InterOil Corporation Management Discussion and Analysis
For the Year ended December 31, 2011 March 16, 2012 | ![]() |
TABLE OF CONTENTS |
FORWARD-LOOKING STATEMENTS | 2 |
OIL AND GAS DISCLOSURES | 4 |
INTRODUCTION | 4 |
BUSINESS STRATEGY | 5 |
OPERATIONAL HIGHLIGHTS | 5 |
SELECTED ANNUAL FINANCIAL INFORMATION AND HIGHLIGHTS | 9 |
YEAR AND QUARTER IN REVIEW | 15 |
LIQUIDITY AND CAPITAL RESOURCES | 23 |
INDUSTRY TRENDS AND KEY EVENTS | 32 |
RISK FACTORS | 34 |
CRITICAL ACCOUNTING ESTIMATES | 35 |
NEW ACCOUNTING STANDARDS | 36 |
NON-GAAP MEASURES AND RECONCILIATION | 39 |
PUBLIC SECURITIES FILINGS | 41 |
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING | 41 |
GLOSSARY OF TERMS | 41 |
The following Management Discussion and Analysis (“MD&A”) should be read in conjunction with our audited annual consolidated financial statements and accompanying notes for the year ended December 31, 2011 and our annual information form (the “2011 Annual Information Form”) for the year ended December 31, 2011. The MD&A was prepared by management and provides a review of our performance in the year ended December 31, 2011, and of our financial condition and future prospects.
Our financial statements and the financial information contained in this MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board applicable to the preparation of financial statements, including IFRS 1 – ‘First-time Adoption of International Financial Reporting Standards’, and are presented in United States dollars (“USD”) unless otherwise specified. Our transition date to IFRS was January 1, 2010. Financial information for 2010 included in this MD&A has been restated in accordance with IFRS. Financial information for 2009 included in this MD&A has been prepared in accordance with previous GAAP.
References to “we,” “us,” “our,” “Company,” and “InterOil” refer to InterOil Corporation or InterOil Corporation and its subsidiaries as the context requires. Information presented in this MD&A is as at December 31, 2011 and for the quarter and year ended December 31, 2011, unless otherwise specified. A listing of specific defined terms can be found in the “Glossary of Terms” section of this document.
Management Discussion and Analysis INTEROIL CORPORATION 1 |
FORWARD-LOOKING STATEMENTS |
This MD&A contains “forward-looking statements” as defined in U.S. federal and Canadian securities laws. Such statements are generally identifiable by the terminology used such as “may,” “plans,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “forecasts,” “budgets,” “targets” or other similar wording suggesting future outcomes or statements regarding an outlook. We have based these forward-looking statements on our current expectations and projections about future events. All statements, other than statements of historical fact, included in or incorporated by reference in this MD&A are forward-looking statements.
Forward-looking statements include, without limitation, our business strategies and plans; plans for our exploration (including drilling plans) and other business activities and results therefrom; characteristics of our properties; entering into definitive agreements with our joint venture partners; the construction of proposed liquefaction facilities and condensate stripping facilities in Papua New Guinea; the development of such liquefaction and condensate stripping facilities; the timing and cost of such development; the commercialization and monetization of any resources; whether sufficient resources will be established; the likelihood of successful exploration for gas and gas condensate or other hydrocarbons; re-commissioning of our CRU; cash flows from operations; sources of capital and its sufficiency; operating costs; contingent liabilities; environmental matters; and plans and objectives for future operations; the timing, maturity and amount of future capital and other expenditures.
Many risks and uncertainties may affect the matters addressed in these forward-looking statements, including but not limited to:
· | our ability to finance the development of liquefaction and condensate stripping facilities; |
· | our ability to negotiate definitive agreements following conditional agreements or heads of agreement relating to the development of liquefaction and condensate stripping facilities, or to otherwise negotiate and secure arrangements with other entities for such development and the associated financing thereof; |
· | the uncertainty associated with the availability, terms and deployment of capital; |
· | our ability to construct and commission our liquefaction and condensate stripping facilities together with the construction of the common facilities and pipelines, on time and within budget; |
· | our ability to obtain and maintain necessary permits, concessions, licenses and approvals from relevant PNG government authorities to develop our gas and condensate resources and to develop liquefaction and condensate stripping facilities within reasonable time periods and upon reasonable terms; |
· | the inherent uncertainty of oil and gas exploration activities; |
· | the availability of crude feedstock at economic rates; |
· | the uncertainty associated with the regulated prices at which our products may be sold; |
· | difficulties with the recruitment and retention of qualified personnel; |
· | losses from our hedging activities; |
· | fluctuations in currency exchange rates; |
· | political, legal and economic risks in Papua New Guinea; |
· | landowner claims and disruption; |
Management Discussion and Analysis INTEROIL CORPORATION 2 |
· | compliance with and changes in Papua New Guinean laws and regulations, including environmental laws; |
· | the inability of our refinery to operate at full capacity; |
· | the impact of competition; |
· | the adverse effects from importation of competing products contrary to our legal rights; |
· | the margins for our products and adverse effects on the value of our refinery; |
· | inherent limitations in all control systems, and misstatements due to errors that may occur and not be detected; |
· | exposure to certain uninsured risks stemming from our operations; |
· | contractual defaults; |
· | interest rate risk; |
· | weather conditions and unforeseen operating hazards; |
· | general economic conditions, including any further economic downturn, the availability of credit the European sovereign debt credit crisis and the downgrading of United States government debt; |
· | the impact of our current debt on our ability to obtain further financing; |
· | risk of legal action against us; and |
· | law enforcement difficulties. |
Forward-looking statements and information are based on our current beliefs as well as assumptions made by, and information currently available to, us concerning anticipated financial conditions and performance, business prospects, strategies, regulatory developments, the ability to attract joint venture partners, future hydrocarbon commodity prices, the ability to secure adequate capital funding, the ability to obtain equipment in a timely manner to carry out development activities, the ability to market products successfully to current and new customers, the effects from increasing competition, the ability to obtain financing on acceptable terms, and the ability to develop reserves and production through development and exploration activities. Although we consider these assumptions to be reasonable based on information currently available to us, they may prove to be incorrect.
