API” means <strong>the</strong> American Petroleum Institute.<br />
“Barrel, Bbl” (petroleum) Unit volume measurement used for petroleum and its products.<br />
“BNP Paribas” means BNP Paribas Capital (Singapore) Limited.<br />
“Board” means <strong>the</strong> board of direc<strong>to</strong>rs of <strong>InterOil</strong>.<br />
“BP” means BP Singapore Pte Limited.<br />
“BSP” means Bank of South Pacific Limited.<br />
“CDU” means crude distillation unit.<br />
“CGR” means condensate <strong>to</strong> gas ratio.<br />
“COGE Handbook” refers <strong>to</strong> <strong>the</strong> Canadian Oil and Gas Evaluation Handbook.<br />
“Condensate” A component of natural gas which is a liquid at surface conditions.<br />
“Convertible notes” means <strong>the</strong> 2.75% convertible senior notes of <strong>InterOil</strong> due November 15, 2015.<br />
“Crack spread” The simultaneous purchase or sale of crude against <strong>the</strong> sale or purchase of refined petroleum products. These spread differentials which<br />
represent refining margins are normally quoted in dollars per barrel by converting <strong>the</strong> product prices in<strong>to</strong> dollars per barrel and subtracting <strong>the</strong> crude price.<br />
“CRU” means catalytic reformer unit.<br />
“Crude oil” A mixture consisting mainly of pentanes and heavier hydrocarbons that exists in <strong>the</strong> liquid phase in reservoirs and remains liquid at atmospheric<br />
pressure and temperature. Crude oil may contain small amounts of sulfur and o<strong>the</strong>r non hydrocarbons but does not include liquids obtained from <strong>the</strong><br />
processing of natural gas.<br />
“CSP Joint Venture” or “CSP JV” means <strong>the</strong> Joint Venture Operating Agreement (“JVOA”) entered in<strong>to</strong> for <strong>the</strong> proposed condensate stripping facilities with<br />
Mitsui or <strong>the</strong> joint venture formed <strong>to</strong> develop and operate <strong>the</strong> proposed condensate stripping facilities as <strong>the</strong> context requires.<br />
“Condensate Stripping Project” means <strong>the</strong> proposed condensate stripping facilities, including ga<strong>the</strong>ring and condensate pipeline, condensate s<strong>to</strong>rage and<br />
associated facilities being progressed in joint venture with Mitsui.<br />
“DST” refers <strong>to</strong> a drill stem test and is a procedure for isolating and testing <strong>the</strong> surrounding geological formation through <strong>the</strong> drill pipe.<br />
“EBITDA” EBITDA represents net income/(loss) plus <strong>to</strong>tal interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation<br />
and amortization expense. EBITDA is a non-GAAP measure used <strong>to</strong> analyze operating performance. See “Non-GAAP Measures and Reconciliation”.<br />
“EPC Contrac<strong>to</strong>r” means an engineering, procurement and construction contrac<strong>to</strong>r.<br />
“ERP” means Enterprise Resource Planning System.<br />
“EWC” means Energy World <strong>Corporation</strong> Limited., a company organized under <strong>the</strong> laws of Australia.<br />
“Farm out” A contractual agreement with an owner who holds a working interest in an oil and gas lease <strong>to</strong> assign all or part of that interest <strong>to</strong> ano<strong>the</strong>r party<br />
in exchange for <strong>the</strong> o<strong>the</strong>r party’s fulfillment of contractually specified conditions. Farm out agreements often stipulate that a party must drill a well <strong>to</strong> a certain<br />
depth, at a specified location, within a certain time frame; fur<strong>the</strong>rmore, typically, <strong>the</strong> well must be <strong>complete</strong>d as a commercial producer <strong>to</strong> earn an assignment<br />
of <strong>the</strong> working interest. The assignor of <strong>the</strong> interest usually reserves a specified overriding royalty interest, with <strong>the</strong> option <strong>to</strong> convert <strong>the</strong> overriding royalty<br />
interest <strong>to</strong> a specified working interest upon payout of drilling and production expenses.<br />
“FEED” means front end engineering and design.<br />
“Feeds<strong>to</strong>ck” means raw material used in a refinery or o<strong>the</strong>r processing plant.<br />
