2014

InterOil Announces 2012 Financial And Operating Results

PORT MORESBY, Papua New Guinea and HOUSTON, Feb. 27, 2013 /PRNewswire/ -- InterOil Corporation (NYSE: IOC) (POMSoX:IOC) today announced financial and operating results for the fourth quarter and full year ended December 31, 2012.

Year End 2012 Highlights and Recent Developments

  • During the year, InterOil drilled both the Triceratops-2 and Antelope-3 wells to total depth and completed initial logging and testing. The Triceratops-2 well established the Triceratops field as the third significant discovery to date on the Company's licenses in Papua New Guinea. The Antelope-3 well results compare favourably with the Antelope-1 and Antelope-2 wells. The GLJ Report, prepared by our independent qualified reserves evaluator, effective as of December 31, 2012, indicated a 10% increase to 10.3 trillion cubic feet of gas equivalents (Tcfe) in the gross contingent best case resource estimate on our licenses in PNG compared to the 2011 year-end estimate of GLJ of 9.4 Tcfe.
  • On November 16, 2012, we were notified by the Prime Minister of Papua New Guinea Hon. Peter O'Neill that the National Executive Committee had conditionally approved our LNG development project in the Gulf Province. We believe that this decision clears the way for us to complete the LNG partnering process and proceed with our plans for the development of an LNG plant in the Gulf Province with initial planned output of a minimum of 3.8 million tonnes per annum.
  • Net profit for the quarter ended December 31, 2012 was $18.5 million, which contributed to our achievement of an annual net profit for the year ended December 31, 2012 of $1.6 million. Our comparative profit for the annual period in 2011 was a net profit of $17.7 million. The operating segments of Corporate, Midstream Refining and Downstream collectively returned a net profit for the year of $61.2 million. The development segments of Upstream and Midstream Liquefaction yielded a net loss of $59.6 million.
  • Subsequent to year end, on January 24, 2013, we announced that we have advised parties with which we have been in discussions that the final binding bid solicitation period for the LNG partnering process currently being undertaken will close on February 28, 2013. Our Board of Directors intends to meet our advisors during March 2013 for the purpose of evaluating bids received and selecting our partner(s) for the development of the LNG Project utilizing gas from the Elk and Antelope fields.

InterOil's Chief Executive Officer Phil Mulacek commented, "The recent approval of our 3.8 mtpa LNG project in the Gulf Province by the National Executive Council of PNG paves the way to completing our LNG partnering process, including a sell down of our interest in the Elk and Antelope fields. The success of our delineation drilling at Triceratops and Antelope has positively impacted our 2012 year-end resource estimate. Our prospect inventory is maturing and we anticipate that it will support our goal of a multi-year, multi-well exploration program. I am pleased to confirm that the fifth annual resource evaluation of the Elk and Antelope fields, and our first estimate at the Triceratops field, continues to support our development plans. We look forward to progressing commercialization of these resources. We believe that these achievements, combined with a successful completion of our LNG partnering process, support our continued growth and operational success."

Corporate Financial Results

InterOil recorded a net profit for the year ended December 31, 2012 of $1.6 million, compared with a profit of $17.7 million for the same period in 2011, a decrease of $16.1 million. The operating segments of Corporate, Midstream Refining and Downstream collectively returned a net profit for the year of $61.2 million. The development segments of Upstream and Midstream Liquefaction yielded a net loss of $59.6 million for an aggregate net profit of $1.6 million.

EBITDA for the year ended December 31, 2012 was $35.9 million, a decrease of $14.5 million compared to EBITDA of $50.4 million for the same period in 2011, the decrease was mainly due to a $25.1 million decrease in foreign exchange gain, due to the PGK being relatively stable in the year ended December 31, 2012.

Total revenues for the year ended December 31, 2012 were $1,320.6 million compared with $1,118.9 million and $807.0 million respectively for the same periods in 2011 and 2010. This increase in the year ended 2012 compared to the same period in 2011 was due to higher sales volumes and higher export prices during the period. The total volume of all products sold by us was 8.5 million barrels for fiscal year 2012, compared with 7.4 million barrels in 2011.

Business Segment Results

Upstream – During the year, InterOil drilled and tested the Triceratops-2 well in Petroleum Prospecting License ("PPL") 237 to confirm the presence of gas and condensate, and test for the presence of reefal carbonate reservoir. Following successful flow from DST#9 of 27 MMSCFPD on June 6, 2012, the Triceratops-2 well was declared a discovery on June 14, 2012 by Department of Petroleum and Energy (the "DPE"). Triceratops seismic data indicates there is a large attic in terms of height and areal extent to the south, west and northwest of the Triceratops-2 well, which will be our focus during future seismic acquisition and well programs in this field.

On April 18, 2012, InterOil signed a binding heads of agreement (HOA) with Pacific Rubiales Energy (PRE) for PRE to be able to earn a 10.0% net (12.9% gross) participating interest in the PPL 237 onshore PNG, including the Triceratops structure located within that license. On November 29, 2012, we executed the PRE joint venture operating agreement and related documents associated with the Farm-In Agreement with PRE. Subsequent to year end, on January 24, 2013, the DPE approved and registered the transfer of interest in PPL 237 to PRE. The PPL 237 JV Operating Committee established with PRE will review and approve the forward work program, and submit an application for a PRL over the Triceratops discovery.