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements will eventuate. In light of the significant uncertainties inherent in our forward-looking statements, the inclusion of such information should not be regarded as a representation by us or any other person that our objectives and plans will be achieved. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the heading “Risk Factors” in our 2011 Annual Information Form.
Furthermore, the forward-looking information contained in this MD&A is made as of the date hereof, unless otherwise specified and, except as required by applicable law, we will not update publicly or to revise any of this forward-looking information. The forward-looking information contained in this report is expressly qualified by this cautionary statement.
Management Discussion and Analysis INTEROIL CORPORATION 3 |
OIL AND GAS DISCLOSURES |
We are required to comply with Canadian Securities Administrators��� National Instrument 51-101 Standards for Disclosure of Oil and Gas Activities (“NI 51-101”), which prescribes disclosure of oil and gas reserves and resources. GLJ Petroleum Consultants Ltd., an independent qualified reserve evaluator based in Calgary, Canada, has evaluated our resources data as at December 31, 2011 in accordance with NI 51-101, which evaluation is summarized in our 2011 Annual Information Form available atwww.sedar.com. We do not have any production or reserves, including proved reserves, as defined under NI 51-101 or as per the guidelines set by the United States Securities and Exchange Commission (“SEC”), as at December 31, 2011.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, possible and probable reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We include in this MD&A information that the SEC’s guidelines generally prohibit U.S registrants from including in filings with the SEC.
All calculations converting natural gas to crude oil equivalent have been made using a ratio of six thousand cubic feet of natural gas to one barrel of crude equivalent. Barrels of oil equivalent may be misleading, particularly if used in isolation. A barrel of oil equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
INTRODUCTION |
We are developing a fully integrated energy company operating in Papua New Guinea and the surrounding Southwest Pacific region. Our operations are organized into four major segments:
Segments | Operations | |
Upstream | Exploration and Production – Explores, appraises and develops crude oil and natural gas structures in Papua New Guinea. Currently developing infrastructure for the Elk and Antelope fields which includes condensate stripping and associated facilities, and the gas gathering and associated facilities, in connection with commercializing gas discoveries. This segment also manages our construction business which services the development projects underway in Papua New Guinea. | |
Midstream | Refining – Produces refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea for the domestic market and for export.
Liquefaction – The LNG Project. Developing liquefaction and associated facilities in Papua New Guinea for the export of LNG. | |
Downstream | Wholesale and Retail Distribution– Markets and distributes refined products domestically in Papua New Guinea on a wholesale and retail basis. | |
Corporate | Corporate – Provides support to the other business segments by engaging in business development and improvement activities and providing general and administrative services and management, undertakes financing and treasury activities, and is responsible for government and investor relations. General and administrative and integrated costs are recovered from business segments on an equitable basis. This segment also manages our shipping business which currently operates two vessels transporting petroleum products for our Downstream segment and external customers, both within PNG and for export in the South Pacific region. Our corporate segment results also include consolidation adjustments. |
Management Discussion and Analysis INTEROIL CORPORATION 4 |
BUSINESS STRATEGY |
Our strategy is to develop a vertically integrated energy company in Papua New Guinea and the surrounding region, focusing on niche market opportunities which provide financial rewards for our shareholders, while being environmentally responsible, providing a quality working environment and contributing positively to the communities in which we operate. A significant current element of that strategy is to develop gas liquefaction and condensate stripping facilities in Papua New Guinea and to establish gas and gas condensate reserves.
