InterOil Corporation Management Discussion and Analysis | ![]() | |
For the Year Ended December 31, 2007 March 28, 2008 |
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The following Management’s Discussion and Analysis (MD&A) should be read in conjunction with InterOil’s audited consolidated financial statements and notes for the year ended December 31, 2007 and annual information form in the year ended December 31, 2007. The MD&A was prepared by the management of InterOil and provides a review of our performance in the year ended December 31, 2007 and our financial condition and future prospects.
Our financial statements and the financial information contained in this MD&A have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) and are presented in United States dollars (USD) unless otherwise specified. References to “we,” “us,” “our,” “Company,” and “InterOil” refer to InterOil Corporation and/or InterOil Corporation and its subsidiaries as the context requires. All dollar amounts are stated in United States dollars unless otherwise specified. Information presented in this MD&A is as at December 31, 2007 unless otherwise specified.
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LEGAL NOTICE – RISK FACTORS AND FORWARD-LOOKING STATEMENTS
This MD&A contains “forward-looking statements” as defined in U.S. federal and Canadian securities laws. Such statements are generally identifiable by the terminology used, such as “may,” “plans,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “forecasts,” “budgets,” “targets” or other similar wording suggesting future outcomes or statements regarding an outlook. We have based these forward-looking statements on our current expectations and projections about future events. All statements, other than statements of historical fact, included in or incorporated by reference in this MD&A are forward-looking statements. Forward-looking statements include, without limitation, statements regarding our plans for our exploration activities and other business segments and results therefrom, expanding our business segments, operating costs, business strategy, contingent liabilities, environmental matters, and plans and objectives for future operations, the timing, maturity and amount of future capital and other expenditures.
Many risks and uncertainties may impact the matters addressed in these forward-looking statements, including but not limited to:
• | the inherent uncertainty of oil and gas exploration activities; | ||
• | the uncertain outcome of our negotiations with the Papua New Guinea government to determine the price at which our refined products may be sold; | ||
• | the availability of crude feedstock at economic rates; | ||
• | uncertainty in our ability to attract capital; | ||
• | refinancing risk; | ||
• | interest rate risk; | ||
• | general economic conditions and illiquidity in the credit markets; | ||
• | the recruitment and retention of qualified personnel; | ||
• | the availability and cost of drilling rigs, oilfield equipment, and other oilfield exploration services; | ||
• | our ability to finance the development of our LNG facility; | ||
• | our ability to timely construct and commission our LNG facility; | ||
• | political, legal and economic risks in Papua New Guinea; | ||
• | our ability to renew our petroleum licenses; | ||
• | landowner claims; | ||
• | the uncertainty in being successful in pending lawsuits and other proceedings; | ||
• | compliance with and changes in foreign governmental laws and regulations, including environmental laws; | ||
• | the inability of our refinery to operate at full capacity; | ||
• | difficulties in marketing our refinery’s output; | ||
• | exposure to certain uninsured risks stemming from our refining operations; | ||
• | weather conditions and unforeseen operating hazards; | ||
• | losses from our hedging activities; | ||
• | the impact of competition; | ||
• | the impact of legislation regulating emissions of greenhouse gases on current and potential markets for our products; and | ||
• | fluctuations in currency exchange rates. |
Forward-looking statements and information are based on our current beliefs as well as assumptions made by, and information currently available to, us concerning anticipated financial performance, business prospects, strategies, regulatory developments, future oil and natural gas commodity prices, the ability to obtain equipment in a timely manner to carry out development activities, the ability to market products successfully to current and new customers, the impact of increasing competition, the ability to obtain financing on acceptable terms, and the ability to develop production and reserves through development and exploration activities. Although we consider these assumptions to be reasonable based on information currently available to us, they may prove to be incorrect.
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this MD&A will prove to be accurate. In light of the significant uncertainties inherent in our forward-looking statements, the inclusion of such information should not be regarded as a representation by us or any other person that our objectives and plans will be achieved. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the heading “Risk Factors” in the AIF.
Furthermore, the forward-looking information contained in this MD&A is made as of the date hereof, unless otherwise specified and, except as required by applicable law, we have no obligation to update publicly or to revise any of this forward-looking information. The forward-looking information contained in this report is expressly qualified by this cautionary statement.
We currently have no production reserves or resources as defined in Canadian National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. All information contained in this MD&A regarding resources are references to undiscovered resources under Canadian National Instrument 51-101, whether stated or not.
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INDUSTRY TRENDS
Competitive Environment and Regulated Pricing
InterOil is currently the sole refiner of hydrocarbons in Papua New Guinea under our 30 year agreement with the Papua New Guinea Government, which terminates in 2035. The government has undertaken to ensure that all domestic distributors purchase their refined petroleum product needs from the refinery, or any refinery which is constructed in Papua New Guinea, at an Import Parity Price (IPP). The basis of calculating IPP price was revised on November 30, 2007 by an interim agreement which more closely mirrors changes in the costs of crude feedstocks that the previous pricing formula. A final agreement on the revised IPP formula is expected to be reached upon completion of an independent review which is to be conducted by a jointly appointed industry expert. The IPP is regulated by the Papua New Guinea Independent Consumer and Competition Commission (ICCC).
InterOil is a significant participant in the retail and wholesale distribution business in Papua New Guinea which was built from the BP’s Papua New Guinea distribution assets. The addition of the Shell’s Papua New Guinea distribution assets was effected on October 1, 2006. InterOil’s major competitor in the distribution segment is Mobil who InterOil believes controls approximately a quarter of the Papua New Guinea retail market. The ICCC regulates the maximum margins that may be charged by the wholesale and retail hydrocarbon distribution industry in Papua New Guinea. Our Downstream business may charge less than the maximum margin set by the ICCC in order to maintain its competitiveness with other participants in the market.
Interest Rates
The LIBOR USD overnight rate is the benchmark floating rate used in our midstream working capital facility and therefore accounts for a significant amount of the Company’s interest rate exposure.
The LIBOR USD overnight rate has decreased from around 5.3% to around 4.3% during 2007 in line with the underlying Federal Reserve rate cuts. Any rate increases add additional cost to financing our crude cargoes whereas any rate decreases reduce the cost to finance crude cargoes. In 2008, InterOil believes that underlying interest rates will be more likely to fall, though volatility in LIBOR rates may remain a significant factor.
Skill and Resource Scarcity
Although all key positions with the Company are filled, we have generally been faced with a shortage of skilled labor to work in our business. Our success depends in large part on the continued services of our executive officers, our senior managers and other key technical personnel. Competition for qualified personnel can be intense and recruitment difficult. There are a limited number of people with the requisite knowledge and experience.
Crude Prices
Crude prices been volatile and have increased markedly throughout the year. The price of Tapis crude oil, as quoted by the Asian Petroleum Price Index (APPI), is a benchmark for setting crude prices within the region where we operate and is used by us when we purchase crude feedstock for our refinery. The price of Tapis during 2007 averaged $76.89 per barrel compared to $68.15 per barrel during 2006. The Tapis monthly average for January 2007 was at 19 month low at $53.69 per barrel. Throughout 2007, the Tapis benchmark increased significantly, with December 2007 being the highest monthly average on record at $100.85.
Refining Margin
The interim benchmark price for refined products in the region in which we operate is the average spot price quotations for refined products from Singapore as reported by Platts. This benchmark, the Mean of Platts Singapore, is commonly referred to as the MOPS price for the relevant refined product.
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The distillation process our refinery uses to convert crude feedstocks into refined products is commonly referred to as hydroskimming. While the Singapore Tapis hydroskimming margin is a useful indicator of the general margin available for hydroskimming refineries in the region in which we operate, it should be noted that the differences in our approach to crude selection, transportation costs and IPP pricing work to assist our refinery in outperforming the Singapore Tapis hydroskimming margin. Therefore, our refinery realizes additional margins due to its niche location when compared to the benchmark for the region.
Singapore Tapis hydroskimming margins have reduced in volatility during 2007 when compared with 2006, while average margins have remained relatively similar. We believe that hydroskimming margins will continue to remain volatile given oil pricing uncertainty.
Exchange Rates
Changes in the Papua New Guinea Kina (PGK) to United States dollar (USD) exchange rate can affect our Midstream refinery results as there is a timing difference between the foreign exchange rates utilized when setting the monthly PGK IPP price and the foreign exchange rate used to convert the subsequent receipt of PGK proceeds to USD to repay our crude cargo borrowings. The PGK generally strengthened against the USD during 2007 (from 0.3300 to 0.3525).
Domestic Demand
Sales results for our Midstream refinery indicate that domestic demand for middle distillates has increased by 2% during 2007 compared with 2006. However, certain volumes of such products have been imported rather than supplied from the refinery, as has occurred in previous years.
The refinery on average sold 12,100 bbls/day of refined petroleum products to the domestic market during the second half of 2007 as compared to 11,900 bbls/day in the second half of 2006.
The majority of the demand increase was driven by the growing investment in the resource sector of Papua New Guinea. We expect this trend to continue into 2008.
Impact of Key Factors on Earnings
The following table shows the estimated after-tax effects that changes in certain factors would have on InterOil’s 2007 net earnings from continuing operations had these changes occurred.
Annual Net Earnings Impact | ||||||||||||
Factor(1)(2) | Change (+) | (thousands of dollars) | ($/share)(3) | |||||||||
Change in domestic demand | 1 | % | 379 | 0.01 | ||||||||
Change in hydro-skimming margin | $1.00/bbl | 6,685 | 0.22 | |||||||||
Change in ICCC pricing margin for retail and distribution business | 0.01 PGK/litre | 1,424 | 0.05 | |||||||||
Change in LIBOR rate | 1 | % | 389 | 0.01 |
(1) | The impact of a change in one factor may be compounded or offset by changes in other factors. This table does not consider the impact of any inter-relationship among the factors. | |
(2) | The impact of these factors is illustrative and based on sales and borrowings made during the 2007 year. | |
(3) | Per share amounts are based on the number of basic shares outstanding at December 31, 2007. |
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RISK MANAGEMENT
InterOil’s business operations and financial position are subject to a range of risks. These risk factors can be found under the heading “Risk Factors” in our 2007 Annual Information Form available at www.sedar.com.
BUSINESS STRATEGY
InterOil’s strategy is to develop a vertically integrated energy company in Papua New Guinea and surrounding regions, focusing on niche market opportunities which provide financial rewards for InterOil shareholders, while being environmentally responsible, providing a quality working environment and contributing value to the communities in which InterOil operates. InterOil has taken a three-pronged approach when planning to achieve this strategy by :-
1. | capitalizing on and expanding on existing business assets, | ||
2. | targeted acquisitions and growth opportunities in Papua New Guinea and the surrounding regions, | ||
3. | Positioning InterOil for long term oil and gas business success. |
Please see our 2007 Annual Information Form for a summary of strategic priorities by business segment available at www.sedar.com
INTRODUCTION
InterOil is developing a vertically integrated energy company in Papua New Guinea and the surrounding region. Our operations are organized into four major segments:
Segments | Operations | |
Upstream | Exploration and Production – Explores and appraises potential oil and natural gas structures in Papua New Guinea with a view to commercializing significant discoveries. | |
Midstream | Refining – Produces refined petroleum products at Napa Napa in Port Moresby Papua New Guinea for domestic market and for spot export. Liquefaction – Developing an onshore liquefied natural gas processing facility in Papua New Guinea. | |
Downstream | Wholesale and Retail Distribution – Markets and distributes refined petroleum products domestically in Papua New Guinea on a wholesale and retail basis. | |
Corporate | Corporate – Provides support to the other business segments by engaging in business development and improvement activities and providing general and administrative services and management, undertakes financing and treasury activities, and is responsible for government and investor relations. General and administrative and integrated costs are recovered from business segments on an equitable basis. Our corporate segment results also include consolidation adjustments. |
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FINANCIAL RESULTS
Summary of Consolidated Financial Results for the Year and Quarter ended December 31, 2007
Highlights for year ended December 31, 2007
Net loss for the year ended December 31, 2007 was $28.9 million, an improvement of $16.9 million, 37% over 2006. EBITDA for the year ended December 31, 2007 was $5.3 million, an improvement of $19.4 million, 138% over 2006.
In summary, the $16.9 million improvement for the year ended December 31, 2007 compared to the same period for 2006, is primarily due to:
ü | improved refinery margins resulting from optimization efforts and capital works undertaken during 2006. | ||
ü | increased Downstream sales volume margins resulting from the Shell acquisition. | ||
ü | recognition of a deferred gain during the period due to signing of the LNG Shareholder’s Agreement on July 31, 2007. |
These improvements were partly offset by:
ü | additional seismic costs in relation to the Elk extended well seismic program. | ||
ü | additional expenses related to our share of preliminary costs of the LNG Project. | ||
ü | additional office and administration expenses associated with the LNG Project and higher share compensation expense. |
Highlights for quarter ended December 31, 2007
Net loss for the quarter ended December 31, 2007 was $2.7 million, a decrease in net loss of $0.7 million, 20% improvement over the loss in the same quarter in 2006. EBITDA for the quarter ended December 31, 2007 was $6.9 million, the same result was achieved for the same quarter in 2006.
In summary, the $0.7 million decrease in net loss for the quarter ended December 31, 2007 compared to the same period for 2006, is primarily due to increased Downstream sales volume on increased domestic demand, coupled with a net positive effect on gross margin due to IPP price movements .
This increase in income was partly offset by:
ü | increased seismic costs in relation to the Elk extended well seismic program. | ||
ü | additional expenses related to our share of preliminary costs of the LNG Project preliminary costs. |
A detailed explanation of our consolidated results for the year and quarter ended December 31, 2007 is contained in the analysis section below. Following is a table containing the annual consolidated results for the year ended December 31, 2007, 2006 and 2005.