“FID” means final investment decision. Such a decision is ordinarily <strong>the</strong> point at which a decision is made <strong>to</strong> proceed with a project and it becomes<br />
unconditional. However, in some instances <strong>the</strong> decision may be qualified by certain conditions, including being subject <strong>to</strong> necessary approvals by <strong>the</strong> State.<br />
“FLEX LNG” means FLEX LNG Limited, a British Virgin Islands Company listed on <strong>the</strong> Oslo S<strong>to</strong>ck Exchange.<br />
111
“GAAP” means Canadian generally accepted accounting principles.<br />
“Gas” means a mixture of lighter hydrocarbons that exist ei<strong>the</strong>r in <strong>the</strong> gaseous phase or in solution in crude oil in reservoirs but are gaseous at atmospheric<br />
conditions. Natural gas may contain sulfur or o<strong>the</strong>r non-hydrocarbon compounds.<br />
“GLJ” means GLJ Petroleum Consultants Limited, an independent qualified reserves evalua<strong>to</strong>r.<br />
“GLJ 2010 Report” means <strong>the</strong> <strong>report</strong> dated March 7, 2011 with an effective date of December 31, 2010 setting forth certain information regarding contingent<br />
resources of <strong>InterOil</strong>’s interests in <strong>the</strong> Elk and Antelope fields in PNG.<br />
“GLJ 2011 Report” means <strong>the</strong> <strong>report</strong> dated February 28, 2012 with an effective date of December 31, 2011 setting forth certain information regarding<br />
contingent resources of <strong>InterOil</strong>’s interests in <strong>the</strong> Elk and Antelope fields in PNG.<br />
“Gross reserves” refers <strong>to</strong> <strong>InterOil</strong>’s working interest reserves before <strong>the</strong> deduction of royalties and before including any royalty interests.<br />
“Gross wells” refers <strong>to</strong> <strong>the</strong> <strong>to</strong>tal number of wells in which we have an interest.<br />
“ICCC” means Papua New Guinea’s competition authority, <strong>the</strong> Independent Consumer and Competition Commission.<br />
“IFRS” means International Financial Reporting Standards as issued by <strong>the</strong> International Accounting Standards Board.<br />
“IPI Agreement” means <strong>the</strong> Amended and Restated Indirect Participation Agreement dated February 25, 2005, as amended.<br />
“IPI holders” means inves<strong>to</strong>rs holding IPWIs in certain exploration wells required <strong>to</strong> be drilled pursuant <strong>to</strong> <strong>the</strong> IPI Agreement.<br />
“IPF” refers <strong>to</strong> <strong>InterOil</strong> power fuel, <strong>InterOil</strong>’s marketing name for low sulfur waxy residue or LSWR.<br />
“IPP” means import parity price. For each refined product produced and sold locally in Papua New Guinea, IPP is calculated under agreement with <strong>the</strong> State<br />
by adding <strong>the</strong> costs that would typically be incurred <strong>to</strong> import such product <strong>to</strong> an average posted price for such product in Singapore as <strong>report</strong>ed by Platts.<br />
The costs added <strong>to</strong> <strong>the</strong> <strong>report</strong>ed Platts price include freight costs, insurance costs, landing charges, losses incurred in <strong>the</strong> transportation of refined products,<br />
demurrage and taxes.<br />
“IPWI” means indirect participation working interest.<br />
“LIBOR” means daily reference rate based on <strong>the</strong> interest rates at which banks borrow unsecured funds from banks in <strong>the</strong> London wholesale money market.<br />
“LNG” means liquefied natural gas. Natural gas may be converted <strong>to</strong> a liquid state by pressure and severe cooling for transportation purposes, and <strong>the</strong>n<br />
returned <strong>to</strong> a gaseous state <strong>to</strong> be used as fuel. LNG, which is predominantly artificially liquefied methane, is not <strong>to</strong> be confused with NGLs, natural gas<br />
liquids, which are heavier fractions that occur naturally as liquids.<br />
“LNGL” means Liquid Niugini Gas Limited, a wholly owned subsidiary of PNG LNG formed in Papua New Guinea <strong>to</strong> contract with <strong>the</strong> State and pursue <strong>the</strong><br />