InterOil plans to achieve this strategy by:
· | Developing our position as a prudent and responsible business operator; |
· | Maximizing the value of our exploration assets; |
· | Monetizing our discovered resources; |
· | Enhancing our existing refining and distribution businesses; and |
· | Positioning for long term success. |
Further details of our business strategy can be found under the heading “Business Strategy” in our 2011 Annual Information Form available atwww.sedar.com.
OPERATIONAL HIGHLIGHTS
Summary of operational highlights
A summary of the key operational matters and events for the year, for each of the segments is as follows:
Upstream
· | The PPL 236 phase 1 exploratory seismic data acquisition program, which included 70 kilometers with six dip lines transecting the Whale, Tuna, Barracuda, Wahoo, Mako and Shark prospects, was completed during the first quarter of 2011. Processing and interpretation of this first phase of seismic data has been completed, and the Wahoo/Mako leads (PPL 236) and the Tuna lead (PPL 236 and PPL 238) have been selected for follow up. Subsequently the Kwalaha seismic data acquisition program was activated consisting of 56 kilometres and seven dip lines. Work commenced on September 16, 2011 and was completed on December 20, 2011. The objective of the survey was to further delineate the Wahoo and Mako prospects and identify potential drilling locations. Processing and interpretation of the data is ongoing. A third phase of seismic data acquisition, which consists of two dip orientated lines totaling 21 kilometres in length over the Tuna prospect, commenced on December 22, 2011. Line preparation is currently in progress. |
· | The PPL 237 phase 3 Triceratops seismic acquisition program, which included four lines for a total of 50 kilometres, was acquired between April and August 2011. This program increased our total seismic data acquisition over the area to 140 kilometers in eleven lines. The objective of the program was to investigate the structure, seismic character, and the aerial closure of the Triceratops field. Following the interpretation of the new seismic data, a review of the field was completed and the conclusion reached that both the Bwata-1 and Triceratops-1 wells lay in the same zone, the same pool and the same field. Subsequently, the field was renamed the Triceratops field. Following the mapping of the seismic there has also been a review and increase in what we believe is the prospective size of the Triceratops field. This potential increase is due to increased size of the closure and the identification of several potential shallow marine reefal carbonate build ups. |
· | The preparation of the Triceratops 2 well site was completed at the end of 2011 and the Triceratops 2 well was spudded on January 15, 2012. The Triceratops 2 well is an appraisal well to test the presence of hydrocarbons and determine whether a potential reefal carbonate reservoir exists in the Triceratops field. |
Management Discussion and Analysis INTEROIL CORPORATION 5 |
· | During 2011, we contracted for airborne magnetic, gravity and gamma ray prospecting over PPL 236, PPL 237 and PPL 238. Five acquisition blocks were acquired for a total of 14,288 line kilometers of airborne data. Data processing over this airborne data is currently undergoing final quality control assessment. |
· | During 2011, the FEED work was carried out on Condensate Stripping Project. The FEED phase generated deliverables to technically and commercially define the project and prepare it for execution (detailed engineering, procurement, construction, fabrication, commissioning, and hand-over to operations) and proposals were solicited from potential Engineering, Procurement and Construction (“EPC”) contractors. We are continuing the planning and preparation efforts for Condensate Stripping Project execution which includes preparing a detailed project execution plan, execution schedule and risk assessment work. At the end of 2011, agreement was reached with Mitsui to extend the target date for FID on the CSP Project until March 31, 2012, which has been extended from the previously disclosed targeted date of December 31, 2011 to be realigned with the targeted FID dates for our LNG Project. |
· | In June 2011, our Board of Directors approved capital expenditures on certain critical steel infrastructure ahead of FID on our LNG Project in order to help preserve the proposed schedule and take advantage of advantageous steel pricing. Total expenditure of up to $100.0 million was authorized for condensate and processed gas line pipe, and other required items with long lead times. |
· | At the end of 2011, we agreed with Petromin that the Investment Agreement we entered into in 2008 was no longer valid or intended to operate and should terminate. The agreement provided for Petromin to take a direct interest in the Elk and Antelope fields and fund 20.5% of the costs of their development, if certain conditions were met. Petromin remains the State’s nominee to acquire this interest under relevant Papua New Guinean’s legislation, once a PDL is granted. We have proposed to Petromin that cash contributions made by Petromin under the Agreement to fund development, amounting to approximately $15.4 million, be held and credited against the State’s obligation to refund its portion of such costs upon grant of the PDL. |
Midstream – Refining
· | Total refinery throughput for the year ended December 31, 2011, was 24,856 barrels per operating day, compared with 24,682 barrels per operating day during 2010. |
· | Capacity utilization of the refinery for 2011, based on 36,500 barrels per day operating capacity, was 54% compared with 53% in 2010. During the years ended December 31, 2011 and 2010, our refinery was shut down for 82 days and 81 days respectively. |