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Annual Consolidated Financial Results
Consolidated results for year ended December 31, 2007 compared to year ended December 31, 2006 and
2005
2005
Consolidated – Operating results | Years ended December 31, | |||||||||||
($ thousands, unless otherwise indicated) | 2007(1) | 2006(1) | 2005 | |||||||||
Sales and operating revenues | 625,526 | 511,088 | 481,181 | |||||||||
Interest revenue | 2,180 | 3,224 | 1,831 | |||||||||
Other non-allocated revenue | 2,667 | 3,748 | 528 | |||||||||
Total revenue | 630,373 | 518,060 | 483,540 | |||||||||
Cost of sales and operating expenses | (573,609 | ) | (499,495 | ) | (467,247 | ) | ||||||
Office and administration and other expenses | (43,468 | ) | (24,834 | ) | (23,296 | ) | ||||||
Gain on LNG shareholder agreement | 6,553 | — | — | |||||||||
Exploration costs | (13,305 | ) | (6,177 | ) | (11,009 | ) | ||||||
Exploration impairment | (1,243 | ) | (1,647 | ) | (19,570 | ) | ||||||
Earnings before interest, taxes, depreciation and amortization (unaudited)(2) | 5,301 | (14,094 | ) | (37,582 | ) | |||||||
Depreciation and amortization | (13,024 | ) | (12,353 | ) | (11,037 | ) | ||||||
Interest expense | (20,005 | ) | (17,273 | ) | (10,987 | ) | ||||||
Loss from ordinary activities before income taxes | (27,728 | ) | (43,720 | ) | (59,606 | ) | ||||||
Income tax expense | (1,207 | ) | (2,343 | ) | (2,832 | ) | ||||||
Non-controlling interest | 22 | 264 | 368 | |||||||||
Total net loss | (28,913 | ) | (45,799 | ) | (62,070 | ) | ||||||
Net loss per share (dollars) (basic) | (0.96 | ) | (1.55 | ) | (2.15 | ) | ||||||
Net loss per share (dollars) (diluted) | (0.96 | ) | (1.55 | ) | (2.15 | ) | ||||||
Total assets | 537,815 | 505,239 | 432,897 | |||||||||
Total liabilities | 441,712 | 417,060 | 311,068 | |||||||||
Cash flows (used in)/provided by | (40,716 | ) | 2,187 | (22,713 | ) | |||||||
Cash dividends declared per share | — | — | — | |||||||||
(1) | Our wholesale and retail distribution business segment acquired the business of Shell PNG Limited on October 1, 2006 and information in this table includes the results of the Shell business from this date. | |
(2) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. |
Analysis of Consolidated Financial Results for year ended December 31, 2007 compared to year ended December 31, 2006
While a complete discussion of each of the business segment’s results can be found under the section “Year in Review,” the following highlights some of the key movements, the net of which has resulted in a $16.9 million, 37% decrease in our net loss between the year ended December 31, 2007 and 2006.
ü | $28.5 million improvement in gross margin (sales and operating revenues less cost of sales and operating expenses) from refinery operations primarily due to the positive impact of revamp and optimization efforts, improved margins on export products and revised IPP pricing for refined products in place during December 2007. |
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ü | $9.7 million improvement in gross margin from our Downstream segment mainly due to margins from additional volumes resulting from the business acquired from Shell and increased domestic demand coupled with a positive effect on Gross Margin due to IPP price movements over the current year. | ||
ü | $6.6 million recognition of a deferred gain on the discounted interest rate on the bridging loan facility entered into in May 2006 with Merrill Lynch Commodities (Europe) Limited and Pacific LNG Operations Ltd, | ||
ü | $0.3 million increase in foreign exchange gain compared to the prior year due to the strengthening of the PGK against the USD from 0.3300 in December 2006 to 0.3525 in December 2007. |
These improvements were partly offset by the following:
ü | $7.1 million increase in exploration costs in our Upstream segment relating to our portion of Elk geophysics and geology costs, which are expensed as incurred under the successful efforts method of accounting. | ||
ü | $19.0 million additional office and administration and other expenses mainly with derivative losses, higher share compensation expense and with the LNG Project, | ||
ü | $2.7 million increase in interest expense for the year as a result of the $130.0 million secured loan financing obtained during the second quarter of 2006. |
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Summary of Consolidated Quarterly Financial Results for Past Eight Quarters
Consolidated Quarterly Financial Results by Quarter for 2007 and 2006
The following is a table containing the consolidated results for the eight quarters ended December 31, 2007 by business segment.
Quarters ended | ||||||||||||||||||||||||||||||||
($ thousands unless stated | 2007 | 2006 | ||||||||||||||||||||||||||||||
otherwise) | Dec 31 | Sep 30 | Jun 30 | Mar 31 | Dec 31 | Sep 30 | Jun 30 | Mar 31 | ||||||||||||||||||||||||
Upstream | 579 | 1,176 | 397 | 395 | 705 | 900 | 2,684 | 959 | ||||||||||||||||||||||||
Midstream — Refining | 137,509 | 168,737 | 114,584 | 103,055 | 147,538 | 94,687 | 106,825 | 103,105 | ||||||||||||||||||||||||
Midstream — Liquefaction | 26 | 10 | 5 | — | — | — | — | — | ||||||||||||||||||||||||
Downstream | 118,495 | 102,786 | 93,186 | 77,812 | 91,990 | 39,527 | 37,995 | 27,807 | ||||||||||||||||||||||||
Corporate and Consolidated | (83,776 | ) | (82,605 | ) | (67,633 | ) | (54,366 | ) | (67,457 | ) | (24,132 | ) | (23,095 | ) | (21,979 | ) | ||||||||||||||||
Sales and operating revenues | 172,833 | 190,105 | 140,539 | 126,896 | 172,776 | 110,982 | 124,409 | 109,892 | ||||||||||||||||||||||||
Upstream | (3,128 | ) | (5,015 | ) | (5,492 | ) | (4,009 | ) | (719 | ) | (1,107 | ) | (1,922 | ) | (5,136 | ) | ||||||||||||||||
Midstream — Refining | 9,589 | (1,332 | ) | 3,775 | 6,336 | 9,144 | 1,674 | (8,188 | ) | (5,229 | ) | |||||||||||||||||||||
Midstream — Liquefaction | (797 | ) | (4,104 | ) | (444 | ) | (322 | ) | (396 | ) | (298 | ) | — | — | ||||||||||||||||||
Downstream | 3,627 | 3,301 | 2,760 | 3,028 | 1,143 | 1,954 | 3,559 | (326 | ) | |||||||||||||||||||||||
Corporate and Consolidated | (2,394 | ) | (3,105 | ) | 4,959 | (1,931 | ) | (2,299 | ) | (853 | ) | (3,770 | ) | (1,321 | ) | |||||||||||||||||
Earnings before interest, taxes, depreciation and amortization(1) | 6,897 | (10,255 | ) | 5,557 | 3,102 | 6,873 | 1,370 | (10,323 | ) | (12,014 | ) | |||||||||||||||||||||
Upstream | (3,262 | ) | (4,716 | ) | (5,831 | ) | (4,318 | ) | (954 | ) | (1,310 | ) | (2,098 | ) | (5,335 | ) | ||||||||||||||||
Midstream — Refining | 2,990 | (12,199 | ) | (1,117 | ) | 1,511 | 3,818 | (4,309 | ) | (13,408 | ) | (10,052 | ) | |||||||||||||||||||
Midstream — Liquefaction | (825 | ) | (4,104 | ) | (444 | ) | (322 | ) | (396 | ) | (298 | ) | — | — | ||||||||||||||||||
Downstream | 670 | (255 | ) | 2,242 | 2,050 | (427 | ) | 1,278 | 2,426 | (282 | ) | |||||||||||||||||||||
Corporate and Consolidated | (2,286 | ) | 3,382 | 2,196 | (4,275 | ) | (5,420 | ) | (2,684 | ) | (4,745 | ) | (1,603 | ) | ||||||||||||||||||
Net income (loss) per segment | (2,713 | ) | (17,892 | ) | (2,954 | ) | (5,354 | ) | (3,379 | ) | (7,323 | ) | (17,825 | ) | (17,272 | ) | ||||||||||||||||
Net income (loss) per share (dollars) | ||||||||||||||||||||||||||||||||
Per Share — Basic | (0.09 | ) | (0.60 | ) | (0.10 | ) | (0.18 | ) | (0.11 | ) | (0.25 | ) | (0.60 | ) | (0.59 | ) | ||||||||||||||||
Per Share — Diluted | (0.09 | ) | (0.60 | ) | (0.10 | ) | (0.18 | ) | (0.11 | ) | (0.25 | ) | (0.60 | ) | (0.59 | ) | ||||||||||||||||
(1) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. |
Analysis of Consolidated Quarterly Financial Results Comparing the Quarters Ended December 31, 2007 and 2006
The following highlights some of the key movements, the net of which has resulted in a $0.7 million, 20% decrease in our net loss between the quarter ended December 31, 2007 and the same quarter in 2006.
ü | $5.3 million improvement in gross margin (sales and operating revenues less cost of sales and operating expenses) from Midstream Refinery operations between fourth quarter of 2007 and same quarter of 2006 primarily due to reduced fuel and operating costs and improved margins on export products. |
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ü | $4.6 million improvement in gross margin from our Downstream segment for fourth quarter of 2007 over fourth quarter of 2006, mainly due to increased domestic demand and favorable IPP movements compared to prior period. | ||
ü | $2.6 million increase in foreign exchange gain for the fourth quarter of 2007 as compared to the same quarter of 2006 due to the strengthening of the PGK against the USD. |
The above items were partly offset by the following changes between the fourth quarter of 2007 and 2006:
ü | $1.2 million increase in exploration costs in our Upstream segment relating to our portion of Elk geophysics and geology costs, which are expensed as incurred under the ‘Successful Efforts’ method of accounting. | ||
ü | $9.7 million additional office and administration and other expenses mainly associated derivative losses, higher share compensation expense and the LNG Project. | ||
ü | $1.0 million impairment write down booked on barge held for sale. |
For analysis of the first through third quarter results, please refer to InterOil’s quarterly MD&A’s available on the Company’s website at www.interoil.com or on www.sedar.com.
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YEAR AND QUARTER IN REVIEW
The following section provides a review of 2007 for each of our business segments. It includes a business summary, an operational review of the year, a review of financial results for the year and quarter ended December 31, 2007, and an analysis of each stream’s contribution to InterOil’s corporate strategy.
UPSTREAM – YEAR AND QUARTER IN REVIEW
Upstream Business Summary
Our Upstream exploration and production business currently holds four exploration licenses and two retention licenses in Papua New Guinea, covering approximately nine million acres. Approximately 8.2 million acres are operated by us, being Petroleum Prospecting Licenses (‘PPL’) 236, 237, 238 and Petroleum Retention License (‘PRL’) 4. The operated exploration licenses are located onshore in the eastern Papuan Basin, northwest of Port Moresby and are 100% owned by us. In addition to the onshore interests, we also have a 15% interest in PPL 244, located offshore in the Gulf of Papua. Our current exploration efforts are focused on PPL 236, 237 and 238, and the majority of our exploration expenditures are related to our ongoing seismic and drilling operations in PPL 238.
Our Indirect Participation Working Interest (‘IPWI’) investors have the right to participate up to a 31.55% working interest in the exploration wells currently being drilled and any resulting fields in our operated exploration licenses. These investors have a 31.55% interest in the next three exploration wells and a 24.8% interest in the two subsequent exploration wells.
At December 31, 2007, we do not have any oil or gas reserves or resources, or working interests in any producing oil and gas wells and therefore no oil and gas sales revenue during 2007. The Elk structure hydrocarbons are currently being evaluated and are not classified as reserves under definitions adopted by the United States or Canadian regulatory authorities.
InterOil is a shareholder in PNG LNG, Inc. which in turn owns all of the shares in Liquid Niugini Gas Ltd, a corporation established to build, own and operate a liquefied natural gas (LNG) facility in PNG. The LNG plant is predicated on at least a substantial portion of the gas being supplied to it from InterOil’s Elk/Antelope complex. The financial investment decision for the construction of the plant and pipeline linking the plant to Elk/Antelope depends, among other considerations, on successful drilling results from the appraisal and exploration program currently under way at Elk/Antelope.
Upstream Operating Review
Key Upstream Metrics | 2007 | 2006 | ||||||
Wells spudded in the period | 2 | 1 | ||||||
Cumulative IPWI Exploration wells drilled | 3 | 3 | ||||||
Cumulative IPWI Appraisal wells drilled | 1 | 0 | ||||||
Total footage drilled (Total Vertical Depth — feet) | 13,602 | 6,087 | ||||||
2D seismic miles acquired | 144 | 79 | ||||||
Airborne gravity and magnetic survey miles acquired | 0 | 6,244 | ||||||
Total gross expenditure on 2D seismic acquisition ($ millions) | $ | 19.5 | $ | 6.8 | ||||
Total Gross expenditure on drilling and testing ($ millions) | $ | 44.5 | $ | 37.9 |
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Elk-1 Well
No activity occurred at the Elk-1 well site during 2007. The well is suspended as a gas/condensate discovery.
Elk-1 Well Control Insurance Claim
During the third quarter of 2007, we received a cash settlement of $7.0 million from our insurers with respect to a claim under the company’s well control insurance policy. On June 11, 2006, we had an uncontrolled flow of gas to surface at Elk-1. There were no injuries suffered by personnel nor was there major equipment damaged, and the well was immediately shut-in with the blow out prevention equipment. As a result of this incident, we were unable to continue drilling until we regained operational control of the well. This insurance claim covered expenditures incurred during the 97 day period from June 11, 2006 to September 15, 2006 that were required to acquire and install equipment required to regain control of the Elk-1 well and allow us to drill ahead.
After deducting the insurance proceeds, gross Elk-1 drilling and testing costs to December 31, 2007 were $29.3 million. Our net share of the Elk-1 cost is $25.4 million, and is capitalized at December 31, 2007, as part of our oil and gas properties pending further evaluation of the structure.
Elk-2 Drilling and Testing
The Elk-2 well spudded on February 9, 2007. The Elk-2 well is located in PPL 238 and is situated 2.9 miles (4.7 kilometers) north of the 2006 Elk-1 discovery well. The primary objectives of this well were to delineate the base of Elk-1 structure, explore for the presence of oil and determine the thickness and quality and reservoir characteristics of the limestone reservoir. On August 18, 2007, we reached the final total depth at Elk-2 of 10,922 feet (3,329 meters).
The Elk-2 well has been suspended pending a decision on whether to drill a side-track the well.
Total gross cost incurred to December 31, 2007 to drill and test Elk-2 was $36.3 million. As Elk-2 is an appraisal well and not one of the eight IPWI exploration wells, our partners have contributed cash to cover their 31.55% of the Elk-2 drilling and testing costs. Our net 68.45% share of the Elk-2 costs is $24.9 million, which is capitalized at December 31, 2007 as part of our oil and gas properties.