During the fourth quarter, InterOil drilled the Antelope-3 well to total depth and completed the initial wireline logging program. The top of the reservoir at the Antelope-3 well was penetrated at a depth of 5,328 feet (1,624 meters). This was 217 feet (66 meters) above the pre-drill estimate and 92 feet (28 meters) higher than the Antelope-1 well. The preliminary independent analysis of the wireline log results demonstrated a carbonate reservoir (limestone and dolomite) with similar reefal reservoir character and quality as the offset Antelope-1 and Antelope-2 wells.

InterOil continued appraising its exploration licenses during the year by acquiring Phase 3 seismic data on PPL 236 in addition to airborne gravity data acquired over PPL 236 and PPL 237. Analysis of the newly acquired gravity data generated additional leads to be assessed for further seismic acquisition. Proposed well locations have currently been selected for Tuna and Wahoo prospects. Given the success of the Triceratops-2 well and the better than expected results of the Antelope-3 well, we have had discussions with the DPE on our future focus and priorities. We believe that a clear mutual objective is to focus on progressing the LNG Project. To progress development of our core assets, we have applied for variations to modify the well commitments for PPL 236 and PPL 238. We are awaiting formal approval of variations in relation to our commitments.

InterOil's Upstream business realized a net loss of $56.8 million in 2012 compared to a loss of $49.1 million in the comparable period a year ago. The increase in the loss in 2012 was mainly due to higher interest expense due to an increase in inter-company loan balance which was partially offset by reduced exploration costs incurred for seismic activity.

InterOil's Annual Information Form includes the details of the independent engineering evaluation prepared by GLJ Petroleum Consultants Ltd. (2012 GLJ Report), which evaluated the Company's contingent resources at the Elk, Antelope and Triceratops fields in Papua New Guinea effective as at December 31, 2012, and was prepared in accordance with the definitions and guidelines in the COGE Handbook and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101).

The 2012 GLJ Report provides a best case estimate of contingent resources of 9.45 trillion cubic feet (Tcf) of natural gas and 143.6 million barrels of condensate (MMBbls), or 10.3 trillion cubic feet of natural gas equivalents (Tcfe).

This compares to GLJ's year-end 2011 best case contingent resources estimate of 8.59 Tcf of natural gas and 128.9 MMBbls of condensate, or 9.4 Tcfe. The 2012 GLJ Report noted an increase of 10%, or 157.8 MMBOE, in the combined gross resource estimate for Elk, Antelope and Triceratops fields from the 2011 year-end estimate of Elk and Antelope fields. All resources estimated in the 2012 GLJ Report are classified as contingent resources – economic status undetermined, as follows:

Total Contingent Resources Estimate for Gas and Condensate for the Elk, Antelope and Triceratops Fields*

As at December 31, 2012

Low

Case

Best

High

Contingent Gas Resources (Tcf)

6.95

9.45

11.75

Contingent Condensate Resources (MMBbls)

114.2

143.6

175.8

Contingent Resources MMBOE

1,273.3

1,718.2

2,134.2

*These estimates represent 100% of the Elk, Antelope and Triceratops Fields.

Contingent Resource Estimate for Gas and Condensate at the Elk, Antelope and Triceratops Fields – Net to InterOil*

As at December 31, 2012

Low

Case

Best

High

Contingent Gas Resources (Tcf)

4.07

5.51

6.84

Contingent Condensate Resources (MMBbls)

66.8

83.7

101.9

Contingent Resources MMBOE

744.8

1,002.8

1,241.2

*These estimates are based upon InterOil holding a 58.5988% working interest in the Elk and Antelope fields and a 53.0364% working interest in PPL 237 (Triceratops field), which assumes that: (i) the State and landowners elect to participate in the Elk and Antelope fields to the full extent provided under applicable PNG oil and gas legislation after PDLs have been granted in relation to the Elk and Antelope fields and the Triceratops field and (ii) all elections are made to participate in such fields by all investors pursuant to relevant indirect participation interest agreements with InterOil, including to participate fully and directly in the PDLs.


There is no certainty that it will be commercially viable to produce any portion of the resources.


InterOil currently has no production or reserves as defined in Canadian NI 51-101 or under the definitions established by the United States Securities and Exchange Commission.

Midstream Refining – Total refinery throughput for the year ended December 31, 2012 was 24,483 barrels per operating day, compared with 24,856 barrels per operating day during 2011. Capacity utilization for 2012, based on 36,500 barrels per day operating capacity, was 58% compared with 54% in 2011.

On October 16, 2012, the Company entered into a five year amortizing $100.0 million secured term loan facility with BNP, BSP, and ANZ. The loan is secured over the fixed assets of our refinery and bears interest at LIBOR plus 6.5%. On November 9, 2012, part of the borrowings under the new term loan facility was used to repay all outstanding amounts under the term loan granted by OPIC.