· | The catalytic reformer unit ("CRU"), which allows the refinery to produce reformate for gasoline, remained shut down through the year due to technical operating issues. As a result, we were required to import unleaded gasoline to satisfy PNG’s domestic needs. It is anticipated that the CRU will be re-commissioned and returned to service during 2012, upon the successful conclusion of major maintenance and catalyst regeneration. |
· | During the year, a decommissioning provision of $4.1 million relating to the future retirement obligations associated with the refinery was initially recognized. This decommissioning provision represents the net present value of the estimated costs of future dismantlement, site restoration and abandonment of properties based upon regulations and economic circumstances. This provision balance as at December 31, 2011 was $4.6 million. |
· | In June 2011, OPIC signed agreements agreeing to release all of the sponsor support collateral and requirements for the loan granted to us in 2001 in recognition of our financial and operational maturity. |
· | On May 23, 2011, the BNP Paribas working capital facility agreement was amended to allow a $10.0 million increase in the facility limit. Total facility limit stood at $230.0 million subsequent to its amendment. In November 2011, our Midstream working capital facility with BNP Paribas was increased temporarily by $30.0 million to $260.0 million till January 31, 2012, and reverting back to $230.0 million on that date. Subsequent to the year end, the facility has been extended and further amended in February 2012 with the allowance of a further $10.0 million increase in the facility limit to $240.0 million until January 31, 2013. |
Midstream – Liquefaction
· | On February 2, 2011, we signed a Project Funding and Construction Agreement and Shareholder Agreement with Energy World Corporation Limited (“EWC”) governing the parameters in respect of the development, construction, financing and operation of the planned 3 mtpa land based modular LNG plant in the Gulf Province of Papua New Guinea. The agreements with EWC, as amended, contemplate the negotiation of further definitive agreements and are conditional on reaching FID to proceed with the LNG plant no later than March 31, 2012. |
Management Discussion and Analysis INTEROIL CORPORATION 6 |
· | On April 11, 2011, we and Pac LNG entered into certain conditional framework agreements with FLEX LNG and Samsung Heavy Industries for the proposed construction of a 1.8 mtpa or 2 mtpa fixed-floating liquefied natural gas vessel. The framework agreements provided that the parties were to undertake project specific FEED work and negotiate final binding agreements in time for a FID decision in mid-December 2011. Project specific FEED work was carried out. However, as FID was not reached by mid-December 2011, these framework agreements with FLEX LNG and Samsung lapsed and were not extended. We are continuing to negotiate with FLEX LNG. Under the framework agreement we entered into with FLEX LNG, an equity purchase option was granted to us to acquire common shares in FLEX LNG at an average strike price of 4.5909 Norwegian Kroner. On May 16, 2011, this option was exercised, with our acquisition of 8,938,913 common shares of FLEX LNG at a cost of $7.5 million. |
· | During the year, site-specific engineering for the land based modular LNG and fixed-floating LNG facilities were undertaken along with other pre-investment in the LNG Project to lower bidder risks and to secure our LNG Project timeline and costs. |
· | On August 1, 2011, Rt. Hon Sir Rabbie Namaliu, former Prime Minister and former Petroleum and Energy Minister of Papua New Guinea, joined us to chair our PNG Advisory Board. The PNG Advisory Board is a management group formed to assist us in discussions with government departments in developing the LNG Project. |
· | On August 3, 2011, we signed a Heads of Agreement with Noble Clean Fuels Limited, a wholly owned subsidiary of Noble Group Limited, for the supply of one mtpa of LNG per annum from the LNG Project for a ten year period beginning in 2014. Definitive, binding agreements are currently being negotiated. |
· | The PNG government’s Minister for Petroleum and Energy and the Secretary of his department issued certain press releases and correspondence during 2011 asserting that our development of the LNG Project may not, were it to continue without amendment to its current form, be in compliance with the terms of the LNG Project Agreement signed with the State in December 2009, and would not be approved by the State. We have provided appropriate assurances to the PNG government in relation to the development of this Project and are continuing to work with the PNG government and its relevant departments in relation to our development plans for the Elk and Antelope fields and the LNG Project. Additionally, the constitution of the PNG government became a matter of dispute during 2011 and remains so. National elections are due to take place in mid-2012. |
· | In September 2011, we retained Morgan Stanley & Co.LLC, Macquarie Capital (USA) Inc. and UBS AG as joint financial advisors to assist us with soliciting and evaluating proposals from potential strategic partners. We anticipate that these proposals will relate to obtaining an internationally recognized LNG operating and equity partner for development of the LNG Project’s gas liquefaction and associated facilities in the Gulf Province of Papua New Guinea, and may include a sale of an interest in the Elk and Antelope fields, and in our other exploration tenements in Papua New Guinea. No assurances can be given that we will be able to attract strategic partners on terms acceptable to us, how such an agreement will affect our current LNG Project plans or whether such a partner will be acceptable to the PNG government. |