The current projection of the GWC from Elk-2 test data suggests a possible increase in resource estimates, when analyzed in conjunction with the 2007 appraisal seismic results, (see below). The evaluation of the Elk structure is therefore a work in progress and as a result the exploration costs are capitalized and maintained on the balance sheet.
Elk Appraisal Seismic
During 2007, a seismic program was initiated to further appraise and delineate the Elk structure and to test a gravity anomaly and lead on-trend known as Bighorn, to the southeast of Elk. Previous seismic campaigns performed by InterOil relied on a “boutique” style of seismic acquisition whereby the seismic crew was contracted directly to InterOil and actively managed in a day to day fashion by InterOil. We contracted the technical services of CGGVeritas to undertake the 2D seismic appraisal program. CGGVeritas has previous operating experience in PNG and is one of the largest and most technologically advanced seismic acquisition contractors in the industry today.
Prior to recording the first production line of the seismic program an extensive field parameter testing program was conducted to test various survey configurations modeled in desktop studies to substantially improve data quality compared to previous acquisition in the area. A series of parameters, including deeper shot holes, was selected for the 2007 seismic program.
The seismic crew was first mobilized on January 15, 2007. The seismic program was completed in mid-October 2007 and acquired 12 lines totaling 144 miles (230 Kilometers) with 28 miles (44 Kilometers) of this total over PPL 237 and the remaining 116 miles (186 Kilometers) over PPL 238.
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The results of the seismic interpretation to date indicate that:
• | The Elk structure extends further to the south than previously projected. | ||
• | A major fault separates the southern portion of the Elk structure into a different structure that we have named Antelope. | ||
• | A reef structure exists on the Antelope structure. |
Final processing of the additional 12 lines of Elk appraisal seismic was completed in early December 2007. Remapping of the Elk and Antelope blocks commenced at that time and is still ongoing.
Management is encouraged by the increased potential aerial extent of the Elk/Antelope play to the south (taking into consideration the revised Gas Water Contact) and also by seismic indications of the existence of a reef and platform development in the Antelope block, which was further supported by the presence of reefal material in the Elk-2 cores.
The presence of shallow water carbonate in the Antelope block is believed to be analogous to the Uramu and Iviri platform and reef complex in the southwestern corner of PPL237, in which the Uramu gas discovery was made. These wells, drilled into reefs by other operators, have demonstrated ‘good to excellent’ reservoir characteristics in terms of their porosity and permeability.
Total gross cost incurred to December 31, 2007 to acquire the Elk appraisal seismic was $19.5 million. As this appraisal seismic is not part of the eight IPWI exploration wells, our partners have contributed cash calls covering their 31.55% of these seismic costs. Therefore, our net 68.45% share of the Elk appraisal seismic costs is $13.3 million, which has been expensed by us during the year ended December 31, 2007 as part of the company’s exploration cost, in accordance with the Successful Efforts Accounting treatment of all Geological and Geophysical expenses.
Elk-4 Drilling
The Elk-4 well spudded on November 15, 2007. This well is planned as an 8,125 foot (2,500 meter) test of the Elk fractured limestone structure and is located 0.9 miles (1.5 kilometers) south of Elk-1. Although this is our third Elk well, this well was named Elk-4, as the Elk-3 designation was reserved for the planned side track of Elk-2, which has been deferred. At December 31, 2007 we had reached a depth of 2,730 feet (830 meters) and are currently drilling ahead at 6,580 feet (2,000 meters). Gross costs to December 31, 2007 were $11.1 million. As Elk-4 is not one of the eight IPWI exploration wells, our partners have contributed cash to cover their 27.05% of the Elk-4 drilling costs. Therefore, the company’s net 72.95% share (one IPI investor with 4.5% interest elected not to participate in this well) of the Elk-4 costs is $8.1 million, which is capitalized at December 31, 2007 as part of the company’s Oil and Gas Properties.
Antelope-1 Well
The Antelope-1 drill site is located 2.5 miles (4 Kilometers) south of Elk-1 on PPL 238 and the drill site and camp construction was substantially complete December 31, 2007. Although efforts were made to secure a second rig to drill Antleope-1 at the same time as InterOil Rig 2 drilled Elk-4, it was not possible to locate a suitable rig due to the current high demand for drilling equipment. Therefore when InterOil Rig # 2 completes the drilling and testing of Elk-4, it will be transported by helicopter to the new location.
Antelope-1 will target the limestone reef at approximately 1,700 meters depth with a total projected depth of approximately 2,500m. Costs to December 31, 2007 were $3.0 million.
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PRL 4 – Operated By Austral Pacific Energy Limited
• | During fourth quarter of 2007 we participated in a non-operated, 26 mile (43 kilometer) 2D seismic program over the Stanley gas/condensate discovery in the PRL 4 license. The extent of our interest in this license is 43.13%. | ||
• | The joint venture has engaged in negotiations to provide gas to an electrical power generation company. Gas composition and well deliverability are required to progress to financial close and the PRL 4 partners are planning a reentry and production test of the Stanley-1 discovery well, to validate the resource. | ||
• | In February 2008, Austral Pacific resigned as operator of PRL 4 and InterOil was elected the new operator with effect from March 3, 2008. |
PRL 5 – Operated By Santos
During 2007, seismic re-processing was undertaken and the operator is proposing to drill Elevala-2 in 2008.
PPL244 – Operated By Talisman
The operator is seeking to delay the commitment of an offshore exploration well into 2009, pending further evaluation of the prospect.
Outlook for 2008
2008 planned activity
ü | Complete drilling and testing of the Elk-4 appraisal well | |
ü | Drill the exploration well Antelope-1 to the south of the Elk structure | |
ü | Operate the re-entry and testing of the Stanley-1 gas condensate well and Drill Stanley-2 | |
ü | Participate in the drilling of one well in PRL 5 |
Key factors that will affect our 2008 progress
ü | The nature of the results derived from Elk-4 and Antelope-1 | |
ü | The continued ability to attract and retain key staff in a competitive oil and gas industry | |
ü | Obtaining further funding for our exploration program, including concluding an agreement with an industry major | |
ü | Proving sufficient gas reserves to guarantee the LNG liquefaction project |
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Upstream Financial Results
Upstream - Operating results | Years ended December 31, | |||||||||||
($ thousands) | 2007 | 2006 | 2005 | |||||||||
Other non-allocated revenue | 2,547 | 5,249 | 1,295 | |||||||||
Total segment revenue | 2,547 | 5,249 | 1,295 | |||||||||
Office and administration and other expenses | (5,643 | ) | (6,310 | ) | (1,738 | ) | ||||||
Exploration costs | (13,305 | ) | (6,177 | ) | (11,009 | ) | ||||||
Exploration impairment | (1,243 | ) | (1,647 | ) | (19,570 | ) | ||||||
Earnings before interest, taxes, depreciation and amortization (unaudited)(1) | (17,644 | ) | (8,885 | ) | (31,022 | ) | ||||||
Depreciation and amortization | (483 | ) | (806 | ) | (314 | ) | ||||||
Interest expense | — | (5 | ) | — | ||||||||
Loss from ordinary activities before income taxes | (18,127 | ) | (9,696 | ) | (31,336 | ) | ||||||
Income tax expense | — | — | — | |||||||||
Total net loss | (18,127 | ) | (9,696 | ) | (31,336 | ) | ||||||
(1) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. |
Upstream Financial Results Analysis
During the year 2007, the Upstream business segment had a net loss of $18.1 million as compared with a net loss of $9.7 million in 2006.
The key variances between year ended December 31, 2007 and 2006 are primarily due to:
ü | $7.1 million additional exploration costs expensed in 2007 due to our portion of Elk seismic and geology costs, which are expensed as incurred under the successful efforts method of accounting. | ||
ü | $2.4 million decrease in interest revenue due to lower cash and cash equivalents available on account of usage of cash on deposit. | ||
ü | $0.3 million decrease in other unallocated revenue in 2007 due to lower third party rental income from our rig. | ||
ü | $0.7 million decrease in office and administration and other expenses related mainly due to lower rig expenses. |
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Upstream Financial Results for Quarter Ended December 31, 2007 and the Preceding Seven Quarters
Upstream – Operating | ||||||||||||||||||||||||||||||||
results | ||||||||||||||||||||||||||||||||
($ thousands) | 2007 | 2006 | ||||||||||||||||||||||||||||||
Dec 31 | Sep 30 | Jun 30 | Mar 31 | Dec 31 | Sep 30 | Jun 30 | Mar 31 | |||||||||||||||||||||||||
Other non-allocated revenue | 579 | 1,176 | 397 | 395 | 705 | 900 | 2,684 | 959 | ||||||||||||||||||||||||
Total segment revenue | 579 | 1,176 | 397 | 395 | 705 | 900 | 2,684 | 959 | ||||||||||||||||||||||||
Office and administration and other expenses | (1,756 | ) | (1,453 | ) | (1,366 | ) | (1,068 | ) | (1,354 | ) | (1,531 | ) | (2,370 | ) | (1.053 | ) | ||||||||||||||||
Exploration costs | (1,234 | ) | (4,232 | ) | (4,518 | ) | (3,322 | ) | 50 | (505 | ) | (2,162 | ) | (3,560 | ) | |||||||||||||||||
Exploration impairment | (717 | ) | (505 | ) | (6 | ) | (14 | ) | (119 | ) | 30 | (76 | ) | (1,482 | ) | |||||||||||||||||
Earnings before interest, taxes, depreciation and amortization(1) | (3,128 | ) | (5,015 | ) | (5,493 | ) | (4,009 | ) | (717 | ) | (1,106 | ) | (1,924 | ) | (5,136 | ) | ||||||||||||||||
Depreciation and amortization | (134 | ) | 299 | (338 | ) | (309 | ) | (233 | ) | (202 | ) | (173 | ) | (198 | ) | |||||||||||||||||
Interest expense | — | — | — | — | (2 | ) | (1 | ) | (1 | ) | (1 | ) | ||||||||||||||||||||
Loss from ordinary activities before income taxes | (3,262 | ) | (4,716 | ) | (5,831 | ) | (4,318 | ) | (953 | ) | (1,309 | ) | (2,098 | ) | (5,335 | ) | ||||||||||||||||
Income tax expense | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Total net loss | (3,262 | ) | (4,716 | ) | (5,831 | ) | (4,318 | ) | (953 | ) | (1,309 | ) | (2,098 | ) | (5,335 | ) | ||||||||||||||||
(1) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. |
Analysis of Upstream Financial Results Comparing Quarter Ended December 31, 2007 and 2006
During the fourth quarter of 2007, the Upstream business had a net loss of $3.3 million, compared with a loss of $1.0 million in the same quarter of 2006.
The key variances in the quarter ended December 31, 2007, compared with the same quarter in 2006, are primarily due to:
ü | $1.2 million additional exploration costs expensed in the fourth quarter of 2007 due to our portion of Elk geophysics and geology costs, which are expensed as incurred under the successful efforts method of accounting. The seismic program ended on October 7, 2007. | ||
ü | $0.6 million additional exploration impairment due to the write off of cash calls paid by us for exploratory activities in PRL 4 and 5 conducted by the joint venture operator. | ||
ü | $0.2 million increase in other unallocated revenue due to higher third party rental income from our rig. | ||
ü | $0.4 million increase in office and administration and other expenses relates mainly to impairment write down on barge held for sale partially offset by lower rig expenses. |
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MIDSTREAM REFINING – YEAR AND QUARTER IN REVIEW
Midstream Refining Business Summary
The Midstream refinery segment is essentially comprised of our facilities situated at Napa Napa in Port Moresby, the capital city of Papua New Guinea. Our refinery consists of a 32,500 barrel per day crude distillation unit (CDU) and a 3,500 barrel per day catalytic reforming unit (CRU) which was commissioned during the second half of 2004 and began commercial operations in 2005. We are currently the sole refiner of hydrocarbons in Papua New Guinea and the refinery’s output is sufficient to meet 100% of that country’s domestic demand for diesel, jet fuel and gasoline. Diesel, jet fuel and gasoline are the primary products that we produce for the domestic market.
Operation of the crude distillation unit also results in the production of naphtha and low sulfur waxy residue. Sometimes limited volumes of LPG’s are produced depending on the nature of the crude feedstock. To the extent that we do not convert naphtha to gasoline within the crude reforming unit, we export it to the Asian markets in two grades, light naphtha and mixed naphtha, which are predominately used as petrochemical feedstocks. At present, the majority of the low sulfur waxy residue is exported, as it is valued by more complex refineries as cracker feedstock. We also market the lower sulfur waxy residue in Papua New Guinea are as InterOil Power Fuel.
Midstream Refining Operating Review
Key Refining Metrics | 2007 | 2006 | ||||||
Net income/(loss) ($ millions) | ($8.8 | ) | ($24.0 | ) | ||||
EBITDA ($ millions)(1) | $ | 18.4 | ($2.6 | ) | ||||
Throughput (barrels per day)(2) | 19,680 | 19,784 | ||||||
Cost of production per barrel(3) | $ | 2.53 | $ | 3.46 | ||||
Working capital financing cost per barrel of production(2) | $ | 0.83 | $ | 1.16 | ||||
Distillates as percentage of production | 65 | % | 65 | % |
(1) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. | |
(2) | Throughput per day has been calculated excluding shut down days. | |
(3) | Our cost of production per barrel and working capital financing cost per barrel have been calculated based on a notional throughput. Our actual throughput has been adjusted to include the throughput that would have been necessary to produce the equivalent amount of diesel that we imported during the year. |
The Midstream refining segment has reduced its net loss by $15.2 million and increased its EBITDA by $21.0 million between 2006 to 2007. The improvements in the results are explained in detail in the annual financial results section below.
In 2007, our total refinery throughput for the year was 19,680 barrels (‘bbls’) per day versus 19,784 bbls per day in 2006. The slight decrease in throughput from 2006 to 2007 is the result of improved distillate yields in the face of increased domestic demand for distillates.
Total operating costs were down approximately $5.1 million or 23% compared to 2006. Total notional throughput was also down marginally over the course of the year resulting in a significant improvement to the operating cost per barrel. In 2008, we expect total operating costs to increase as a result of increasing wages, strengthening in the PGK and Australian dollar and other general cost increases.