The Company's Midstream Refining operations generated a net loss of $2.9 million in 2012 versus a profit of $46.7 million in the prior year. The $49.6 million negative variance is primarily due to a decrease in gross margin resulting from negative crude and product price movements and a decrease in foreign exchange gains compared to the previous year, which were partially offset by an increase in income tax benefits for the 2012 year.

Midstream Liquefaction – Throughout the year, investment bankers led by Morgan Stanley & Company LLC, Macquarie Capital (USA) Inc. and UBS AG continued working on the bid process to seek a strategic partner to acquire an interest in the Elk and Antelope fields, the LNG Project and certain exploration licenses. Interested parties include major oil companies, national oil companies, and global utilities.

On November 16, 2012, we were notified by the Prime Minister of Papua New Guinea Hon. Peter O'Neill that the NEC had conditionally approved our LNG development project in the Gulf Province. We believe that this decision clears the way for us to proceed with our plans for the development of an LNG plant in the Gulf Province with initial planned output of a minimum of 3.8 million tonnes per annum. The PNG Cabinet also approved the establishment of the Ministerial Gas Committee comprised of key economic ministers to fast track commercialization of the LNG Project.

Subsequent to year end, on January 24, 2013, we announced that we have advised potential bidders with whom we have been in discussions that the final binding bid solicitation period for the partnering process currently being undertaken will close on February 28, 2013. Our Board of Directors intends to meet our advisors during March 2013 for the purpose of evaluating bids received and selecting our partner(s) for the development of the LNG Project utilizing gas from the Elk and Antelope fields.

The Company's Midstream Liquefaction business generated a loss of $2.8 million in 2012 compared with a loss of $15.5 million a year ago. The positive variance is largely due to a decrease in office, administration and other expenses resulting from lower management expenses and share compensation costs related to the midstream facilities of the LNG Project development which are not capitalized.

Downstream - The PNG economy continued to grow strongly throughout 2012 largely due to resource development projects, which has also led to growth in our aviation and retail businesses within our downstream segment. Total Downstream sales volumes for 2012 were 752.5 million liters, compared with 678.0 million liters in 2011.

Investments have been made over the last three years in new electronic systems for both pumps and the forecourt control units to support the further development of this business. During 2012, one new retail site was opened as well as a commercial truck stop site. One existing retail site was purchased to secure tenure, and additional land was purchased for a future retail site.

InterOil's Downstream operations generated a net profit of $32.6 million in 2012, an improvement of $21.0 million versus a profit of $11.6 million in the previous year. Gross margins increased in 2012 as compared to the prior year mainly due to an increase in domestic sales volumes resulting from various development projects being undertaken in Papua New Guinea.

Corporate – InterOil Corporate PNG Limited is incorporated under the laws of PNG, as a 100% subsidiary of InterOil Corporation to employ all corporate staff in PNG and to capture their associated costs. In addition, this entity has taken over the operation of the Napa Napa camp and all costs associated with the operation of the camp are now captured in this entity. All costs incurred by this entity will be recharged to relevant InterOil entities based on an equitable driver basis. This entity began transacting in October 2012.

The Corporate segment generated a net profit of $33.1 million in 2012, compared to a net profit of $21.9 million in 2011. The positive variance is largely due to higher interest income resulting from an increase in inter-company loan balances.

Quarterly Comparative

Our net profit for the quarter ended December 31, 2012 was $18.5 million compared with a net profit of $13.2 million for the same quarter of 2011, an increase of $5.3 million. The operating segments of Corporate, Midstream Refining and Downstream collectively derived a net profit for the quarter of $32.0 million, while the investments in development segments of Upstream and Midstream Liquefaction resulted in a net loss of $13.5 million.

The improvement in net profit for the fourth quarter in 2012 as compared to 2011 was mainly due to a $26.0 million increase in gross margin attributable to the improved crude and product price movements, a $2.6 million reduction of exploration costs incurred for seismic activity for PPL 236; a $1.6 million decrease in the loss on available-for-sale investment in the shares in FLEX LNG, and a $1.6 million increase in gain on conveyance of oil and gas properties recognized due to the waiver or forfeiture of 1.5% indirect participation interest (IPI) interest conversion rights into common shares. These increases in profit was partly offset by a $11.4 million reduction in foreign exchange gain, a $9.5 million increase in borrowing costs and a $6.0 million decrease in income tax benefit.

Total revenues increased by $66.8 million from $289.6 million in the quarter ended December 31, 2011 to $356.4 million in the quarter ended December 31, 2012, primarily due to higher sales volumes made during the year. The total volume of all products sold by us was 2.3 million barrels for quarter ended December 31, 2012, compared with 1.9 million barrels in the same quarter of 2011.