· | On November 25, 2011, a Heads of Agreement was signed with Gunvor Singapore Pte. Ltd. for the supply of one mtpa of LNG from the LNG Project in Papua New Guinea. Definitive binding agreements are currently being negotiated. |
· | On December 2, 2011, a further Heads of Agreement was signed with ENN Energy Trading Company Ltd of China, for the supply of one to one and one half mtpa of LNG from the LNG Project. The Heads of Agreement, while not binding, provides exclusivity on the LNG volumes, during negotiation of the definitive agreement, and set out the basis upon which the parties intend to negotiate and document terms for the purchase and sale of LNG, for a period of 15 years, commencing in 2015. |
Downstream
· | In 2011, we signed supply agreements with several key contractors and sub-contractors associated with the Exxon Mobil LNG project, Papua New Guinea’s largest resource project to date. In addition, we re-signed all existing major customers in the agricultural, commercial and aviation sectors to further three year term supply agreements. |
· | Year on year, sales volumes for 2011 were 678.0 million liters and were up by 51.5 million liters, or 8.2%, on the 2010 volumes of 626.5 million liters. |
Management Discussion and Analysis INTEROIL CORPORATION 7 |
· | Our retail business accounted for approximately 13% of our total downstream sales in 2011. Investments were made in 2010 and 2011 in new electronic systems for both pumps and the forecourt control units to support the further development of this business. |
· | On December 8, 2011, the ICCC advised that margins for wholesale will increase in line with the ICCC mandated formula for a five year period. A CPI increase of 7% is reflected in these revised margins. These increases apply to unleaded gasoline, diesel and kerosene and are effective for the fiscal year ending December 31, 2012. |
· | Subsequent to year end in February 2012, Westpac working capital facility was increased by $4.7 million (PGK 10.0 million) bringing the total Downstream working capital facility to $65.3 million (PGK 140.0 million). In addition, a secured loan of $15.0 million was provided by Westpac which is repayable in equal installments over 3.5 years with an interest rate of LIBOR + 4.4% per annum. |
Corporate
· | The shipping business, which operates two vessels transporting petroleum products for us and external customers both within PNG and for export in the South Pacific region, was transferred from our Downstream business segment to Corporate during the year. |
Management Discussion and Analysis INTEROIL CORPORATION 8 |
SELECTED ANNUAL FINANCIAL INFORMATION AND HIGHLIGHTS |
Consolidated Results for the years ended December 31, 2011, 2010 and 2009
Consolidated – Operating results | Year ended December 31, | |||||||||||
($ thousands, except per share data) | 2011 | 2010 | 2009(4) | |||||||||
Sales and operating revenues | 1,106,534 | 802,374 | 688,479 | |||||||||
Interest revenue | 1,356 | 151 | 351 | |||||||||
Other non-allocated revenue | 11,058 | 4,470 | 4,228 | |||||||||
Total revenue | 1,118,948 | 806,995 | 693,058 | |||||||||
Cost of sales and operating expenses | (1,020,932 | ) | (701,557 | ) | (601,983 | ) | ||||||
Office and administration and other expenses | (52,793 | ) | (52,650 | ) | (44,894 | ) | ||||||
Derivative gain/(loss) | 2,006 | (1,065 | ) | 1,009 | ||||||||
Exploration costs | (18,435 | ) | (16,982 | ) | (209 | ) | ||||||
Gain on sale of oil and gas properties assets | - | 2,141 | 7,364 | |||||||||
Loss on extinguishment of IPI liability | - | (30,569 | ) | (31,710 | ) | |||||||
Litigation settlement expense | - | (12,000 | ) | - | ||||||||
Loss on Flex LNG Investment | (3,420 | ) | - | - | ||||||||
Foreign exchange gain/(loss) | 25,019 | (10,777 | ) | (3,305 | ) | |||||||
EBITDA(1) | 50,393 | (16,464 | ) | 19,330 | ||||||||
Depreciation and amortization | (20,137 | ) | (14,275 | ) | (14,322 | ) | ||||||
Interest expense | (13,333 | ) | (7,364 | ) | (9,993 | ) | ||||||
Profit/(loss) before income taxes | 16,923 | (38,103 | ) | (4,985 | ) | |||||||
Income tax benefit/(expense) | 736 | (6,410 | ) | 11,076 | ||||||||
Net profit/(loss) | 17,659 | (44,513 | ) | 6,091 | ||||||||
Net profit/(loss) per share (dollars) (basic) | 0.37 | (1.00 | ) | 0.15 | ||||||||
Net profit/(loss) per share (dollars) (diluted) | 0.36 | (1.00 | ) | 0.15 | ||||||||
Total assets | 1,088,355 | 975,743 | 631,754 | |||||||||
Total liabilities | 328,464 | 272,841 | 189,764 | |||||||||
Total long-term liabilities | 128,072 | 130,323 | 96,225 | |||||||||
Gross margin(2) | 85,602 | 100,817 | 86,496 | |||||||||
Cash flows generated from/(used in) operating activities(3) | 62,670 | (13,561 | ) | 44,500 |
Notes:
(1) | EBITDA, is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
(2) | Gross margin is a non-GAAP measure and is “sales and operating revenues” less ”cost of sales and operating expenses” and is reconciled to IFRS in the section to this document entitled ”Non-GAAP Measures and Reconciliation”. |
(3) | Refer to “Liquidity and Capital Resources – Summary of Cash Flows” for detailed cash flow analysis. |
(4) | The 2009 selected financial information was prepared in accordance with the Company’s former GAAP, and has not been restated in accordance with IFRS. |
Management Discussion and Analysis INTEROIL CORPORATION 9 |
Analysis of Financial Condition Comparing Years Ended December 31, 2011, 2010 and 2009
During the year ended December 31, 2011, our debt-to-capital ratio (being debt/[shareholders’ equity + debt]) was 12% (13% as at December 31, 2010 and 11% as at December 31, 2009), well below our targeted maximum gearing level of 50%. Gearing targets are based on a number of factors including operating cash flows, future cash needs for development, capital market conditions, economic conditions, and are assessed regularly.