LNG Project, including construction of <strong>the</strong> proposed liquefaction facilities.<br />
“LNG Project” means <strong>the</strong> development by us of liquefaction facilities in <strong>the</strong> Gulf Province of Papua New Guinea described as our Midstream Liquefaction<br />
business segment and being undertaken as a joint venture with Pac LNG and with o<strong>the</strong>r potential partners, including <strong>the</strong> State.<br />
“LNG Project Agreement” means <strong>the</strong> LNG Project Agreement between <strong>the</strong> State and LNGL dated December 23, 2009.<br />
“LSWR” means low sulfur waxy residue.<br />
“Mark-<strong>to</strong>-market” refers <strong>to</strong> <strong>the</strong> accounting standards of assigning a value <strong>to</strong> a position held in a financial instrument based on <strong>the</strong> current fair market price for<br />
<strong>the</strong> instrument or similar instruments.<br />
“Mitsui” refers <strong>to</strong> Mitsui & Co., Ltd., a company organized under <strong>the</strong> laws of Japan and/or certain of its wholly-owned subsidiaries (as <strong>the</strong> context requires).<br />
“Mtpa” means million <strong>to</strong>nnes per annum.<br />
“Naphtha” That portion of <strong>the</strong> distillate obtained from <strong>the</strong> refinement of petroleum which is an intermediate between <strong>the</strong> lighter gasoline and <strong>the</strong> heavier<br />
benzene. It is a feeds<strong>to</strong>ck destined ei<strong>the</strong>r for <strong>the</strong> petrochemical industry or for gasoline production by reforming or isomerisation within a refinery.<br />
“Natural gas” means a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath <strong>the</strong> earth’s<br />
surface, often in association with petroleum. The principal constituent is methane.<br />
“NGL” means natural gas liquids, consisting of any one or more of propane, butane and condensate.<br />
“Net wells” refers <strong>to</strong> <strong>the</strong> aggregate of <strong>the</strong> numbers obtained by multiplying each gross well by our percentage working interest in that well.<br />
“NI 51-101” refers <strong>to</strong> National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities adopted by <strong>the</strong> Canadian Securities Administra<strong>to</strong>rs.<br />
“NI 52-110” refers <strong>to</strong> National Instrument 52-110 - Audit Committees adopted by <strong>the</strong> Canadian Securities Administra<strong>to</strong>rs.<br />
“OPIC” means Overseas Private Investment <strong>Corporation</strong>, an agency of <strong>the</strong> United States Government.<br />
112
“Pac LNG” means Pacific LNG Operations Ltd., a company incorporated in <strong>the</strong> Bahamas and affiliated with Clarion Finanz A.G. This company is our joint<br />
venture partner in <strong>the</strong> LNG Project (holding equal voting shares in PNG LNG), holds a 2.5% direct interest in <strong>the</strong> Elk and Antelope fields, is an IPI holder and a<br />
shareholder in PNGDV.<br />
“PDL” means Petroleum Development License. The right granted by <strong>the</strong> State <strong>to</strong> develop a field for commercial production.<br />
“Petromin” means Petromin PNG Holdings Limited, a company incorporated in Papua New Guinea by <strong>the</strong> State.<br />
“PGK” means <strong>the</strong> Kina, currency of Papua New Guinea.<br />
“PNGDV” means PNG Drilling Ventures Limited, an entity with which we entered in<strong>to</strong> an indirect participation agreement in May 2003, as amended.<br />
“PNG LNG” means PNG LNG, Inc., a joint venture company established in 2007 <strong>to</strong> hold <strong>the</strong> interests of certain joint venturers in <strong>the</strong> venture <strong>to</strong> construct <strong>the</strong><br />
proposed liquefaction facilities. Shareholders are <strong>InterOil</strong> LNG Holdings Inc., a wholly-owned subsidiary of <strong>InterOil</strong>, and Pac LNG.<br />
“PPL” means Petroleum Prospecting License. The tenement given by <strong>the</strong> State <strong>to</strong> explore for oil and gas.<br />
“PRL” means Petroleum Retention License. The tenement given by <strong>the</strong> State <strong>to</strong> allow <strong>the</strong> license holder <strong>to</strong> evaluate <strong>the</strong> commercial and technical options for<br />