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

Quarters ended
($ thousands except per share data)

2012

2011

Dec-31

Sep-30

Jun-30

Mar-31

Dec-31

Sep-30

Jun-30

Mar-31

Upstream

4,136

2,216

1,727

2,284

1,891

2,645

4,638

668

Midstream – Refining

301,925

274,671

236,006

302,310

237,640

231,455

262,111

217,743

Midstream – Liquefaction

-

-

-

-

-

-

-

-

Downstream

220,512

201,749

223,620

218,974

209,678

186,304

191,431

157,709

Corporate

37,552

26,880

24,742

24,757

21,831

25,078

26,548

18,659

Consolidation entries

(207,686)

(178,652)

(186,991)

(210,174)

(181,428)

(163,584)

(180,945)

(151,125)

Total revenues

356,439

326,864

299,104

338,151

289,612

281,898

303,783

243,654

Upstream

(873)

956

(5,730)

(6,374)

665

(6,169)

593

(10,957)

Midstream – Refining

12,370

13,417

(42,647)

18,933

2,604

3,461

27,967

26,632

Midstream – Liquefaction

192

11

676

(1,406)

(4,123)

(3,602)

(4,035)

(2,375)

Downstream

12,258

9,275

11,102

21,414

6,808

3,570

5,777

8,744

Corporate

14,133

9,841

9,975

9,188

10,134

1,548

13,940

5,223

Consolidation entries

(12,199)

(14,503)

(9,871)

(14,216)

(11,280)

(10,263)

(5,269)

(9,200)

EBITDA (1)

25,881

18,997

(36,495)

27,539

4,808

(11,455)

38,973

18,067

Upstream

(13,081)

(10,936)

(15,532)

(17,244)

(9,402)

(15,080)

(6,703)

(17,949)

Midstream – Refining

13,401

5,358

(32,969)

11,320

15,684

(1,201)

17,314

14,894

Midstream – Liquefaction

(394)

(573)

93

(1,969)

(4,574)

(3,980)

(4,309)

(2,604)

Downstream

7,716

5,626

6,045

13,195

3,621

1,146

2,306

4,491

Corporate

10,519

7,849

8,445

6,270

7,616

(473)

11,275

3,463

Consolidation entries

384

(1,988)

2,205

(2,136)

252

(190)

3,657

(1,596)

Net profit/(loss)

18,545

5,336

(31,713)

9,436

13,197

(19,778)

23,540

699

Net profit/(loss) per share (dollars)









Per Share – Basic

0.38

0.11

(0.66)

0.20

0.27

(0.41)

0.49

0.01

Per Share – Diluted

0.38

0.11

(0.66)

0.19

0.27

(0.41)

0.48

0.01

(1) EBITDA is a non-GAAP measure, please refer to "Non-GAAP EBITDA Reconciliation" in this press release.

Balance Sheet and Liquidity

InterOil closed 2012 with cash, cash equivalents and cash restricted totaling $98.9 million
(December 2011 - $108.1 million), of which $49.0 million is restricted (December 2010 - $39.3 million).

We also had aggregate working capital facilities of $307.3 million, with $6.2 million available for use in our Midstream Refining operations, and $67.3 million available for use in our Downstream operations.

The Company is managing its gearing levels by maintaining the debt-to-capital ratio (debt/(shareholders' equity + debt)) at 50% or less. Our debt-to-capital ratio was 19% in December 2012 from 12% in December 2011.

InterOil has no obligation to execute exploration activities within a set timeframe and therefore has the ability to select the timing of these activities as long as the minimum license commitments in relation to the Company's PPLs and Petroleum Retention Licenses ("PRL") are met. Additionally, we have applied for variations to modify the well commitments for PPL 236 and PPL 238. We are awaiting formal approval of variations in relation to our commitments.

Summary of Debt Facilities

Summarized below are the debt facilities available to us and the balances outstanding as at December 31, 2012.

Organization

Facility

Balance outstanding

December 31, 2012

Effective interest rate

Maturity date

ANZ, BSP and BNP syndicated secured loan facility

$100,000,000

$100,000,000

6.81%

November 2017

BNP working capital facility

$240,000,000

$94,290,479(1)

2.67%

See detail below(4)

Westpac PGK working capital facility

facility

$43,245,000

-

-

November 2014

BSP PGK working capital facility

$24,025,000

-

-

August 2013

Westpac secured loan

$12,857,000

$12,857,000

4.73%

September 2015

2.75% convertible notes

$70,000,000

$70,000,000

7.91%(3)

November 2015

Mitsui unsecured loan (2)

$11,912,297

$11,912,297

6.24%

See detail below

(1)

Excludes letters of credit totaling $139.5 million, which reduces the available borrowings under the facility to $6.2 million at December 31, 2012.

(2)

Facility is to fund our share of the Condensate Stripping Project costs as they are incurred pursuant to the CSP JVOA with Mitsui.

(3)

Effective rate after bifurcating the equity and debt components of the $70 million principal amount of 2.75% convertible senior notes due 2015.

(4)

In October 2012, the BNP Paribas working capital facility agreement with a maximum availability of $240,000,000 was amended so that the facility was made evergreen and the annual renewal requirement removed.