Our working capital financing costs have decreased year on year, despite a significant rise in oil price. The decrease is primarily due to negotiating a reduction in letter of credit fees, increased use of our cash backing facility and decreases to benchmark interest rates in the latter half of the year.
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During 2007, the refinery achieved its objective of satisfying the domestic Papua New Guinea demand for diesel, jet, kerosene and gasoline while minimizing production of naphtha and low sulphur waxy residue. Naphtha and low sulphur waxy residue are exported at a lower margin than the distillates which are sold in Papua New Guinea.
Our gross margin improved $28.5 million between 2006 and 2007 due to the following contributing factors:
Controllable
+ | Improved yield structure post revamp (whole year vs part year) | |
+ | Decreased fuel consumption post revamp (whole year vs part year) | |
+ | Decreased fuel cost post revamp (whole year vs part year) | |
+ | Improved premiums negotiated on export products (whole year vs part year) | |
+ | Decreased direct operating costs | |
Non controllable | ||
+ | Increasing price environment including revised IPP pricing | |
- | Significantly reduced margins on domestic sales of distillates | |
- | Increasing crude premiums over Tapis benchmark | |
ü | $5.9 million increase in interest expense comprised of a $7.7 million charge from the Corporate segment that was not charged in 2006 offset by a $1.8 million interest reduction due to increased utilization of the cash backing component of our working capital facility balance, decreased working capital loan balances, decreased LIBOR rates and reduced interest on OPIC loan balances due to repayment of capital during 2006. | |
ü | $1.5 million decrease in office and administration and other expenses due to a number of factors, including lower fees on letters of credit raised with BNP Paribas, reduced consultancy fees and lower repair and maintenance costs, as compared to the same period in 2006. | |
ü | $0.3 million decrease to depreciation charge in 2007 as compared to 2006 | |
ü | $1.3 million increase in foreign exchange gain is mainly due to the appreciation of the PGK against the US dollar. | |
ü | $9.8 million decrease to the gain on derivative contracts deemed not to be subject to hedge accounting. This movement is primarily due to upward price trends during the year which have resulted in losses on derivative contracts used to manage price and margin exposure (refer section on liquidity and capital resources – derivative instruments in this MD&A). This loss partially offsets the improved physical sales prices achieved reflected within sales. |
Outlook for 2008 | ||
2007 improvements expected to show full year benefit in 2008 | ||
ü | Potential revision to IPP pricing formula for refined products (benchmarked to MOPS and Tapis rather than posted prices) | |
ü | Contract premium improvements to export products | |
ü | Increased sales of InterOil Power Fuel | |
ü | Reducing working capital interest rates (reducing LIBOR rates) | |
2008 Initiatives: | ||
ü | Eliminate unplanned downtime | |
ü | Continue to expand niche market for InterOil Power Fuel | |
ü | Continue to seek out niche export opportunities |
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Midstream Refining Annual Financial Results
Midstream | ||||||||||||
Refining – Operating results | Years ended December 31, | |||||||||||
($ thousands) | 2007 | 2006 | 2005 | |||||||||
External sales | 233,869 | 315,211 | 356,327 | |||||||||
Inter-segment revenue | 289,947 | 136,584 | 80,094 | |||||||||
Interest and other revenue | 70 | 360 | 245 | |||||||||
Total segment revenue | 523,886 | 452,155 | 436,666 | |||||||||
Cost of sales and operating expenses | (495,059 | ) | (451,374 | ) | (436,491 | ) | ||||||
Office and administration and other expenses | (10,460 | ) | (3,381 | ) | (10,639 | ) | ||||||
Earnings before interest, taxes, depreciation and amortization (unaudited)(1) | 18,367 | (2,600 | ) | (10,464 | ) | |||||||
Depreciation and amortization | (10,405 | ) | (10,729 | ) | (10,598 | ) | ||||||
Interest expense | (16,798 | ) | (10,881 | ) | (10,162 | ) | ||||||
Loss from ordinary activities before income taxes | (8,836 | ) | (24,210 | ) | (31,224 | ) | ||||||
Income tax expense | — | — | — | |||||||||
Non controlling interest | 21 | 259 | 362 | |||||||||
Total net loss | (8,815 | ) | (23,951 | ) | (30,862 | ) | ||||||
(1) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. |
Midstream Refining Annual Financial Results Analysis
During the year 2007, the Midstream Refining business net loss was $8.8 million, compared with a loss of $24.0 million in 2006.
The key variances between the two periods are explained as follows:
ü | An increase in Gross Margin of $28.5 million for the year ended December 31, 2007 when compared to the same period in 2006 was primarily due to a combination of movements in the following: | |
Elements within our control | ||
+ | Improved yield structure post revamp (whole year vs part year) | |
+ | Decreased fuel consumption post revamp (whole year vs part year) | |
+ | Decreased fuel cost post revamp (whole year vs part year) | |
+ | Improved premiums negotiated on export products (whole year vs part year) | |
+ | Decreased direct operating costs | |
Elements outside our control | ||
+ | Increasing price environment including revised IPP pricing | |
- | Significantly reduced margins on domestic sales of distillates | |
- | Increasing crude premiums over Tapis benchmark | |
ü | $7.1 million increase in office and administration and other expenses due to the following factors: | |
- lower fees on letters of credit raised with BNP Paribas, decreased external consultant costs and decreased repair and maintenance costs, as compared to the same period in 2006. |
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- $9.8 million decrease to the gain on derivative contracts deemed not to be subject to hedge accounting. This movement is primarily due to upward price trends during the year which have resulted in losses on derivative contracts used to manage price and margin exposure (See under the heading “ Liquidity and Capital Resources – Derivative instruments”). These derivative losses are partially offset by the improved physical sales prices achieved during the year, reflected within sales revenue. | ||
- $1.3 million increase in foreign exchange gains due to the appreciation of the PGK against the US dollar. | ||
ü | $5.9 million increase in interest expense comprised of a $7.7 million charge from the Corporate segment that was not charged in 2006 offset by a $1.8 million interest reduction due to increased utilization of the cash backing component of our working capital facility balance, decreased working capital loan balances, decreased LIBOR rates and reduced interest on OPIC loan balances due to repayment of capital during 2006. |
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Midstream Refining Financial Results for the Quarter Ended December 31, 2007 and the Preceding Seven Quarter
Operating results | 2007 | 2006 | ||||||||||||||||||||||||||||||
($ thousands) | Dec 31 | Sep 30 | Jun 30 | Mar 31 | Dec 31 | Sep 30 | Jun 30 | Mar 31 | ||||||||||||||||||||||||
External sales | 53,385 | 85,733 | 46,538 | 48,213 | 79,634 | 69,901 | 84,823 | 80,854 | ||||||||||||||||||||||||
Inter-segment revenue | 84,094 | 82,989 | 68,031 | 54,833 | 67,894 | 24,665 | 21,870 | 22,155 | ||||||||||||||||||||||||
Interest and other revenue | 30 | 15 | 15 | 9 | 10 | 121 | 132 | 96 | ||||||||||||||||||||||||
Total segment revenue | 137,509 | 168,737 | 114,584 | 103,055 | 147,538 | 94,687 | 106,825 | 103,105 | ||||||||||||||||||||||||
Cost of sales and operating expenses | (123,363 | ) | (166,780 | ) | (110,074 | ) | (94,841 | ) | (138,664 | ) | (95,052 | ) | (112,108 | ) | (105,550 | ) | ||||||||||||||||
Office and administration and other expenses | (4,557 | ) | (3,289 | ) | (735 | ) | (1,878 | ) | 270 | 2,039 | (2,905 | ) | (2,784 | ) | ||||||||||||||||||
Earnings before interest, taxes, depreciation and amortization(1) | 9,589 | (1,332 | ) | 3,775 | 6,336 | 9,144 | 1,674 | (8,188 | ) | (5,229 | ) | |||||||||||||||||||||
Depreciation and amortization | (2,158 | ) | (2,781 | ) | (2,748 | ) | (2,717 | ) | (2,806 | ) | (2,699 | ) | (2,626 | ) | (2,598 | ) | ||||||||||||||||
Interest expense | (4,397 | ) | (8,155 | ) | (2,156 | ) | (2,091 | ) | (2,478 | ) | (3,330 | ) | (2,731 | ) | (2,342 | ) | ||||||||||||||||
Loss from ordinary activities before income taxes | 3,034 | (12,268 | ) | (1,129 | ) | 1,528 | 3,860 | (4,355 | ) | (13,545 | ) | (10,169 | ) | |||||||||||||||||||
Income tax expense | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Non- controlling Interest | (44 | ) | 69 | 12 | (17 | ) | (42 | ) | 46 | 137 | 117 | |||||||||||||||||||||
Total net income/(loss) | 2,990 | (12,199 | ) | (1,117 | ) | 1,511 | 3,818 | (4,309 | ) | (13,408 | ) | (10,052 | ) | |||||||||||||||||||
(1) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. |
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Analysis of Midstream Refining Financial Results Comparing the Quarters Ended December 31, 2007 and 2006
During the quarter ended December 31, 2007, the Midstream Refining business net income was $3.0 million, compared with $3.8 million in the same period of 2006.
The key variances between the quarter ended December 31, 2007 and 2006 are explained as follows:
ü | An increase in gross margin of $5.3 million for the fourth quarter of 2007 mainly due to revised IPP pricing | |
ü | $4.8 million increase in office and administration and other expenses due to of the following factors: | |
- lower fees on letters of credit raised with BNP Paribas, decreased external consultant costs and decreased repair and maintenance costs, as compared to the same period in 2006. | ||
- $8.0 million decrease to the gain on derivative contracts deemed not to be subject to hedge accounting. This movement is primarily due to upward price trends during the year which have resulted in losses on derivative contracts used to manage price and margin exposure (refer section on liquidity and capital resources – derivative instruments in this MD&A). This loss partially offsets the improved physical sales prices achieved reflected within sales. | ||
- $3.0 million increase in foreign exchange gains due to the appreciation of the PGK against the US dollar. | ||
ü | $1.9 million increase in interest expense due to an additional $1.9 million interest charge from the Corporate segment. |
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MIDSTREAM LIQUEFACTION YEAR IN REVIEW
Midstream Liquefaction Operating Review
Our liquefaction segment is in the early stages of its development. In May 2006, InterOil signed a memorandum of understanding with the Government of Papua New Guinea for natural gas development projects in Papua New Guinea and a tri-partite agreement with Merrill Lynch Commodities (Europe) Limited and Pacific LNG Operations Ltd., an affiliate of Clarion Finanz AG. The tri-partite agreement related to a proposal for the construction of a liquefaction plant to be built adjacent to our refinery. The joint venture is targeting a facility that will produce up to nine million tons per annum of Liquefied Natural Gas (LNG) and condensates. The infrastructure currently being contemplated includes condensate storage and handling, a gas pipeline from the Elk/Antelope field, as well as sourced suppliers of gas, and LNG storage and handling. The LNG facility is designed to interface with our existing refining facilities.
On July 30, 2007, a shareholders’ agreement was signed between InterOil LNG Holdings Inc. (100% subsidiary of InterOil), Pacific LNG Operations Ltd., Merrill Lynch Commodities (Europe) Limited and PNG LNG Inc. (“Joint Venture Company”). The signing of this shareholders’ agreement meant that PNG LNG Inc. was no longer a subsidiary of InterOil Corporation and became a jointly controlled entity between the other parties to the shareholders’ agreement, from the date of the agreement.
As part of the shareholders’ agreement, five ‘A’ Class shares were issued with full voting rights with each share controlling one board position. Two ‘A’ Class shares are owned by InterOil, two by Merrill Lynch Commodities (Europe) Limited, and one by Pacific LNG Operations Ltd. All key operational matters require either a unanimous or supermajority board resolution. As the entity is now a joint venture, guidance under CICA 3055 – ‘Interest in Joint Ventures’ has been followed and the entity has been proportionately consolidated in our consolidated financial statements from the date of the Shareholders’ Agreement.
We were also provided with ‘B’ Class shares in the Joint Venture Company with a fair value of $100.0 million in recognition of InterOil’s contribution to the LNG Project at the time of signing the Shareholders’ Agreement. Our contribution to the Joint Venture Company includes, among other things, infrastructure developed by us near the proposed LNG site at Napa Napa, our stakeholder relations within Papua New Guinea, our negotiation of natural gas supply agreements with landowners, and our contribution to project development. InterOil, Merrill Lynch and Pacific LNG will contribute cash into the Joint Venture Company in response to cash calls. Under the shareholders’ agreement, we are not required to contribute towards cash calls from the Joint Venture Company until a total of $200.0 million has been contributed by the other Joint Venture partners to equalize their shareholding in the Joint Venture Company with that of InterOil. As at December 31, 2007, InterOil held 90.72% of the B class shareholding in the Joint Venture Company. The balance of the shareholding is held in equal shares by Pacific LNG Operations Ltd. and Merrill Lynch Commodities (Europe) Limited.
Pacific LNG Operations Ltd. and Merrill Lynch Commodities (Europe) Limited have initially approved and agreed to provide a total of $40.0 million to fund cash costs incurred through the front end engineering and design (FEED) phase of the project and until the Final Investment Decision (FID) milestone is achieved. Both FEED and FID are defined in the Shareholders Agreement and are available on SEDAR at www.sedar.com.
Some progress has been made on a number of the key components necessary to develop a LNG project. During 2008, we anticipate further development stage activities aimed towards the financing, government approvals and construction of such an LNG plant.
If approval is given, completion of an LNG facility will require substantial amounts of financing and construction will take a number of years to complete. No assurances can be given that we will be able to successfully construct such a facility, or as to the timing of such construction. In addition, no assurance can be given that we will have access to sufficient gas reserves, whether from the Elk location or otherwise, to support or justify an LNG facility.