Our current ratio (being current assets/current liabilities), which measures our ability to meet short term obligations, was 2.1 times as at December 31, 2011 (3.2 times as at December 31, 2010 and 2.2 times as at December 31, 2009). The quick ratio (or acid test ratio, (being [current assets less inventories]/current liabilities)) which is a more conservative measure of our ability to meet short term obligations, was 1.3 times as at December 31, 2011 (2.3 times as at December 31, 2010 and 1.5 times as at December 31, 2009). These ratios satisfy our internal targets to be above 1.5 times for the current ratio and 1.0 times for the quick ratio.
As at December 31, 2011, our total assets amounted to $1,088.4 million, compared with $975.7 million as at December 31, 2010 and $631.8 million as at December 31, 2009. The increase of $112.7 million or 11.5% from December 31, 2010 was primarily due to increases in the value of our oil and gas properties of $107.6 million associated with the appraisal and development of the Elk and Antelope fields, preparation for drilling the Triceratops 2 well, and continued development of the LNG Project; an increase in inventory balances and trade receivable balances of $43.9 million and $87.2 million respectively due to higher working capital needs on higher average crude prices during the current period; a net $20.8 million increase in plant and equipment (after depreciation) from capitalization of refinery asset retirement obligations, tank upgrades, camp and office building works, and new business system implementation costs; $7.5 million increase in deferred tax benefits mainly due to the temporary difference arising on foreign exchange translation of non-monetary assets of the refinery operation; and $3.7 million for our investment in shares in FLEX LNG. These increases were offset by net decreases in our cash, cash equivalents, cash restricted, and short term treasury bills of $160.9 million, due primarily to expenditure on development of our oil and gas properties. The increase in total assets of $344.0 million or 54.4% from December 31, 2009 to December 31, 2010 was due primarily to a $187.1 million increase in cash and cash equivalents following the concurrent common share and convertible notes offerings, increases in our oil and gas properties of $82.8 million associated with the appraisal and development of the Elk and Antelope fields and furthering of the Condensate Stripping Project and LNG Project, and an increase in inventory balances of $57.0 million at our refinery due to the timing of shipments.
As at December 31, 2011, our total liabilities amounted to $328.5 million, compared with $272.8 million at December 31, 2010 and $189.8 million as at December 31, 2009. The increase of $55.7 million or 20.4% from December 31, 2010 was primarily due to an increase in accounts payable and accrued liabilities of $84.7 million, offset in part by a reduction of $34.8 million in the working capital facility which is mainly a function of timing of crude purchases for the refining operation. The increase in liability of $83.0 million or 43.7% as at December 31, 2010 from December 31, 2009 was primarily due to the recognition of a $52.4 million liability relating to the fair value of the debt component of the unsecured 2.75% convertible notes issuance in November 2010 and an increase in the working capital facility balance of $26.6 million.
Analysis of Consolidated Financial Results Comparing Years and Quarters Ended December 31, 2011, 2010 and 2009
Annual Comparative
Net profit for the year ended December 31, 2011 was $17.7 million compared with a net loss of $44.5 million for the same period in 2010, an improvement of $62.2 million. The operating segments of Corporate, Midstream Refining and Downstream collectively returned a net profit for the year of $82.3 million. The development segments of Upstream and Midstream Liquefaction yielded a net loss of $64.6 million.
The main items contributing towards the loss in 2010 were unusual, one time charges including a loss on extinguishment of IPI liability of $30.6 million and a $12.0 million expense relating to settlement of certain long-standing litigation.