NON-GAAP EBITDA Reconciliation

EBITDA represents our net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is used by us to analyze operating performance. EBITDA does not have a standardized meaning prescribed by GAAP (i.e., IFRS) and, therefore, may not be comparable with the calculation of similar measures for other companies. The items excluded from EBITDA are significant in assessing our operating results. Therefore, EBITDA should not be considered in isolation or as an alternative to net earnings, operating profit, net cash provided from operating activities and other measures of financial performance prepared in accordance with IFRS. Further, EBITDA is not a measure of cash flow under IFRS and should not be considered as such. For reconciliation of EBITDA to the net income (loss) under IFRS, refer to the following table.

The following table reconciles net income (loss), a GAAP measure, to EBITDA, a non-GAAP measure for each of the last eight quarters. Our IFRS transition date was January 1, 2010 and as such, the 2010 comparative information has been restated in accordance with IFRS.

Quarters ended
($ thousands)

2012

2011

Dec-31

Sep-30

Jun-30

Mar-31

Dec-31

Sep-30

Jun-30

Mar-31

Upstream

(873)

956

(5,730)

(6,374)

665

(6,169)

593

(10,957)

Midstream – Refining

12,370

13,417

(42,647)

18,933

2,604

3,461

27,967

26,632

Midstream – Liquefaction

192

11

676

(1,406)

(4,123)

(3,602)

(4,035)

(2,375)

Downstream

12,258

9,275

11,102

21,414

6,808

3,570

5,777

8,744

Corporate

14,133

9,841

9,975

9,188

10,134

1,548

13,940

5,223

Consolidation Entries

(12,199)

(14,503)

(9,871)

(14,214)

(11,280)

(10,263)

(5,270)

(9,200)

Earnings before interest, taxes, depreciation and amortization

25,881

18,997

(36,495)

27,541

4,808

(11,455)

38,972

18,067

Subtract:









Upstream

(11,734)

(11,438)

(10,517)

(9,408)

(8,712)

(7,806)

(7,142)

(6,352)

Midstream – Refining

(11,390)

(1,654)

(2,011)

(2,771)

(3,285)

(2,494)

(2,211)

(1,675)

Midstream – Liquefaction

(586)

(584)

(579)

(559)

(445)

(372)

(268)

(223)

Downstream

(337)

(394)

(909)

(1,233)

(1,170)

(1,233)

(1,116)

(826)

Corporate

(1,601)

(1,540)

(1,535)

(1,510)

(1,498)

(1,477)

(1,641)

(1,395)

Consolidation Entries

12,552

12,482

12,044

12,045

11,500

10,041

8,894

7,572

Interest expense

(13,096)

(3,128)

(3,507)

(3,436)

(3,610)

(3,341)

(3,484)

(2,899)

Upstream

-

-

-

-

-

-

-

-

Midstream – Refining

16,574

(3,484)

14,580

(1,948)

19,243

678

(5,677)

(7,298)

Midstream – Liquefaction

-

-

-

-

-

-

-

-

Downstream

(3,070)

(1,791)

(2,907)

(5,746)

(595)

(297)

(1,449)

(2,623)

Corporate

(1,330)

177

535

(880)

(493)

(195)

(629)

71

Consolidation Entries

-

-

-

-

-

-

-

-

Income taxes

12,174

(5,098)

12,208

(8,574)

18,155

186

(7,755)

(9,850)

Upstream

(474)

(454)

715

(1,462)

(1,355)

(1,105)

(154)

(641)

Midstream – Refining

(4,153)

(2,921)

(2,891)

(2,894)

(2,878)

(2,846)

(2,764)

(2,765)

Midstream – Liquefaction

0

0

(4)

(4)

(6)

(6)

(6)

(6)

Downstream

(1,135)

(1,464)

(1,241)

(1,240)

(1,422)

(894)

(906)

(804)

Corporate

(683)

(629)

(530)

(528)

(527)

(349)

(395)

(435)

Consolidation Entries

31

33

32

33

32

32

32

32

Depreciation and amortisation

(6,414)

(5,435)

(3,919)

(6,095)

(6,156)

(5,168)

(4,193)

(4,619)

Upstream

(13,081)

(10,936)

(15,532)

(17,244)

(9,402)

(15,080)

(6,703)

(17,949)

Midstream – Refining

13,401

5,358

(32,969)

11,320

15,684

(1,201)

17,314

14,894

Midstream – Liquefaction

(394)

(573)

93

(1,969)

(4,574)

(3,980)

(4,309)

(2,604)

Downstream

7,716

5,626

6,045

13,195

3,621

1,146

2,306

4,491

Corporate

10,519

7,849

8,445

6,270

7,616

(473)

11,275

3,463

Consolidation Entries

384

(1,988)

2,205

(2,136)

252

(190)

3,657

(1,596)

Net profit/(loss) per segment

18,545

5,336

(31,713)

9,436

13,197

(19,778)

23,540

699

InterOil Corporation

Consolidated Income Statements

(Expressed in United States dollars)


















Year ended


December 31,

December 31,

December 31,


2012

2011

2010


$

$

$





Revenue




Sales and operating revenues

1,308,051,816

1,106,533,853

802,374,399

Interest

248,261

1,356,124

150,816

Other

12,257,833

11,058,090

4,470,048


1,320,557,910

1,118,948,067

806,995,263





Changes in inventories of finished goods and work in progress

23,799,540

43,934,439

57,010,311

Raw materials and consumables used

(1,242,987,054)