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Outlook for 2008 | ||
2008 goals: | ||
ü | Execution of an appropriate Project Agreement with the Papua New guinea government | |
ü | Awarding front end engineering and design (FEED)/engineering procurement and construction (EPC) contract | |
ü | Confirmation of gas reserves | |
ü | Agreement reached for the participation of a strategic industry based shareholder in the project |
Midstream Liquefaction Annual Financial Results
Midstream | |||||||||||||||
Liquefaction – Operating results | Years ended December 31, | ||||||||||||||
($ thousands) | 2007 | 2006 | 2005(1) | ||||||||||||
Interest and other revenue | 41 | — | — | ||||||||||||
Total segment revenue | 41 | — | — | ||||||||||||
Office and administration and other expenses | (5,708 | ) | (694 | ) | — | ||||||||||
Earnings before interest, taxes, depreciation and amortization (unaudited)(2) | (5,667 | ) | (694 | ) | — | ||||||||||
Depreciation and amortization | (16 | ) | — | — | |||||||||||
Interest expense | — | — | — | ||||||||||||
Loss from ordinary activities before income taxes | (5,683 | ) | (694 | ) | — | ||||||||||
Income tax expense | (13 | ) | — | — | |||||||||||
Total net loss | (5,696 | ) | (694 | ) | — | ||||||||||
(1) | Our liquefaction segment was formed in 2006 and as a result there is no comparative information for 2005. The liquefaction segment is in its early stage of development. | |
(2) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. |
Analysis of Midstream Liquefaction Financial Results Comparing the Year and Quarter Ended December 2007 and 2006:
All costs to the date of shareholders’ agreement relating to this segment have been expensed. These costs included expenses relating to employees, office premises and consultants.
All costs incurred, subsequent to the date of the shareholders’ agreement on July 31, 2007, during the pre-acquisition and construction stage will be expensed as incurred, unless they can be directly identified with the property, plant and equipment of the LNG construction project. As at December 31, 2007, we have capitalized $2.7 million relating to the direct costs relating to the project.
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Midstream Liquefaction Quarterly Financial Results by Quarter for 2007 to date and the Preceding Seven Quarters
Midstream Liquefaction | ||||||||||||||||||||||||||||||||
Operating results | 2007 | 2006 | ||||||||||||||||||||||||||||||
($ thousands) | Dec 31 | Sep 30 | Jun 30 | Mar 31 | Dec 31 | Sep 30 | Jun 30 | Mar 31 | ||||||||||||||||||||||||
Interest and other revenue | 26 | 10 | 5 | — | — | — | — | — | ||||||||||||||||||||||||
Total segment revenue | 26 | 10 | 5 | — | — | — | — | — | ||||||||||||||||||||||||
Office and administration and other expenses | (823 | ) | (4,114 | ) | (449 | ) | (322 | ) | (396 | ) | (298 | ) | — | — | ||||||||||||||||||
Earnings before interest, taxes, depreciation and amortization(1) | (797 | ) | (4,104 | ) | (444 | ) | (322 | ) | (396 | ) | (298 | ) | — | — | ||||||||||||||||||
Depreciation and amortization | (15 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||
Interest expense | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Loss from ordinary activities before income taxes | (812 | ) | (4,104 | ) | (444 | ) | (322 | ) | (396 | ) | (298 | ) | — | — | ||||||||||||||||||
Income tax expense | (13 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||
Total net income/(loss) | (825 | ) | (4,104 | ) | (444 | ) | (322 | ) | (396 | ) | (298 | ) | — | — | ||||||||||||||||||
(1) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. |
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DOWNSTREAM YEAR IN REVIEW
Downstream Business Summary
Our Downstream wholesale and retail refined petroleum products distribution business is the largest and most comprehensive distribution base in Papua New Guinea. It encompasses bulk storage, aviation refueling, and the wholesaling and retailing of refined petroleum products which we believe in 2007 supplied approximately two thirds of Papua New Guinea’s total refined petroleum product needs. Our retail and wholesale distribution business distributes diesel, jet fuel, gasoline, kerosene, avgas, and fuel oil as well as Shell and BP branded commercial and industrial lubricants such as engine and hydraulic oils. In general, all of the refined products sold pursuant to our wholesale and retail distribution business are purchased from our refining business segment with the exception of lubricants, fuel oil and avgas.
As at December 2007, we provided petroleum products to 49 retail service stations that operate under the InterOil brand name. Of the 49 service stations that we supply, 35 are owned by us or head leased, with a sublease to company approved operators. The other 14 service stations are independently owned and operated. We supply products to each of these service stations pursuant to retail supply agreements.
In addition to the retail distribution network, we supply petroleum products as a wholesaler to commercial clients and also operate 12 aviation refueling stations throughout Papua New Guinea. In the fourth quarter of 2007, we also acquired 3 additional aviation fuelling depots in 3 provinces where we have an existing presence, thus making us the single largest aviation supplier outside Port Moresby. We own and operate 6 larger terminals and 11 depots that are used as staging posts to supply product throughout Papua New Guinea. We are currently reviewing terminal and depot assets following the Shell acquisition with a view to rationalizing them. As at the end of 2007, we had ceased selling product from six depots and these depots are either being used purely as storage sites or plans are being finalized for them to may be dismantled in the near future. A provision has been made in our Downstream financials for the modifications and remediation work to be done on these depots. More than two-thirds of the volume of petroleum products that we sold during year was supplied to commercial customers. Although the volume of sales to commercial customers is far larger than through our retail distribution network, the sales to our larger commercial customers are generally at lower margins.
Downstream Operating Review
Key Downstream Metrics | 2007 | 2006 | ||||||
Net income ($ millions) | $ | 4.7 | $ | 3.0 | ||||
EBITDA ($ millions)(1) | $ | 12.7 | $ | 6.3 | ||||
Sales volumes (millions of liters)(2) | 556.4 | 291.8 | ||||||
Cost of distribution per liter ($ per liter)(3) | $ | 0.06 | $ | 0.06 |
(1) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. | |
(2) | Sales volumes reflect the actual sales volumes achieved for the year and therefore only include the effect of the Shell acquisition from October 1, 2006. | |
(3) | Cost of distribution per liter includes land based freight costs and operational costs. It excludes depreciation and interest. |
On October 1, 2006, InterOil completed the Shell Overseas Holdings Limited (‘Shell’) purchase which included all of Shell’s retail and distribution assets in Papua New Guinea and all aviation facilities except Shell’s interest in the aviation facility in Port Moresby. The purchase price of this business was $29.1 million, net of cash received including the purchase price adjustment which was completed in 2007.
The Shell acquisition made InterOil the largest distributor of refined petroleum products in Papua New Guinea. Other major commercial customer contracts have also increased our presence in the Papua New Guinea market. Currently, our market share based on the annual refinery offtake for the year ending December 2007 is at 78%, however our total market share of refined petroleum products, based on all product consumed in Papua New Guinea, is estimated to be between 60 and 65%.
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At the end of November 2007, the IPP pricing review resulted in an average wholesale adjustment of $0.10 per litre.
The diesel IPP, despite a slight dip at the beginning of the year, rose steadily for most of the year. The IPP is set on the eighth day of each month and is monitored by the ICCC. The transportation rates change every quarter and these rates are also monitored by the ICCC.
By the end of 2007, major renovation of Lae, PNG vertical storage tanks at the ex-Shell facility were complete. This also included connecting the pipeline manifold from the ex-Shell pipeline to our existing pipeline. We had previously been renting the pipeline from a competitor for this facility.
Major tankage repairs in Rabaul, PNG were commenced in the fourth quarter of 2007 and are scheduled to be completed in the first quarter of 2008. The Rabaul terminal has suffered rapid corrosion due to the active volcanic conditions in existence in that area.
Outlook for 2008
2008 capital spending plans
ü Upgrades to select terminal, depots and aviation sites
ü Aviation upgrade and refueller vehicles
ü New customer base pumps and tankage requirements
2008 growth plans:
ü Consider commercial bunkering opportunities
ü Seek contracts to supply new mining and petroleum companies
ü Pursue opportunities for organic growth in the agriculture sector
ü Explore market opportunities in North Solomon’s Province, PNG, including strategic alliances with key
distributors
distributors
ü Explore acquiring and operating the Manus Province depot from the Manus Provincial Government
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Downstream Financial Results
Downstream — Operating results | Years ended December 31, | |||||||||||
($ thousands) | 2007 | 2006(1) | 2005 | |||||||||
External sales | 391,657 | 195,877 | 124,854 | |||||||||
Inter-segment revenue | 81 | 22 | 6 | |||||||||
Interest and other revenue | 541 | 1,421 | 341 | |||||||||
Total segment revenue | 392,279 | 197,320 | 125,201 | |||||||||
Cost of sales and operating expenses | (368,803 | ) | (183,511 | ) | (110,857 | ) | ||||||
Office and administration and other expenses | (10,759 | ) | (7,479 | ) | (4,725 | ) | ||||||
Earnings before interest, taxes, depreciation and amortization (unaudited)(2) | 12,717 | 6,330 | 9,619 | |||||||||
Depreciation and amortization | (2,205 | ) | (910 | ) | (204 | ) | ||||||
Interest expense | (4,438 | ) | (152 | ) | (226 | ) | ||||||
Income from ordinary activities before income taxes | 6,074 | 5,268 | 9,189 | |||||||||
Income tax expenses | (1,366 | ) | (2,273 | ) | (2,756 | ) | ||||||
Total net income | 4,708 | 2,995 | 6,433 | |||||||||
(1) | Our wholesale and retail distribution business segment acquired the business of Shell Papua New Guinea Limited on October 1, 2006 and contains the results of the Shell business from this date. | |
(2) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. |
Downstream Financial Results Analysis
During the year 2007, the Downstream business earned a net income of $4.7 million compared with $3.0 million in 2006.
The key sources of variance between these periods were as follows:
ü | $9.7 million increase in gross margin in year ended December 31, 2007 over same period last year was mainly due to added volumes from the Shell acquisition and increased domestic demand, coupled with a net positive effect on due to IPP price movements as applied to the inventory sold during the period. | ||
ü | $3.1 million increase in office and administration and other expenses due to a number of factors including added insurance costs from the acquisition and inclusion of the Shell’s retail business. Also the Downstream operations incurred higher Corporate allocations, increased repairs and maintenance costs, and increased travel costs. | ||
ü | $1.3 million increase in depreciation expense over the year ended December 31, 2006 related primarily to the addition of the Shell assets on October 1, 2006. | ||
ü | $4.3 million increase in interest expense over the previous period due to interest charges from Corporate to Downstream during the year on intercompany loans mainly relating to funding provided for the BP and Shell acquisitions. |
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Downstream Financial Results for Quarter Ended December 31, 2007 and the Preceding Seven Quarters
Downstream — Operating | ||||||||||||||||||||||||||||||||
results | 2007 | 2006 | ||||||||||||||||||||||||||||||
($ thousands) | Dec 31 | Sep 30 | Jun 30 | Mar 31 | Dec 31 | Sep 30 | Jun 30 | Mar 31 | ||||||||||||||||||||||||
External sales | 118,538 | 102,632 | 92,782 | 77,705 | 90,695 | 39,451 | 37,955 | 27,775 | ||||||||||||||||||||||||
Inter-segment revenue | 18 | 16 | 27 | 20 | (29 | ) | 43 | 8 | — | |||||||||||||||||||||||
Interest and other revenue | (61 | ) | 138 | 377 | 87 | 1,324 | 33 | 32 | 32 | |||||||||||||||||||||||
Total segment revenue | 118,495 | 102,787 | 93,186 | 77,812 | 91,990 | 39,527 | 37,995 | 27,807 | ||||||||||||||||||||||||
Cost of sales and operating expenses | (109,391 | ) | (98,324 | ) | (88,236 | ) | (72,853 | ) | (87,521 | ) | (35,743 | ) | (33,447 | ) | (26,801 | ) | ||||||||||||||||
Office and administration and other expenses | (5,477 | ) | (1,161 | ) | (2,190 | ) | (1,931 | ) | (3,326 | ) | (1,830 | ) | (989 | ) | (1,333 | ) | ||||||||||||||||
Earnings before interest, taxes, depreciation and amortization(1) | 3,627 | 3,301 | 2,760 | 3,028 | 1,143 | 1,954 | 3,559 | (327 | ) | |||||||||||||||||||||||
Depreciation and amortization | (700 | ) | (497 | ) | (552 | ) | (456 | ) | (537 | ) | (222 | ) | (90 | ) | (62 | ) | ||||||||||||||||
Interest expense | (1,145 | ) | (3,320 | ) | 66 | (39 | ) | (36 | ) | (38 | ) | (39 | ) | (38 | ) | |||||||||||||||||
Income from ordinary activities before income taxes | 1,782 | (516 | ) | 2,274 | 2,533 | 570 | 1,694 | 3,430 | (427 | ) | ||||||||||||||||||||||
Income tax expense | (1,112 | ) | 261 | (32 | ) | (483 | ) | (997 | ) | (416 | ) | (1,004 | ) | 145 | ||||||||||||||||||
Total net income/(loss) | 670 | (255 | ) | 2,242 | 2,050 | (427 | ) | 1,278 | 2,426 | (282 | ) | |||||||||||||||||||||
(1) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. |
Downstream Financial Results Analysis Comparing Quarter Ended December 31, 2007 and 2006
During the quarter ended December 31, 2007, the Downstream business made a net profit of $0.7 million, compared with $0.4 million loss in the same quarter of 2006.
The key sources of variance between these quarters are as follows:
ü | $4.6 million increase in gross margin during the fourth quarter of 2007 over the same quarter of 2006 mainly due to increased domestic demand, coupled with a net positive effect on gross margin due to IPP price movements as applied to the inventory sold during the quarter. IPP review at the end of November resulted in an additional $0.10 per litre which also was a significant contribution to Gross Margin. | ||
ü | $2.2 million increase in office and administration and other expenses due to a number of factors including added insurance costs from the acquisition and inclusion of the Shell’s retail and distribution business. Also the Downstream operations incurred higher Corporate allocations, increased repairs and maintenance costs, and increased travel costs. | ||
ü | $1.1 million increase in interest expense over the previous period due to interest charges from Corporate to Downstream during the quarter on intercompany loans mainly relating to funding provided for BP and Shell acquisition. |
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CORPORATE YEAR IN REVIEW
Our Corporate segment engages in business development and improvement, provides common services and management, undertakes financing and treasury activities, and is responsible for government and investor relations. Common and integrated costs are recovered from business segments on an equitable allocation basis.