Management Discussion and Analysis INTEROIL CORPORATION 10 |
Total revenues for the year ended December 31, 2011 were $1,118.9 million compared with $807.0 million and $693.1 million respectively for the same periods in 2010 and 2009. This increase in the year ended 2011 compared to the same period in 2010 was due to the higher crude price environment in the 2011 year and an increase in domestic volumes of product sold for higher margin products. The total volume of all products sold by us was 7.5 million barrels for fiscal year 2011, compared with 7.2 million barrels in 2010 and 6.5 million barrels in 2009.
EBITDA for the year ended December 31, 2011 was $50.4 million, an increase of $66.9 million over negative EBITDA of $16.5 million for the same period in 2010, mainly due to the unusual, one time charges in 2011 as detailed above. The current year also had an improvement in our net foreign exchange gain/loss for the year of $35.8 million compared to the prior period as a result of rising Papua New Guinea Kina (“PGK”) against USD.
The Upstream segment realized a net loss of $49.1 million in 2011 (2010 – loss of $78.6 million, 2009 – loss of $39.5 million). The reduction in the loss in 2011 by $29.4 million from 2010 was mainly due to one-time events in the prior year of $30.6 million loss on extinguishment of IPI liability and $2.1 million gain on sale of oil and gas properties. During 2011, there has been an increase of $11.5 million on intercompany interest charges due to higher loan balances from the parent entity (Corporate segment) to fund the exploration activities. This increase has been offset by a $8.6 million reduction in office and administration expenses as more expenses have been capitalized (mainly relating to rig expenditure associated with mud corrosion caused during the drilling of Antelope 2 well, and expenditure associated with rig standby on Triceratops 2 well drilling due to delays in finalization of the location of the well and weather associated delays), and a $6.5 million increase in other revenue driven by higher recovery of construction and related equipments on their better utilization during the period on LNG Project related civil works and related infrastructure development. The increase in the loss in 2010 by $39.1 million from 2009 was mainly due to a $16.8 million increase in exploration costs relating to the Triceratops field and Wolverine seismic, $9.2 million higher intercompany interest charges, and a $5.2 million reduction in the gain on sale of exploration assets in 2010 compared to 2009 as the prior year included conveyance accounting on the IPI agreement for conversion rights waived by certain IPI investors.
The Midstream Refining segment generated a net profit of $46.7 million in 2011 (2010 - $33.5 million, 2009 - $41.8 million) mainly on account of a $34.0 million increase in foreign exchange gains as a result of rising PGK against USD, a $7.5 million improvement to income tax expense arising primarily from the temporary differences due to translation of the non-monetary assets held by the Refinery using period end rates, and a $3.6 million increase in derivative gains. These increases have been partly offset by lower gross margins (a decrease of $27.1 million from 2010) due primarily to lower crack spreads, and a $3.1 million increase in interest expense charged on higher loan balances from the parent entity. The net profit in 2010 decreased from 2009 mainly on account of the initial recognition of $14.3 million of deferred tax assets in 2010.
The Midstream Liquefaction segment had a net loss of $15.5 million during the 2011 year (2010 – loss of $8.4 million, 2009 – loss of $8.4 million) resulting from higher management expenses and share compensation costs related to the LNG Project development which are not capitalized. As the LNG Project Agreement was signed by the Government of Papua New Guinea in December 2009, all direct project related costs since that date have been capitalized to the project rather than expensed.
The Downstream segment generated a net profit of $11.6 million in 2011 (2010 – profit of $6.7 million, 2009 – profit of $8.5 million). The increased profit was mainly due to a $5.6 million improvement in gross margins due to an increase in domestic volumes resulting from various development projects being undertaken in Papua New Guinea, the positive impact from the revised pricing formula that came into effect in late 2010 following the ICCC’s review of wholesale, distribution and retail margins set by the PNG State for the petroleum industry, and the impact of the increasing price environment during the period leading to higher margins on inventories sold. This improvement in gross margins has been partly offset by a $1.2 million increase in depreciation and amortization on capital purchases related primarily to office refurbishment and upgrade projects across various terminals and depots. The decreased profit in 2010 compared to 2009 was mainly due to a $3.0 million increase in office and administration expenses, a $2.0 million increase in foreign exchange loss and a $1.7 million increase in income tax expense offset in part by a $4.6 million improvement in gross margin.
The Corporate segment generated a net profit of $21.9 million (2010 – profit of $3.3 million, 2009 – loss of $4.3 million). The 2010 results included a $12.0 million settlement expense to finalize certain long-standing litigation, and a $14.2 million increase in interest charges to other business segments on increased loan balances. These expenses have been partly offset by a $4.5 million increase in interest expense due to the 2.75% convertible notes issued on November 10, 2010 and a $3.4 million impairment loss on our investment in shares in Flex LNG held by us as part of the framework agreements entered into with FLEX LNG and Samsung Heavy Industries in April 2011.