(1,064,866,361)

(758,566,961)

Administrative and general expenses

(40,825,612)

(41,160,824)

(41,047,949)

Derivative (losses)/gains (note 9)

(4,229,190)

2,006,321

(1,065,188)

Legal and professional fees

(5,418,210)

(6,801,334)

(6,902,241)

Exploration costs, excluding exploration impairment (note 14)

(13,901,558)

(18,435,150)

(16,981,929)

Finance costs

(28,614,981)

(18,163,769)

(12,064,982)

Depreciation and amortization

(21,863,367)

(20,136,649)

(14,274,922)

Gain on conveyance of oil and gas properties (note 14)

4,418,170

-

2,140,783

Loss on extinguishment of liability

-

-

(30,568,710)

Litigation settlement expense

-

-

(12,000,000)

Loss on available-for-sale investment

-

(3,420,406)

-

Foreign exchange (losses)/gains

(43,148)

25,018,661

(10,776,823)


(1,329,665,410)

(1,102,025,072)

(845,098,611)

(Loss)/profit before income taxes

(9,107,500)

16,922,995

(38,103,348)





Income taxes




Current tax expense (note 16)

(15,883,469)

(5,512,842)

(3,898,067)

Deferred tax benefit/(expense) (note 16)

26,594,678

6,248,509

(2,511,656)


10,711,209

735,667

(6,409,723)





Profit/(loss) for the period

1,603,709

17,658,662

(44,513,071)





Profit/(loss) is attributable to:




Owners of InterOil Corporation

1,603,709

17,652,461

(44,519,573)

Non-controlling interest

-

6,201

6,502


1,603,709

17,658,662

(44,513,071)





Basic profit/(loss) per share

0.03

0.37

(1.00)

Diluted profit/(loss) per share

0.03

0.36

(1.00)

Weighted average number of common shares outstanding




Basic (Expressed in number of common shares)

48,352,822

47,977,478

44,329,670

Diluted (Expressed in number of common shares)

49,357,256

49,214,190

44,329,670





See accompanying notes to the consolidated financial statements

InterOil Corporation

Consolidated Balance Sheets

(Expressed in United States dollars)



















As at














December 31,

December 31,

December 31,



2012

2011

2010



$

$

$







Assets





Current assets:





Cash and cash equivalents (note 6)

49,860,044

68,846,441

233,576,821


Cash restricted (note 9)

37,340,631

32,982,001

40,664,995


Short term treasury bills - held-to-maturity (note 8)

-

11,832,110

-


Trade and other receivables (note 10)

146,948,227

135,273,600

48,047,496


Derivative financial instruments (note 9)

233,922

595,440

-


Other current assets

832,936

867,967

505,059


Inventories (note 11)

194,871,339

171,071,799

127,137,360


Prepaid expenses

8,517,340

5,477,596

3,593,574


Total current assets

438,604,439

426,946,954

453,525,305


Non-current assets:





Cash restricted (note 9)

11,670,463

6,268,762

6,613,074


Goodwill (note 12)

6,626,317

6,626,317

6,626,317


Plant and equipment (note 13)

255,031,703

246,043,948

225,205,427


Oil and gas properties (note 14)

515,055,288

362,852,766

255,294,738


Deferred tax assets (note 16)

63,526,458

35,965,273

28,477,690


Other non-current receivables (note 22)

5,000,000

-

-


Available-for-sale investments (note 15)

4,304,176

3,650,786

-


Total non-current assets

861,214,405

661,407,852

522,217,246


Total assets

1,299,818,844

1,088,354,806

975,742,551


Liabilities and shareholders' equity





Current liabilities:





Trade and other payables (note 17)

180,026,381

159,882,177

75,132,880


Income tax payable

11,977,681

4,085,137

955,074


Derivative financial instruments (note 9)

-

11,457

178,578


Working capital facilities (note 18)

94,290,479

16,480,503

51,254,326


Unsecured loan and current portion of secured loans (note 19)

31,383,115

19,393,023

14,456,757


Current portion of Indirect participation interest (note 20)

15,246,397

540,002

540,002


Total current liabilities

332,924,053

200,392,299

142,517,617


Non-current liabilities:





Secured loans (note 19)

89,446,137

26,037,166

34,813,222


2.75% convertible notes liability (note 26)

59,046,581

55,637,630

52,425,489


Deferred gain on contributions to LNG project (note 21)

-

5,810,775

8,949,857


Indirect participation interest (note 20)

16,405,393

34,134,840

34,134,387


Other non-current liabilities (note 22)

20,961,380

-

-


Asset retirement obligations (note 23)

4,978,334

4,562,269

-


Deferred tax liabilities (note 16)

-

1,889,391

-


Total non-current liabilities

190,837,825

128,072,071

130,322,955


Total liabilities

523,761,878

328,464,370

272,840,572


Equity:





Equity attributable to owners of InterOil Corporation:





Share capital (note 25)