Corporate Annual Financial Results
Corporate — Operating results | Years ended December 31, | |||||||||||
($ thousands) | 2007 | 2006 | 2005 | |||||||||
External sales elimination | — | — | — | |||||||||
Inter-segment revenue elimination(1) | (290,028 | ) | (136,606 | ) | (80,101 | ) | ||||||
Interest revenue | 1,648 | (58 | ) | 480 | ||||||||
Other unallocated revenue | — | — | (1 | ) | ||||||||
Total segment revenue | (288,380 | ) | (136,664 | ) | (79,622 | ) | ||||||
Cost of sales and operating expenses elimination(1) | 290,253 | 135,391 | 80,101 | |||||||||
Office and administration and other expenses(2) | (10,897 | ) | (6,971 | ) | (6,193 | ) | ||||||
Gain on LNG shareholder agreement | 6,553 | — | — | |||||||||
Earnings before interest, taxes, depreciation and amortization (unaudited)(3) | (2,471 | ) | (8,244 | ) | (5,714 | ) | ||||||
Depreciation and amortization(4) | 83 | 92 | 79 | |||||||||
Interest expense(5) | 1,232 | (6,235 | ) | (599 | ) | |||||||
Income from ordinary activities before income taxes | (1,156 | ) | (14,387 | ) | (6,234 | ) | ||||||
Income tax expenses | 171 | (69 | ) | (76 | ) | |||||||
Non-controlling interest | 2 | 4 | 6 | |||||||||
Total net income | (983 | ) | (14,452 | ) | (6,304 | ) | ||||||
(1) | Represents the elimination upon consolidation of our refinery sales to other segments and other minor inter-company product sales. | |
(2) | Includes the elimination of inter-segment administration service fees. | |
(3) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. | |
(4) | Represents the amortization of a portion of costs capitalized to assets on consolidation. | |
(5) | Includes the elimination of interest accrued between segments. |
Corporate Annual Results Analysis
The loss made by our Corporate services segment decreased to $1.0 million in 2007 as compared to $14.5 million in 2006. The key items contributing to the $13.5 million improvement between the years ended December 31, 2007 and 2006 were as follows:
ü | $6.6 million gain recognized being the deferred gain on the $130.0 million secured bridging facility realized on signing of PNG LNG Inc. shareholder agreement. | ||
ü | $9.1 million increase in net interest revenue less interest expenses mainly on account of interest costs recharged to other segments at market rates relating to the$130.0 million secured bridging facility | ||
ü | $3.9 million increase in office and administration expenses mainly relating to non-cash stock compensation expense associated with our stock incentive plans for employees and directors. |
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Corporate Consolidated Financial Results for Quarter Ended December 31, 2007 and the Preceding Seven Quarters
Corporate — Operating | ||||||||||||||||||||||||||||||||
results | 2007 | 2006 | ||||||||||||||||||||||||||||||
($ thousands) | Dec 31 | Sep 30 | Jun 30 | Mar 31 | Dec 31 | Sep 30 | Jun 30 | Mar 31 | ||||||||||||||||||||||||
Inter-segment revenue elimination | (84,112 | ) | (83,005 | ) | (68,058 | ) | (54,853 | ) | (67,864 | ) | (24,708 | ) | (21,878 | ) | (22,154 | ) | ||||||||||||||||
Interest revenue | 336 | 401 | 424 | 487 | 457 | 554 | (1,194 | ) | 125 | |||||||||||||||||||||||
Other unallocated revenue | — | — | — | — | (50 | ) | 22 | (23 | ) | 50 | ||||||||||||||||||||||
Total segment revenue | (83,776 | ) | (82,604 | ) | (67,634 | ) | (54,366 | ) | (67,457 | ) | (24,132 | ) | (23,095 | ) | (21,981 | ) | ||||||||||||||||
Cost of sales and operating expenses elimination | 83,121 | 83,005 | 69,906 | 54,220 | 66,649 | 24,708 | 21,878 | 22,156 | ||||||||||||||||||||||||
Office and administration and other expenses | (1,739 | ) | (3,506 | ) | (3,866 | ) | (1,785 | ) | (1,491 | ) | (1,429 | ) | (2,553 | ) | (1,498 | ) | ||||||||||||||||
Gain on LNG shareholder agreement | — | — | 6,553 | — | — | — | — | — | ||||||||||||||||||||||||
Earnings before interest, taxes, depreciation and amortization(1) | (2,394 | ) | (3,105 | ) | 4,959 | (1,931 | ) | (2,299 | ) | (853 | ) | (3,770 | ) | (1,321 | ) | |||||||||||||||||
Depreciation and amortization | 21 | 20 | 20 | 21 | 22 | 24 | 26 | 21 | ||||||||||||||||||||||||
Interest expense | 99 | 6,253 | (2,768 | ) | (2,352 | ) | (3,131 | ) | (1,981 | ) | (838 | ) | (285 | ) | ||||||||||||||||||
Income from ordinary activities before income taxes | (2,274 | ) | 3,168 | 2,211 | (4,262 | ) | (5,408 | ) | (2,810 | ) | (4,582 | ) | (1,585 | ) | ||||||||||||||||||
Income tax expense | (11 | ) | 212 | (15 | ) | (13 | ) | (10 | ) | 125 | (166 | ) | (20 | ) | ||||||||||||||||||
Non-controlling interest | (1 | ) | 2 | — | — | (2 | ) | 1 | 3 | 2 | ||||||||||||||||||||||
Total net income/(loss) | (2,286 | ) | 3,382 | 2,196 | (4,275 | ) | (5,420 | ) | (2,684 | ) | (4,745 | ) | (1,603 | ) | ||||||||||||||||||
(1) | Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP under ‘Non-GAAP measures and reconciliation’ section in this document. |
Analysis of Corporate Financial Results Comparing Quarter Ended December 31, 2007 and 2006
Key movements in Corporate between the fourth quarters of 2007 and 2006 were as follows:
ü | $3.1 million increase in net interest revenue less interest expenses mainly on account of interest costs recharged to other segments at market rates relating to the $130.0 million bridging facility. | ||
ü | $0.2 million increase in office and administration expenses mainly relating to non-cash stock compensation expense associated with our stock incentive plans for employees and directors recognized during the quarter. |
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LIQUIDITY AND CAPITAL RESOURCES
Summary of Debt facilities
Balance | ||||||||||||
outstanding Dec | ||||||||||||
Organization | Facility | 31, 2007 | Maturity date | |||||||||
Merrill Lynch bridging facility | $ | 130,000,000 | $ | 130,000,000 | May 3, 2008 | |||||||
OPIC secured loan | $ | 85,000,000 | $ | 71,500,000 | December 31, 2015 | |||||||
BNP Paribas working capital facility | $ | 170,000,000 | $ | 66,501,372 | (1) | August 31, 2008 |
(1) Excludes letters of credit outstanding of $32.0 million and bank guarantees on hedging facility outstanding of
$2.5 million.
$2.5 million.
Merrill Lynch bridging facility (Corporate)
InterOil entered into a loan agreement for $130.0 million on May 3, 2006 with Merrill Lynch and as at December 31, 2007 had fully drawn down the facility. The facility was for a fixed term of two years and is due for repayment on May 3, 2008. The agreement contains certain financial covenants which include the maintenance of minimum levels of fixed charge ratios, a maximum leverage ratio and limitations on the incurrence of additional indebtedness. The loan is secured over the assets of the downstream business and secondary security over refinery assets.
We plan to refinance this debt before the due date to meet these repayment obligations either by extending the facility, refinancing, raising equity or selling assets. We are currently in negotiations with Merrill Lynch to refinance the $130.0 million secured bridging facility. As part of these negotiations, subsequent to year end, the Company has received a draft term sheet which outlines the terms and conditions for the refinancing of this secured bridging facility with a combination of long term secured term loans and warrants. As at March 28, 2007, Management is working towards the finalization of the term sheet and refinancing of the facility before the due date of the facility.
We cannot assure that our business will generate cash flow from operations or that future borrowings will be available to us in an amount sufficient to enable us to pay our maturing indebtedness. As a result, we may need to refinance all or a portion of this debt, or to secure new financing before maturity. This, to some extent, is subject to general economic, financial, legislative and regulatory factors and other factors that are beyond our control. We cannot be sure that we will be able to obtain the refinancing or new financing on reasonable terms or at all.
OPIC secured loan (Midstream)
On June 12, 2001, the Company entered into a loan agreement with OPIC to secure a project financing facility of $85.0 million. The loan is secured over the assets of the refinery. The interest rate on the loan is equal to the treasury cost applicable to each promissory note outstanding plus 3% OPIC spread, and are payable quarterly in arrears. Half-yearly principal repayments of $4.5 million each are due on June 30 and December 31 of each year until the end of the loan agreement, being December 31, 2014.
In December 2006, the OPIC loan agreement was amended whereby the half yearly principal payment due in December 2006 and June 2007 of $4.5 million each was deferred until January 31, 2008 and February 29, 2008 respectively, and interest previously due on December 31, 2006 and June 30, 2007 were deferred until September 30, 2007. The normal repayment of interest and scheduled principal payments recommenced on September 30, 2007 and December 31, 2007 respectively. The deferred interest and principal payment due in December 31, 2007 were paid prior to year end. Subsequent to the year end, a further amendment was agreed with OPIC which deferred principal payments due in January 31, 2008 and February 29, 2008 to the end of the loan agreement, payable on June 30, 2015 and December 31, 2015.
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While cash flows from operations are expected to be sufficient to cover the costs of operating our refinery and the financing charges incurred under our crude import facility, should there be a major deterioration in refining margins or the pricing review not yield an agreement for the revision of the pricing formula applicable to our refined product, our refinery may not generate sufficient cash flows to cover all of the interest and principal payments under our secured loan agreements. As a result, we may be required to raise additional capital and/or refinance these facilities in the future. We can provide no assurances that we will be able to obtain such additional capital or that our lenders will agree to refinance these facilities, or, if available, that the terms of any such capital raising or refinancing will be acceptable to us.
BNP Paribas working capital facility (Midstream)
On August 9, 2007, approval was received for the renewal of Secured Revolving Crude Import Facility with BNP Paribas (Singapore Branch), for $170.0 million. This crude import facility is used to finance purchases of crude feedstock for our refinery. Our ability to borrow additional amounts under this crude import facility currently expires on August 31, 2008. As of December 31, 2007, $69.0 million remained available for use under the crude import facility. The weighted average interest rate under the crude import facility was 7.01% for the year ended December 31, 2007.
We expect to be able to renew this facility for another year when it expires on August 31, 2008. The renewal negotiations with BNP will commence in second quarter of 2008.
Other Sources of Capital
Upstream
We fund our Upstream capital expenditures for exploration on the drilling program using the proceeds of the $125.0 million Indirect Participation Interest (IPI) Agreement that we entered into in February 2005. For expenditures on the extended well program and other appraisal wells, funding of our share of these costs is sourced from operational cash flows, secured loans or equity raising activities. Cash calls are also made from IPI investors for their share of interest in these appraisal wells.
In December, 2007, we completed a common stock private placement yielding gross proceeds of $25.0 million, after having previously (on November 21, 2007) completed a private placement of convertible preference stock yielding gross proceeds of $15.0 million. The funds from these offerings are being used for appraisal and development of the Elk/Antelope structures.
Downstream
Our Downstream working capital and capital investment programs are funded by cash generated from operating activities.
Summary of Cash Flows
($ thousands) | 2007 | 2006 | 2005 | |||||||||
Net cash inflows/(outflows) from: | ||||||||||||
Operations | (40,717 | ) | 2,187 | (22,713 | ) | |||||||
Investing | (25,273 | ) | (97,071 | ) | (64,942 | ) | ||||||
Financing | 78,170 | 66,964 | 118,712 | |||||||||
Net cash movement | 12,180 | (27,920 | ) | 31,057 | ||||||||
Opening cash | 31,681 | 59,601 | 28,544 | |||||||||
Closing cash | 43,862 | 31,681 | 59,601 | |||||||||
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Operating Activities
For the year ended 2007 cash used in our operating activities was $40.7 million compared with cash generated by operating activities of $2.2 million in 2006. The operating cash flows for these periods include:
ü | $5.0 million inflow in our cash provided by operations, prior to changes in non-cash working capital, compared to a cash outflow of $22.6 million in 2006. This was due to higher margins from our Midstream and Downstream operations compared to the prior period. | |
ü | $45.7 million outflow in non-cash working capital as compared to $24.8 million inflow for same period of 2006. These working capital movements relate to the timing of receipts, payments and inventory purchases, along with the increasing crude and product price environment. |
Investing Activities
For the year 2007, cash used in our investing activities was $25.2 million compared with $97.1 million for the year 2006. During these periods, the cash used on investing activities consisted primarily of:
ü | $69.1 million outflow on oil and gas exploration expenditure for the year 2007 relating to Elk extended well program versus $48.0 million in same period of 2006 related to drilling and seismic activities. The Elk extended well program is not directly covered by the initial indirect participation interest contributions. Therefore, we must make separate cash calls for the IPI Investors share of these costs. | |
ü | $7.0 million inflow in 2007 on settlement of the insurance claim for Elk well blowout. | |
ü | $21.8 million inflow from cash calls from IPI investors in relation to the Elk extended well programs. | |
ü | $10.1 million inflow due to decrease in our secured cash balances year 2007 versus an outflow due to increase of $15.9 million in same period of 2006. | |
ü | $3.3 million outflow as final payment in 2007 to acquire Shell Papua New Guinea as compared to $25.8 million payment in same period of 2006 as deposit on acquisition of Shell which was effective October 1, 2006. | |
ü | $7.3 million outflow for plant and equipment in the year 2007 related to LNG project deferred costs proportionately consolidated and Downstream projects versus $13.6 million in same period of 2006 which primarily related to revamp and optimization activities undertaken by the refinery. |
Financing Activities
For the year 2007, cash proceeds from our financing activities amounted to $78.2 million. The cash movements generated by financing activities were primarily due to:
ü | $5.9 million inflow from Clarion Finanz on entering into an option agreement relating to the Elk well. | |
ü | $29.6 million inflow from the BNP Paribas working capital facility as compared to $33.9 million of repayments during 2006. | |
ü | $4.5 million outflow on repayment of the OPIC secured loan. During 2006, $125.3 million was received as draw down from bridging facility, and $21.5 million and $4.5 million repaid of the unsecured and secured loans respectively. | |
ü | $9.5 million inflow from cash calls to joint venture partners in issue of ‘B’ class shares | |
ü | $23.8 million inflow from the issuance of common shares in 2007 as compared to $1.5 million received in 2006. | |
ü | $14.3 million inflow from the issuance of preference shares in 2007. |
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Capital Expenditures
Upstream Capital Expenditures
Gross capital expenditures for exploration in Papua New Guinea for the year ended December 31, 2007 were $69.1 million compared with $49.7 million during the same periods in 2006. Our capital expenditures for 2007 consisted of:
ü | $19.3 million for seismic acquisition costs relating to Elk extended well program. | |
ü | $25.8 million on drilling Elk-2 appraisal well as part of the Elk extended well program. | |
ü | $7.6 million on testing Elk-2 appraisal well as part of the Elk extended well program. | |
ü | $11.1 million on drilling Elk-4 appraisal well as part of the Elk extended well program. | |
ü | $2.7 million on preparatory costs on Antelope-1, being a potential exploratory well. | |
ü | Fixed assets and inventory movement made up the balance of the expenditure. |
The IPI investors are required to fund 31.55% of the Elk extended well program costs to maintain their interest in the well program. The amounts capitalized in our books, or expensed as incurred, in relation to the extended well program are the net amounts after adjusting the IPI interest in the program.