<strong>the</strong> potential development of an oil and/or gas field.<br />
“Prospective Resources” are those quantities of petroleum estimated, as of a given date, <strong>to</strong> be potentially recoverable from undiscovered accumulations by<br />
application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective<br />
Resources are fur<strong>the</strong>r subdivided in accordance with <strong>the</strong> level of certainty associated with recoverable estimates assuming <strong>the</strong>ir discovery and development<br />
and may be sub classified based on project maturity.<br />
“Samsung Heavy Industries” means Samsung Heavy Industries Co., Ltd., a corporation incorporated and existing under <strong>the</strong> laws of <strong>the</strong> Republic of Korea.<br />
“SGD” means Singapore Dollars.<br />
“Shut-in” refers <strong>to</strong> wells that are capable of producing oil or natural gas which are not producing due <strong>to</strong> lack of available transportation facilities, available<br />
markets or o<strong>the</strong>r reasons.<br />
“State” or “PNG” means <strong>the</strong> Independent State of Papua New Guinea.<br />
“Sweet/sour crude” Sweetness describes <strong>the</strong> degree of a given crude’s sulfur content. Sour crudes are high in sulfur, sweet crudes are low.<br />
“USD” means United States Dollars.<br />
“Westpac” means Westpac Bank PNG Limited.<br />
“Working interest” means <strong>the</strong> percentage of undivided interest held by <strong>InterOil</strong> in an oil and natural gas property.<br />
“YBCA” means <strong>the</strong> Business <strong>Corporation</strong>s Act (Yukon Terri<strong>to</strong>ry).<br />
Conversion<br />
The following table sets forth certain standard conversions between Standard Imperial Units and <strong>the</strong> International System of<br />
Units (metric units).<br />
To Convert From<br />
mcf<br />
cubic metres<br />
bbls<br />
cubic metres<br />
feet<br />
metres<br />
miles<br />
kilometers<br />
acres<br />
hectares<br />
To<br />
cubic metres<br />
cubic feet<br />
cubic metres<br />
bbls<br />
metres<br />
feet<br />
kilometers<br />
miles<br />
hectares<br />
acres<br />
Multiply By<br />
28.317<br />
35.315<br />
0.159<br />
6.289<br />
0.305<br />
3.281<br />
1.609<br />
0.621<br />
0.405<br />
2.471<br />
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Corporate Direc<strong>to</strong>ry<br />
Direc<strong>to</strong>rs and Executive Officers<br />
The following table provides information with respect <strong>to</strong> all of our direc<strong>to</strong>rs and executive officers:<br />
Name, Location Position with <strong>InterOil</strong> Date of Appointment<br />
Phil E. Mulacek<br />
Texas, USA<br />
Christian Vinson<br />
Port Moresby, PNG<br />
Gaylen Byker<br />
Michigan, USA<br />
Roger Grundy<br />
Derbyshire, UK<br />
Roger F. Lewis<br />
Western Australia, Australia<br />
Ford Nicholson<br />
British Columbia, Canada<br />
William Jasper III<br />
Texas, USA<br />
Collin Visaggio<br />
Western Australia, Australia<br />
Mark Laurie<br />
South Australia, Australia<br />
Notes<br />
Chairman, Direc<strong>to</strong>r and Chief Executive Officer May 29, 1997<br />
Vice President Corporate Development and<br />
Government Affairs, Direc<strong>to</strong>r<br />
May 29, 1997<br />
Direc<strong>to</strong>r (1) May 29, 1997<br />
Direc<strong>to</strong>r (2) May 29, 1997<br />
Direc<strong>to</strong>r (3) November 26, 2008<br />
Direc<strong>to</strong>r (4) June 22, 2010<br />
President and Chief Operating Officer September 18, 2006<br />
Chief Financial Officer Oc<strong>to</strong>ber 26, 2006<br />
General Counsel and Corporate Secretary June 12, 2007<br />
1 Gaylen Byker acts is <strong>the</strong> Company’s Lead Independent Direc<strong>to</strong>r and acts as Chairman of each of <strong>the</strong> Board’s Nominating and<br />
Governance Committee and Compensation Committee and has held such positions throughout 2011. He is a member of <strong>the</strong> Audit<br />
Committee and of <strong>the</strong> Reserves Committee. He acts as deputy Chairman of <strong>the</strong> Board and chairs a number of its meetings.<br />
2 Roger Grundy was Chairman of <strong>the</strong> Reserves Committee throughout 2011.<br />