928,659,756

905,981,614

895,651,052


Authorized - unlimited





Issued and outstanding - 48,607,398





(Dec 31, 2011 - 48,121,071)





(Dec 31, 2010 - 47,800,552)





2.75% convertible notes (note 26)

14,298,036

14,298,036

14,298,036


Contributed surplus (note 27)

21,876,853

25,644,245

16,738,417


Accumulated Other Comprehensive Income

25,032,953

29,380,882

9,261,177


Conversion options (note 20)

12,150,880

12,150,880

12,150,880


Accumulated deficit

(225,961,512)

(227,565,221)

(245,217,682)


Total equity attributable to owners of InterOil Corporation

776,056,966

759,890,436

702,881,880


Non-controlling interest (note 24)

-

-

20,099


Total equity

776,056,966

759,890,436

702,901,979


Total liabilities and equity

1,299,818,844

1,088,354,806

975,742,551

See accompanying notes to the consolidated financial statements

InterOil Corporation

Consolidated Statements of Cash Flows

(Expressed in United States dollars)














Year ended


December 31,

December 31,

December 31,


2012

2011

2010


$

$ (revised)

$ (revised)





Cash flows generated from (used in):








Operating activities




Net profit/(loss) for the period

1,603,709

17,658,662

(44,513,071)

Adjustments for non-cash and non-operating transactions




Depreciation and amortization

21,863,367

20,136,649

14,274,922

Deferred tax

(29,450,576)

(5,598,192)

1,841,473

Gain on conveyance of exploration assets

(4,418,170)

-

(2,140,783)

Accretion of convertible notes liability

3,408,951

3,212,141

432,632

Amortization of deferred financing costs

598,698

223,944

1,223,944

Timing difference between derivatives recognized




and settled

350,061

(762,561)

178,578

Stock compensation expense, including restricted stock

7,882,067

14,721,387

11,804,000

Inventory write down

322,535

259,406

-

Accretion of asset retirement obligation liability

331,096

159,356

-

Loss on extinguishment of IPI Liability

-

-

30,568,710

Non-cash litigation settlement expense

-

-

12,000,000

Loss on Flex LNG investment

-

3,420,406

-

Gain on proportionate consolidation of LNG project

-

(555,030)

-

Unrealized foreign exchange gain

(1,070,269)

(2,618,814)

(72,456)

Change in operating working capital




Increase in trade and other receivables

(31,472,316)

(53,064,305)

(9,224,005)

(Increase)/decrease in other current assets and prepaid expenses

(3,004,713)

(2,246,930)

3,505,963

Increase in inventories

(28,886,641)

(28,003,484)

(56,115,637)

Increase in trade and other payables

25,912,734

77,291,915

5,692,543

Net cash (used in)/generated from operating activities

(36,029,467)

44,234,550

(30,543,187)





Investing activities




Expenditure on oil and gas properties

(184,165,722)

(116,492,551)

(96,146,987)

Proceeds from IPI cash calls

3,497,542

749,794

23,723,752

Expenditure on plant and equipment

(36,661,897)

(42,050,435)

(22,560,055)

Proceeds received on sale of exploration assets

-

-

15,544,465

Proceeds from Pacific Rubiales Energy (conveyance accounted portion)

20,000,000

-

-

Maturity of/(investment in) short term treasury bills

11,832,110

(11,832,110)

-

Acquisition of Flex LNG Ltd shares, including transaction costs

-

(7,478,756)

-

(Increase)/decrease in restricted cash held as security on borrowings

(9,760,331)

8,027,306

(17,969,494)

Change in non-operating working capital




Decrease/(increase) in trade and other receivables

5,000,000

(10,000,000)

-

Increase/(decrease) in trade and other payables

20,545,509

(6,727,960)

3,232,029

Net cash used in investing activities

(169,712,789)

(185,804,712)

(94,176,290)





Financing activities




Repayments of OPIC secured loan

(35,500,000)

(9,000,000)

(9,000,000)

Proceeds from Mitsui for Condensate Stripping Plant

3,578,489

9,872,532

11,913,514

Proceeds from/(repayments of) Clarion Finanz secured loan, net of transaction costs

-

-

(1,000,000)

Proceeds from Westpac secured loan

15,000,000

-

-

Repayments of Westpac secured loan

(2,143,000)

-

-

Proceeds from PNG LNG cash call

-

2,247,533

866,600

Proceeds from Pacific Rubiales Energy for interest in PPL237

20,000,000

-

-

Proceeds from Petromin for Elk and Antelope field development

-

-

5,000,000

Proceeds from/(repayments of) working capital facility

77,809,976

(34,773,823)

26,627,907

Proceeds from ANZ, BSP & BNP syndicated loan (net of transaction costs)

95,924,091

-

-

Proceeds from issue of common shares, net of transaction costs

11,028,683

4,488,703

211,147,565

Proceeds from issue of convertible notes, net of transaction costs

-

-

66,290,893

Net cash generated from/(used in) financing activities

185,698,239

(27,165,055)

311,846,479





(Decrease)/increase in cash and cash equivalents

(20,044,017)

(168,735,217)