Midstream Capital Expenditures
There were no major capital expenditures in our Midstream refinery business segment for the year ended December 31, 2007. Capital expenditures of $12.0 million during 2006 primarily related to our refinery optimization program that was completed during the third quarter of that year.
Downstream Capital Expenditures
Capital expenditures for the Downstream wholesale and retail distribution business segment were $5.2 million for 2007 compared with $10.5 million during the same period in 2006. Our 2007 capital expenditures mainly consisted of final payments for the acquisition of Shell’s Papua New Guinea business and costs associated with the construction and purchase of storage tanks and related infrastructure and new fuel distribution software for the Downstream business.
Capital Requirements
The capital requirements for each of our business segments are discussed below. The oil and gas industry is capital intensive and our business plans necessarily involve raising additional capital. The availability and cost of such capital is highly dependent on market conditions at the time we raise such capital. No assurance can be given that we will be successful in obtaining new sources of capital on terms that are acceptable to us.
Upstream
We are obliged under our $125.0 million indirect participation agreement entered into in February 2005 to drill eight exploration wells. We completed our third exploration well, Elk-1, in November 2006, for which drilling costs increased as a result of a discovery with high pressure gas and gas liquids. The higher costs incurred at the Elk-1 well were partially funded by the receipt of $7.0 million under our “Control of Well” insurance policy during the year. We believe that we will be able to meet the obligations to drill the remaining five wells under the indirect participation agreement. We may have to raise additional funds in order for us to complete the program and meet the obligation under the agreement. The cost of drilling exploration wells in Papua New Guinea is subject to numerous factors, including the location where such wells are drilled. If we are unable to drill future exploration wells at a cost per well that is significantly lower than the current cost of the Elk discovery well drilled pursuant to this agreement, we may not have sufficient funds to satisfy our obligations under the indirect participation agreement, and would look to farm out or raise additional capital. However, we can provide no assurances that a farm out will be completed, that the terms of any such farm out will be acceptable to us or that we will be successful in raising additional capital. As of December 31, 2007, we had incurred $79.4 million in
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capital expenditures pursuant to the indirect participation interest related to the drilling of exploration wells and associated assets required for the program.
In order to evaluate the Elk discovery of gas and gas liquids, we will be required to drill additional appraisal wells. We are required to obtain the consent of the investors under the indirect participation interest agreement to use proceeds raised under the agreement to drill non-exploration wells or we will be required to raise additional funds to support this development. We can provide no assurances that we will be able to obtain such approvals or financing on terms that are acceptable.
We will also be required to attract funding for the Elk field development and delivery of gas to the LNG project. We plan to use a combination of debt, equity and partial sale of capitalized properties to strategic investors to raise adequate capital. The availability and cost of various sources of financing is highly dependent on market conditions at the time and we can provide no assurances that we will be able to obtain such financing or conduct such sales on terms that are acceptable.
Midstream — Refining
We believe that we will have sufficient funds from our operating cashflows to pay our estimated capital expenditures for 2008. Additionally, we also believe cash flows from operations are expected to be sufficient to cover the costs of operating our refinery and the financing charges incurred under our crude import facility. Should there be a major deterioration in refining margins or the pricing review not yield an agreement for the revision of the pricing formula applicable to our refined product, our refinery may not generate sufficient cash flows to cover all of the interest and principal payments under our secured loan agreements. As a result, we may be required to raise additional capital and/or refinance these facilities in the future. We can provide no assurances that we will be able to obtain such additional capital or that our lenders will agree to refinance these facilities, or, if available, that the terms of any such capital raising or refinancing will be acceptable to us.
Midstream — Liquefaction
Completion of any LNG facility will require substantial amounts of financing and construction will take a number of years to complete. As a joint venture partner in the project, if the project proceeds we would be required to fund our share of the development costs after the initial costs of $200.0 million are funded by our joint venture partners to equalize their shareholding. No assurances can be given that we will be able to source sufficient gas reserves, successfully construct such a facility, or as to the timing of such construction. We plan to use a combination of debt, equity and partial sale of capitalized properties to strategic investors to raise adequate capital. The availability and cost of such capital is highly dependent on market conditions at the time we raise such capital. We can provide no assurances that we will be able to obtain such financing or conduct such sales on terms that are acceptable to us.
Downstream
We believe on the basis of current market conditions and the status of this business that our cash flows from operations will be sufficient to meet our estimated capital expenditures for our wholesale and retail distribution business segment for 2008.
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Contractual Obligations and Commitments
The following table contains information on payments for contracted obligations due for each of the next five years and thereafter. It should be read in conjunction with our financial statements in the year ended December 31, 2007 and the notes thereto:
Payments Due by Period | ||||||||||||||||||||||||||||
Less | More | |||||||||||||||||||||||||||
Contractual obligations | than 1 | 1 – 2 | 2 – 3 | 3 – 4 | 4 – 5 | than 5 | ||||||||||||||||||||||
($ thousands) | Total | year | years | years | years | years | years | |||||||||||||||||||||
Secured loan obligations | 199,310 | 136,810 | 9,000 | 9,000 | 9,000 | 9,000 | 26,500 | |||||||||||||||||||||
Accrued financing costs | 1,088 | 1,088 | — | — | — | — | — | |||||||||||||||||||||
Indirect participation interest(1) | 1,924 | 1,080 | 844 | — | — | — | — | |||||||||||||||||||||
Indirect participation interest(2) | 96,086 | — | 96,086 | — | — | — | — | |||||||||||||||||||||
PNG LNG Inc. Joint Venture (proportionate share of commitments) | 388 | — | 236 | 152 | — | — | — | |||||||||||||||||||||
Petroleum prospecting and retention licenses(3) | 7,899 | 2,183 | 5,716 | — | — | — | — | |||||||||||||||||||||
Total | 306,695 | 141,161 | 111,882 | 9,152 | 9,000 | 9,000 | 26,500 | |||||||||||||||||||||
(1) | These amounts represent the estimated cost of completing our commitment to drill exploration wells under our indirect participation interest agreement entered into in July 2003. See Note 18 to our audited financial statements for the year ended December 31, 2007. | |
(2) | The liability presented in relation to indirect participation interest is not a cash commitment and will be resolved once the IPI investors have elected to convert their interests into a joint venture interest or shares in InterOil Corporation. InterOil’s commitment is to complete the eight well drilling program. As at December 31, 2007, management estimate that a further $47.4 million will be required to be spent to fulfill this commitment. | |
(3) | The amount pertaining to the petroleum prospecting and retention licenses represents the amount InterOil has committed to its joint venture partners to spend. In addition to this amount, InterOil must drill an exploration well in Petroleum Prospecting License 237 prior to the end of March 2009 in order to retain this license. As the cost of drilling this well cannot be estimated, it is not included within the above table. |
Off Balance Sheet Arrangements
Neither during the year ended, nor as at December 31, 2007, did we have any off balance sheet arrangements or any relationships with unconsolidated entities or financial partnerships.
Transactions with Related Parties
Petroleum Independent and Exploration Corporation, a company owned by Mr. Mulacek, our Chairman and Chief Executive Officer, earned management fees of $150,000 during 2007 (2006 — $150,000). This management fee relates to Petroleum Independent and Exploration Corporation being appointed the General Manager of one of our subsidiaries, S.P. InterOil, LDC.
Breckland Limited provides technical and advisory services to us on normal commercial terms. Mr. Roger Grundy, one of our directors, is also a director of Breckland Limited and he provides consulting services to us as an employee of Breckland. Amounts paid or payable to Breckland Limited during the year ended December 31, 2007 amounted to $39,416 (2006 — $140,165).
Amounts due to directors and executives at December 31, 2007 totaled $nil for directors fees (December 2006 — $18,000) and $nil for executive bonuses (December 2006 — $nil). An amount of $130,000 (2006 — $91,500) was paid to the directors for directors’ fees during the year.
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Share Capital
Our authorized share capital consists of an unlimited number of common shares and unlimited number of preferred shares, of which 1,035,554 series A preference shares are authorized. As of December 31, 2007, we had 31,026,356 common shares outstanding and 36,393,552 common shares on a fully diluted basis.
As of March 28, 2008, we had 31,026,356 common shares outstanding, 35,971,775 common shares on a fully diluted basis and 517,777 series A preferred shares outstanding.
Derivative Instruments
Our revenues are derived from the sale of refined products. Prices for refined products and crude feedstocks are extremely volatile and sometimes experience large fluctuations over short periods of time as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions. Due to the nature of our business, there is always a time difference between the purchase of a crude feedstock and its arrival at the refinery and the supply of finished products to the various markets.
Generally, we are required to purchase crude feedstock two months forward, whereas the supply/export of finished products will take place after the crude feedstock is discharged and processed. Because of this timing difference, there is an impact on our cost of crude feedstocks and the revenue from the proceeds of the sale of products, due to the fluctuation in prices during the time period. Therefore, we use various derivative instruments as a tool to reduce the risks of changes in the relative prices of our crude feedstocks and refined products. Such an activity is better known as hedging and risk management. These derivatives, which we use to manage our price risk, effectively enable us to lock-in the refinery margin such that we are protected in the event that the difference between our sale price of the refined products and the acquisition price of our crude feedstocks contracts are reduced. On the flip side, when we have locked-in the refinery margin and if the difference between our sales price of the refined products vis-à-vis our acquisition price of crude feedstocks expands or increase, then the benefits would be limited to the locked-in margin.
The derivatives instrument which we generally use is the over-the-counter (OTC) swap. The swaps transactions are concluded between counterparties in the derivatives swaps market, unlike futures which are transacted on the IPE and Nymex Exchanges. It is common place among refiners and trading companies in the Asia Pacific market to use derivatives swaps as a tool to hedge their price exposures and margins. Due to the wide usage of derivatives tools in the Asia Pacific region, the swaps market generally provides sufficient liquidity for the hedging and risk management activities. The derivatives swaps instrument covers commodities or products such as jet and kerosene, diesel, naphtha, and also crudes such as Tapis and Dubai. Using these tools, we actively engage in hedging activities to lock in margins. Occasionally, there is insufficient liquidity in the crude swaps market and we then use other derivative instrument such as Brent futures on the IPE Exchange to hedge our crude costs.
For a description of our current derivative contracts as of December 31, 2007, see Note 8 to our financial statements for the year ended December 31, 2007 and 2006.
At December 31, 2007, InterOil had a net payable of $1,960,300 (2006 – net receivable of $1,759,575, 2005 – net receivable of $1,482,798) relating to commodity hedge contracts. Of this total, a receivable of $nil (2006 – payable of $45,925, 2005 – receivable of $897,798) relates to hedges deemed effective at December 31, 2007 and a payable of $1,960,300 (2006 – receivable of $1,805,500, 2005 – receivable of $585,000) relates to outstanding derivative contracts for which hedge accounting was not applied or had been discontinued. The gain/(loss) on hedges for which final pricing will be determined in future periods was nil (2006 — $1,385, 2005 — $1,016,998) and has been included in comprehensive income.
There were no outstanding hedge accounted contracts on which final pricing was to be determined in future periods as at December 31, 2007.
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The following summarizes the hedge accounted contracts by derivative type on which final pricing will be determined in future periods as at December 31, 2006:
Derivative | Type | Notional volumes (bbls) | ||||
Naphtha swap | Sell Naphtha | 175,000 |
As at December 31, 2005:
Derivative | Type | Notional volumes (bbls) | ||||
Crude swap | Sell crude | 300,000 | ||||
Crude swap | Buy crude | 250,000 | ||||
Jet kerosene crack spread swap | Sell jet kero/buy crude | 249,999 |
In addition to the above hedge accounted contracts, as at December 31, 2007, the Company had the following open non-hedge accounted derivative contracts outstanding. All gains/losses on these contracts are included in general and administration expenses for the period.
As at December 31, 2007:
Derivative | Type | Notional volumes (bbls) | ||||
Brent contracts to manage export price risk | Sell Brent | 130,000 | ||||
Naphtha swap | Sell Naphtha | 150,000 |
As at December 31, 2006:
Derivative | Type | Notional volumes (bbls) | ||||
Brent contracts to manage export price risk | Sell Brent | 320,000 |
As at December 31, 2005:
Derivative | Type | Notional volumes (bbls) | ||||
Crude swap | Sell Crude | 50,000 |
We will continue with our hedging and risk management program in 2008 and we will continue to evaluate new approaches to enhance our hedging arrangement and margin protection.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with Canadian GAAP requires our management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The following accounting policies involve estimates that are considered critical due to the level of sensitivity and judgment involved, as well as the impact on our consolidated financial position and results of operations. The information about our critical accounting estimates should be read in conjunction with Note 3 of the notes to our consolidated financial statements for the year ended December 31, 2007, which summarizes our significant accounting policies.
Income Taxes
We use the asset and liability method of accounting for income taxes. Under the asset and liability method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.
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Future tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date of enactment or substantive enactment. A valuation allowance is provided against any portion of a future tax asset which will more than likely not be recovered. If actual results differ from the estimates or we adjust the estimates in future periods, we may need to record a valuation allowance. The net deferred income tax assets as of December 31, 2007 and 2006 were $2.9 million and $1.4 million, respectively.