3 Roger Lewis was Chairman of <strong>the</strong> Audit Committee, and a member of <strong>the</strong> Nominating and Governance Committee and Compensation<br />
Committee throughout 2011.<br />
4 Ford Nicholson was a member of <strong>the</strong> Audit Committee and Reserves Committee throughout 2011.<br />
5 Certain information has been furnished by our direc<strong>to</strong>rs and executive officers. Such information includes information as <strong>to</strong> our common<br />
shares in <strong>the</strong> Company beneficially owned, controlled or directed, directly or indirectly, by <strong>the</strong>m, <strong>the</strong>ir places of residence and principal<br />
occupations, both present and his<strong>to</strong>rical, interests in material transactions and potential conflicts of interest.<br />
Operational Office Locations<br />
Cairns, Australia<br />
Level 3, Cairns Square<br />
42 - 52 Abbott street<br />
Cairns Queensland 4870 Australia<br />
Telephone: +61 (7) 4046 4600<br />
Facsimile: +61 (7) 4031 4565<br />
Port Moresby, Papua New Guinea<br />
<strong>InterOil</strong> Limited<br />
<strong>InterOil</strong> Refinery<br />
Post Office Box 1971<br />
Port Moresby, NCD<br />
Telephone: +(675) 309-9100<br />
Facsimile: +(675) 309-9188<br />
Hous<strong>to</strong>n, Texas USA<br />
25025 I-45 North, Suite 420<br />
The Woodlands, Texas 77380<br />
Telephone: +1 (281) 292-1800<br />
Facsimile: +1 (281) 292-0888<br />
Singapore<br />
<strong>InterOil</strong> Singapore Pte Ltd<br />
7 Temasek Boulevard<br />
#28-01 Suntec Tower One<br />
Singapore 038987<br />
Telephone: +65 6507 0222<br />
Facsimile: +65 6884 9562<br />
114
S<strong>to</strong>ck Exchanges<br />
United States of America<br />
NYSE Euronext<br />
11 Wall Street<br />
New York, New York 10005<br />
www.nyse.com<br />
Trading symbol: IOC<br />
Papua New Guinea<br />
Port Moresby S<strong>to</strong>ck Exchange Limited<br />
Defens Haus, 4th Floor<br />
Port Moresby NCD<br />
Papua New Guinea<br />
Telephone: +1 (675) 320-1980<br />
www.pomsox.com.pg<br />
Trading symbol: IOC<br />
Audi<strong>to</strong>rs<br />
PricewaterhouseCoopers<br />
2 Southbank Boulevard<br />
Southbank, VIC 3006<br />
DX 77 Melbourne, Australia<br />
Telephone +61 (3) 8603 1000<br />
Facsimile +61 (3) 8603 1999<br />
Transfer Agent and Share Registrars<br />
Main Agent<br />
Computershare Inves<strong>to</strong>r Services Inc.<br />
100 University Avenue, 9th Floor<br />
Toron<strong>to</strong>, Ontario<br />
Canada M5J 2YI<br />
Telephone: (800) 564-6253<br />
Facsimile: (888) 453-0330<br />
E-mail: service@computershare.com<br />
Website: www.computershare.com<br />
Co-Transfer Agent (USA)<br />
Computershare Trust Company N.A.<br />
350 Indiana Street<br />
Golden, Colorado 80401 USA<br />
Telephone: (800) 962-4284<br />
International: (514) 982-7555<br />
Legal<br />
Canada<br />
Bennett Jones LLP<br />
45 Bankers Hall East<br />
855 2nd Street SW<br />
Calgary, Alberta T2P 4K7<br />
Telephone: +1 (403) 298-3100<br />
Australia Papua New Guinea<br />
Gadens Lawyers<br />
77 Castlereagh Street<br />
Sydney NSW 2000 Australia<br />
Telephone: +1 (61) 2 9931 4999<br />
United States of America<br />
Haynes and Boone LLP<br />
At<strong>to</strong>rneys and Counselors<br />
901 Main Street Suite 3100<br />
Dallas, Texas 75202 USA<br />
Telephone: +1 (214) 651-5000<br />
Bankers<br />
Canada<br />
Canadian Imperial Bank of Commerce<br />
Commerce Court<br />
Toron<strong>to</strong> ON M5L 1A2 Canada<br />
Telephone: +1 (416) 980-2211<br />
United States of America<br />
Wells Fargo Bank TX N.A.<br />
1500 Broadway<br />
Lubbock, Texas 79401 USA<br />
Telephone: +1 (806) 767-7418<br />
Australia Papua New Guinea<br />
Australian and New Zealand Bank<br />
Defens Haus, 3rd Floor<br />
Port Moresby NCD<br />
Papua New Guinea<br />
Telephone: +1 (675) 322-3333<br />
Inves<strong>to</strong>r Relations<br />
Wayne W. Andrews<br />
Vice President of Capital Markets<br />
The Woodlands, Texas<br />
Email: wayne.andrews@interoil.com<br />
Meg LaSalle<br />
Inves<strong>to</strong>r Relations Coordina<strong>to</strong>r<br />
The Woodlands, Texas<br />
Email: meg.lasalle@interoil.com<br />
Global Agency of Record<br />
Content Media Group Limited<br />
The Woodlands, Texas<br />
www.contentmedia.cc<br />
Where Applicable: Pho<strong>to</strong>graphy by Greg Davis (www.gregdavispho<strong>to</strong>graphy.com)<br />
115
www.interoil.com