187,127,002

Cash and cash equivalents, beginning of period

68,846,441

233,576,821

46,449,819

Exchange gains on cash and cash equivalents

1,057,620

4,004,837

-

Cash and cash equivalents, end of period

49,860,044

68,846,441

233,576,821

Comprising of:




Cash on Deposit

49,225,717

18,758,288

233,576,821

Term Deposits

634,327

50,088,153

-

Total cash and cash equivalents, end of period

49,860,044

68,846,441

233,576,821





See accompanying notes to the consolidated financial statements

About InterOil

InterOil Corporation is developing a vertically integrated energy business whose primary focus is Papua New Guinea and the surrounding region. InterOil's assets consist of petroleum licenses c overing about 3.9 million acres, an oil refinery, and retail and commercial distribution facilities, all located in Papua New Guinea. In addition, InterOil is a shareholder in a joint venture established to construct an LNG plant in Papua New Guinea. InterOil's common shares trade on the NYSE in US dollars.

Investor Contacts for InterOil:

Wayne Andrews

Meg LaSalle

V. P. Capital Markets

Investor Relations Coordinator

Wayne.Andrews@InterOil.com

Meg.LaSalle@InterOil.com

The Woodlands, TX USA

The Woodlands, TX USA

Phone: +1-281-292-1800

Phone:+1-281-292-1800

Forward Looking Statements

This press release includes "forward-looking statements" as defined in United States federal and Canadian securities laws. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the InterOil expects, believes or anticipates will or may occur in the future are forward-looking statements, including in particular further seismic-related exploration activities, development activities, the ability to attract a strategic LNG partner and complete the LNG partnering process and the timing of such process, the construction and development of the proposed LNG project, the characteristics of our properties, the ability to commercially develop our resources, anticipated financial conditions and performance, business prospects, strategies, regulatory developments, the ability to obtain financing on acceptable terms, the ability to identify drilling locations and the ability to develop reserves and production through development and exploration activities. Statements relating to 'resources' are forward looking, as they involve the applied assessment, based on certain estimates and assumptions, that the resources described exist in the quantities estimated. These statements are based on certain assumptions made by the Company based on its experience and perception of current conditions, expected future developments, the terms of agreements with its joint venture partners and other factors it believes are appropriate in the circumstances. No assurances can be given however, that these events will occur. Actual results will differ, and the difference may be material and adverse to the Company and its shareholders. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause our actual results to differ materially from those implied or expressed by the forward-looking statements. Some of these factors include the risk factors discussed in the Company's filings with the Securities and Exchange Commission and on SEDAR, including but not limited to those in the Company's Annual Report for the year ended December 31, 2012 on Form 40-F and its Annual Information Form for the year ended December 31, 2012. In particular, there is no established market for natural gas or gas condensate in Papua New Guinea and no guarantee that gas or gas condensate from the Elk and Antelope fields will ultimately be able to be extracted and sold commercially.

Investors are urged to consider closely the disclosure in the Company's Form 40-F, available from us at www.interoil.com or from the SEC at www.sec.gov and its Annual Information Form available on SEDAR at www.sedar.com.

Oil and Gas and Resource Information

InterOil currently has no production or reserves as defined in Canadian NI 51-101 or under the definitions established by the United States Securities and Exchange Commission.

The resources information set forth in this press release is based on the 2012 GLJ Report, which was prepared in accordance with NI 51-101 and is included in InterOil's annual information form for the year ended December 31, 2012, a copy of which has been filed on SEDAR (www.SEDAR.com) and on InterOil's website (www.interoil.com).

Contingent resources are those quantities of natural gas and condensate estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. The economic status of the resources is undetermined and there is no certainty that it will be commercially viable to produce any portion of the resources. The following contingencies must be met before the resources can be classified as reserves: (i) sanctioning of the facilities required to process and transport marketable natural gas to market, (ii) confirmation of a market for the marketable natural gas and condensate and (iii) determination of economic viability. Although a final project has not yet been sanctioned, pre-FEED studies are ongoing for the LNG Project and FEED studies conducted for the Condensate Stripping Project as options for potential monetization of the gas and condensate.

The "low" estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. With the probabilistic methods used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. The "best" estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. With the probabilistic methods used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. The "high" estimate is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. With the probabilistic methods used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

The accuracy of resource estimates is in part a function of the quality and quantity of the available data and of engineering and geological interpretation and judgment. Other factors in the classification as a resource include a requirement for more delineation wells, detailed design estimates and near term development plans. The size of the resource estimate could be positively impacted, potentially in a material amount, if additional delineation wells determined that the aerial extent, reservoir quality and/or the thickness of the reservoir is larger than what is currently estimated based on the interpretation of the seismic and well data. The size of the resource estimate could be negatively impacted, potentially in a material amount, if additional delineation wells determined that the aerial extent, reservoir quality and/or the thickness of the reservoir are less than what is currently estimated based on the interpretation of the seismic and well data.

All calculations converting natural gas to crude oil equivalent have been made using a ratio of six mcf of natural gas to one barrel of crude equivalent. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf of natural gas to one barrel of crude oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.



SOURCE InterOil Corporation



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