Oil and Gas Properties
We use the successful-efforts method to account for our oil and gas exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. We continue to carry as an asset the cost of drilling exploratory wells if the required capital expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near future, or when exploration and evaluation activities have not yet reached a stage to allow reasonable assessment regarding the existence of economical reserves. Capitalized costs for producing wells will be subject to depletion using the units-of-production method. Geological and geophysical costs are expensed as incurred. If our plans change or we adjust our estimates in future periods, a reduction in our oil and gas properties asset will result in a corresponding increase in the amount of our exploration expenses. The net costs of drilling exploratory wells carried as an asset as of December 31, 2007 and 2006 were $62.5 million and $41.0 million.
Asset Retirement Obligations
Estimated costs of future dismantlement, site restoration and abandonment of properties are provided based upon current regulations and economic circumstances at year end. Management estimates there are no material obligations associated with the retirement of the refinery or with its normal operations relating to future restoration and closure costs. The refinery is located on land leased from the Independent State of Papua New Guinea. The lease expires on July 26, 2097. Future legislative action and regulatory initiatives could result in changes to our operating permits which may result in increased capital expenditures and operating costs.
Environmental Remediation
Remediation costs are accrued based on estimates of known environmental remediation exposure. Ongoing environmental compliance costs, including maintenance and monitoring costs, are expensed as incurred. Provisions are determined on an assessment of current costs, current legal requirements and current technology. Changes in estimates are dealt with on a prospective basis. We currently do not have any amounts accrued for environmental remediation obligations. Future legislative action and regulatory initiatives could result in changes to our operating permits which may result in increased capital expenditures and operating costs.
Impairment of Long-Lived Assets
We are required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas assets, for potential impairment. We test long-lived assets for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to earnings. In order to determine fair value, our management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates and growth rates, that could significantly impact the fair value of the asset being tested for impairment. Due to the significant subjectivity of the assumptions used to test for recoverability and to determine fair value, changes in market conditions could result in significant impairment charges in the future, thus affecting our earnings. Our impairment evaluations are based on assumptions that are consistent with our business plans. However, providing sensitivity analysis if other assumptions were used in performing the impairment evaluations is not practicable due to the significant number of assumptions involved in the estimates.
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Legal and Other Contingent Matters
We are required to determine whether a loss is probable based on judgment and interpretation of laws and regulations and whether the loss can reasonably be estimated. When the amount of a contingent loss is determined it is charged to earnings. Our management continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstances.
NEW ACCOUNTING STANDARDS
Financial Instruments and Capital Disclosures
Effective January 1, 2008 the Company will adopt the following new CICA sections:
CICA 3862 – Financial Instruments – Disclosures
• | CICA 3863 – Financial Instruments – Presentation; and | ||
• | CICA 1535 – Capital Disclosures |
Section 3862 and 3863 – Financial Instruments – Disclosures and Presentation:
The objectives of these Sections are to require entities to provide disclosures in their financial statements that enable users to evaluate:
a. the significance of financial instruments for the entity’s financial position and performance.
b. the nature and extent of risks arising from financial instruments to which the entity is exposed during the period and at the balance sheet date, and how the entity manages those risks; and
c. to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows.
These revised sections would require InterOil to disclose additional information on the risk arising from financial instruments to which InterOil is exposed to, mainly relating to the derivative transactions of the Company. InterOil will apply the provisions of these new Sections to all interim and annual financial statements issued by the Company effective January 1, 2008.
Section 1535 – Capital Disclosures:
This Section establishes standards for disclosing information about an entity’s capital and how it is managed. This section would require InterOil to disclose information that enables users of its financial statements to evaluate the entity’s objectives, policies and processes for managing capital. InterOil will apply the provisions of these new Sections to all interim and annual financial statements issued by the Company effective January 1, 2008.
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NON-GAAP MEASURES AND RECONCILIATION
Earnings before interest, taxes, depreciation and amortization, commonly referred to as 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 InterOil to analyze operating performance. EBITDA does not have a standardized meaning prescribed by United States or Canadian generally accepted accounting principles 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 Canadian generally accepted accounting principles. Further, EBITDA is not a measure of cash flow under Canadian generally accepted accounting principles and should not be considered as such. For reconciliation of EBITDA to the net income (loss) under GAAP, refer to the Non GAAP Measures Reconciliation of this MD&A.
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The following table reconciles net income (loss), a Canadian GAAP measure, to EBITDA, a non-GAAP measure for each of the last eight quarters.
Quarters ended | 2007 | 2006 | ||||||||||||||||||||||||||||||
($ thousands) | Dec 31 | Sep 30 | Jun 30 | Mar 31 | Dec 31 | Sep 30 | Jun 30 | Mar 31 | ||||||||||||||||||||||||
Upstream | (3,128 | ) | (5,015 | ) | (5,492 | ) | (4,009 | ) | (719 | ) | (1,107 | ) | (1,922 | ) | (5,136 | ) | ||||||||||||||||
Midstream — Refining | 9,589 | (1,332 | ) | 3,775 | 6,335 | 9,144 | 1,674 | (8,188 | ) | (5,229 | ) | |||||||||||||||||||||
Midstream — Liquefaction | (797 | ) | (4,104 | ) | (444 | ) | (322 | ) | (396 | ) | (298 | ) | — | — | ||||||||||||||||||
Downstream | 3,627 | 3,301 | 2,760 | 3,028 | 1,143 | 1,954 | 3,559 | (326 | ) | |||||||||||||||||||||||
Corporate and Consolidated | (2,394 | ) | (3,105 | ) | 4,959 | (1,930 | ) | (2,299 | ) | (853 | ) | (3,770 | ) | (1,321 | ) | |||||||||||||||||
Earnings before interest, taxes, depreciation and amortization | 6,897 | (10,255 | ) | 5,557 | 3,102 | 6,873 | 1,370 | (10,323 | ) | (12,014 | ) | |||||||||||||||||||||
Subtract: | ||||||||||||||||||||||||||||||||
Upstream | — | — | — | — | 2 | 1 | 1 | 1 | ||||||||||||||||||||||||
Midstream — Refining | 4,397 | 8,155 | 2,156 | 2,091 | 2,479 | 3,329 | 2,731 | 2,343 | ||||||||||||||||||||||||
Midstream — Liquefaction | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Downstream | 1,145 | 3,320 | (67 | ) | 40 | 37 | 38 | 39 | 38 | |||||||||||||||||||||||
Corporate and Consolidated | (99 | ) | (6,252 | ) | 2,768 | 2,351 | 3,131 | 1,981 | 838 | 285 | ||||||||||||||||||||||
Interest expense | 5,443 | 5,223 | 4,857 | 4,482 | 5,649 | 5,349 | 3,609 | 2,667 | ||||||||||||||||||||||||
Upstream | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Midstream — Refining | 43 | (69 | ) | (12 | ) | 17 | 42 | (46 | ) | (137 | ) | (118 | ) | |||||||||||||||||||
Midstream — Liquefaction | 13 | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Downstream | 1,112 | (261 | ) | 32 | 483 | 996 | 416 | 1,005 | (144 | ) | ||||||||||||||||||||||
Corporate and Consolidated | 12 | (214 | ) | 15 | 14 | 11 | (126 | ) | 163 | 17 | ||||||||||||||||||||||
Income taxes and non-controlling interest | 1,180 | (544 | ) | 35 | 514 | 1,049 | 244 | 1,031 | (245 | ) | ||||||||||||||||||||||
Upstream | 134 | (299 | ) | 338 | 309 | 233 | 202 | 173 | 198 | |||||||||||||||||||||||
Midstream — Refining | 2,159 | 2,781 | 2,749 | 2,717 | 2,805 | 2,700 | 2,626 | 2,598 | ||||||||||||||||||||||||
Midstream — Liquefaction | 15 | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Downstream | 700 | 497 | 552 | 455 | 537 | 222 | 89 | 62 | ||||||||||||||||||||||||
Corporate and Consolidated | (21 | ) | (20 | ) | (20 | ) | (21 | ) | (21 | ) | (24 | ) | (26 | ) | (20 | ) | ||||||||||||||||
Depreciation and amortization | 2,987 | 2,959 | 3,619 | 3,460 | 3,554 | 3,100 | 2,862 | 2,838 | ||||||||||||||||||||||||
Upstream | (3,262 | ) | (4,716 | ) | (5,831 | ) | (4,318 | ) | (954 | ) | (1,310 | ) | (2,098 | ) | (5,335 | ) | ||||||||||||||||
Midstream — Refining | 2,990 | (12,199 | ) | (1,117 | ) | 1,511 | 3,818 | (4,309 | ) | (13,408 | ) | (10,052 | ) | |||||||||||||||||||
Midstream — Liquefaction | (825 | ) | (4,104 | ) | (444 | ) | (322 | ) | (396 | ) | (298 | ) | — | — | ||||||||||||||||||
Downstream | 670 | (255 | ) | 2,242 | 2,050 | (427 | ) | 1,278 | 2,426 | (282 | ) | |||||||||||||||||||||
Corporate and Consolidated | (2,286 | ) | 3,382 | 2,196 | (4,275 | ) | (5,420 | ) | (2,684 | ) | (4,745 | ) | (1,603 | ) | ||||||||||||||||||
Net income (loss) per segment | (2,713 | ) | (17,892 | ) | (2,954 | ) | (5,354 | ) | (3,379 | ) | (7,323 | ) | (17,825 | ) | (17,272 | ) | ||||||||||||||||
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STATEMENT REGARDING DISCLOSURE CONTROLS
As of December 31, 2007, an evaluation was carried out, under the supervision of and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the our disclosure controls and procedures as defined under Multilateral Instrument 52-109 — Certification on Disclosure in Issuers’ Annual and Interim Filing. Based on the evaluation, the Chief Executive Officer and Chief Financial Officer identified no control deficiencies in our internal controls over financial reporting as of December 31 2007. Should control deficiencies be identified, their potential effects on the financial statements, and our plans for remediation will be been described in Management’s S404 Certification.
PUBLIC SECURITIES FILINGS
You may access additional information about us, including our Annual Information Form for the year ended December 31, 2007, which is filed with the Canadian Securities Administrators at www.sedar.com, and our Form 40-F, which is filed with the U.S. Securities and Exchange Commission at www.sec.gov.
GLOSSARY OF TERMS
Barrel, Bbl (petroleum)Unit volume measurement used for petroleum and its products.
BPBP Singapore Pte Limited.
CondensateA component of natural gas which is a liquid at surface conditions.
Crack spreadThe simultaneous purchase or sale of crude against the sale or purchase of refined petroleum products. These spread differentials which represent refining margins are normally quoted in dollars per barrel by converting the product prices into dollars per barrel and subtracting the crude price.
Crude OilA mixture consisting mainly of pentanes and heavier hydrocarbons that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain small amounts of sulphur and other non-hydrocarbons but does not include liquids obtained from the processing of natural gas.
EBITDAEarnings before interest, taxes, depreciation and amortization. EBITDA represents net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is used to analyze operating performance.
Farm outA contractual agreement with an owner who holds a working interest in an oil and gas lease to assign all or part of that interest to another party in exchange for the other party’s fulfillment of contractually specified conditions. Farm out agreements often stipulates that the other party must drill a well to a certain depth, at a specified location, within a certain time frame; furthermore, typically, the well must be completed as a commercial producer to earn an assignment of the working interest. The assignor of the interest usually reserves a specified overriding royalty interest, with the option to convert the overriding royalty interest to a specified working interest upon payout of drilling and production expenses.
FEEDFront end engineering and design.
FeedstockRaw material used in a processing plant.
FIDFinal investment decision
GAAPGenerally accepted accounting principles.
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GasA mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs but are gaseous at atmospheric conditions. Natural gas may contain sulphur or other non-hydrocarbon compounds.
ICCCIndependent Consumer and Competition Commission in Papua New Guinea.
IPFInterOil Power Fuel. InterOil’s marketing name for low sulphur waxy residue oil.
IPPImport Parity Price. For each refined product produced and sold locally in Papua New Guinea, IPP is calculated by adding the costs that would typically be incurred to import such product to the average posted price for such product in Singapore as reported by Platts. The costs that are added to the reported Platts price include freight costs, insurance costs, landing charges, losses incurred in the transportation of refined products, demurrage and taxes.
IPWIIndirect Participation Working Interest.
LNGLiquefied natural gas. Natural gas converted to a liquid state by pressure and severe cooling, then returned to a gaseous state to be used as fuel. LNG is moved in tankers, not via pipelines. LNG, which is predominantly artificially liquefied methane, is not to be confused with NGLs, natural gas liquids, which are heavier fractions that occur naturally as liquids.
LPGLiquefied petroleum gas, typically ethane, propane butane and isobutane. Usually produced at refineries or natural gas processing plants, including plants that fractionate raw natural gas plant liquids. LPG can also occur naturally as a condensate.
LSWRLow sulfur waxy residual fuel oil.
Mark-to-marketUsed to evaluate futures/option positions using current market prices to determine profit/loss. The profit/loss can then be paid, collected or simply tracked daily.
NaphthaThat portion of the distillate obtained in the refinement of petroleum which is an intermediate between the lighter gasoline and the heavier benzene, has a specific gravity of about 0.7, and is used as a solvent for varnishes, illuminant, and other similar products.
Natural gasA naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.
PGKCurrency of Papua New Guinea.
PDLPetroleum Development License. The right given by the Independent State of Papua New Guinea to develop a field in readiness for commercial production.
PPLPetroleum Prospecting License. The tenement given by the Independent State of Papua New Guinea to explore for oil and gas.
PRLPetroleum Retention License. The tenement given by the Independent State of Papua New Guinea to allow the licensee holder to evaluate the commercial and technical options for the potential development of an oil and/or gas field.
Sweet/sour crudeDefinitions which describe the degree of a given crude’s sulfur content. Sour crudes are high in sulfur, sweet crudes are low.
Working interestAn interest in a mineral property that entitles the owner of such interest to a share of the mineral productions from the property with the share based on such owner’s relative interest.
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Natural gas measurementsThe following are some of the standard abbreviations used in natural gas measurement.
Mcf:standard abbreviation for 1,000 cubic feet.
Bil cu ft:Billion cubic feet. Also abbreviated to bcf.
Tcf:trillion cubic feet.
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