Management Discussion and Analysis INTEROIL CORPORATION 11 |
Quarterly Comparative
The net profit for the quarter ended December 31, 2011 was $13.2 million compared with a loss of $34.8 million for the same quarter of 2010, an improvement of $48.0 million. This movement was mainly due to a $21.8 million loss on extinguishment of IPI liability in the prior year quarter in relation to a 1.0% IPI interest buyback, an $11.8 million reduction in expensed exploration costs on lower seismic activity, a $10.5 million increase in foreign exchange gains, and an $18.7 million improvement in income tax expense primarily from the impact of foreign exchange movements impacting temporary differences on translation of the nonmonetary assets of the refinery operation using period end rates. These gains have been offset in part by an $18.3 million reduction in gross margin for the quarter due primarily to decreased export product crack spreads and the impact of both the CRU and Crude Distillation Unit ("CDU") being shut down.
The operating segments of Corporate, Midstream Refining and Downstream collectively derived a net profit for the fourth quarter of $27.2 million, while the development segments of Upstream and Midstream Liquefaction had a net loss of $14.0 million, for an aggregate net profit of $13.2 million.
Total revenues increased by $95.2 million from $194.4 million in the quarter ended December 31, 2010 to $289.6 million in the quarter ended December 31, 2011 primarily due to higher volumes and prices during the quarter. The total volume of all products sold by us was 1.9 million barrels for quarter ended December 2011, compared with 1.6 million barrels in the same quarter of 2010.
Variance Analysis
A complete discussion of each of our business segments’ results can be found under the section ”Year and Quarter in Review”. The following analysis outlines the key variances, the net of which are the primary explanations for the changes in the consolidated results between the years and quarters ended December 31, 2011 and 2010.
Yearly Variance ($ millions) | Quarterly Variance ($ millions) | ||||||||
$ | 62.2 | $ | 48.0 | Net profit/(loss) variance for the comparative periods primarily due to: | |||||
$ | (15.2 | ) | $ | (18.3 | ) | Reduction in gross margin for the year driven by increase in crude costs, decreases in export product crack spreads and reduced demand for export products, offset by volume increases and improved margins in the domestic market. | |||
$ | 6.6 | $ | 1.5 | Increase in other non-allocated revenue due to better utilization of construction and related equipment on civil works and related infrastructure development associated with the LNG Project. | |||||
$ | (0.1 | ) | $ | 4.9 | Decrease in office and administration and other expenses in the current quarter on higher capitalization of expenses (mainly relating to rig expenditure associated with corrosion caused by drilling mud, and expenditure associated with rig standby on the Triceratops 2 well drilling due to delays in finalization of the location of the well and weather associated delays). | ||||
$ | 3.1 | $ | 1.4 | Movement in gains from derivative contracts that were not accounted for as hedge accounted contracts. |
Management Discussion and Analysis INTEROIL CORPORATION 12 |
$ | (1.5 | ) | $ | 11.8 | Higher exploration costs for seismic activity on our licenses PPL 236, 237 and 238 during the year. The majority of the seismic costs were incurred during the first three quarters of the current year and the fourth quarter of 2010. These seismic costs were expensed as incurred. | ||||
$ | 30.6 | $ | 21.8 | Loss on extinguishment of IPI liability in 2010 in relation to the interest buyback of 1.4%, 1.0% of which was purchased in the fourth quarter. There have been no such buybacks during 2011. | |||||
$ | 12.0 | - | Litigation settlement expense in the third quarter of 2010 on settlement of the Todd Peters et al litigation for which we issued 199,677 common shares to the plaintiffs valued at $12.0 million. | ||||||
$ | (3.4 | ) | $ | (1.6 | ) | Loss recognized on our investment in shares in FLEX LNG held by us as part of the framework agreements entered into with FLEX LNG and Samsung Heavy Industries in April 2011. | |||
$ | 35.8 | $ | 10.5 | The PGK strengthened against the USD from 0.3785 at the start of the year to 0.4665 as at December 31, 2011. We are currently holding more PGK cash balances in PNG to partly mitigate the risk of a rising PGK which would affect exploration and development costs. | |||||
$ | (5.9 | ) | $ | (2.0 | ) | Increase in depreciation expense mainly due to the depreciation of construction machinery which was acquired over the last year, and the depreciation of the new ERP system. | |||
$ | (6.0) | $ | (1.0 | ) | Higher interest expense for the quarter and year primarily due to higher utilization of our Midstream and Downstream working capital facilities, and interest on the 2.75% convertible senior notes issued on November 10, 2010. | ||||
$ | 7.1 | $ | 18.7 | Decrease in income tax expense for the year primarily from the impact of foreign exchange movements impacting temporary differences on translation of the nonmonetary assets of the refinery operation using period end rates. |
Analysis of Consolidated Cash Flows Comparing Years and Quarters Ended December 31, 2011 and 2010
As at December 31, 2011, we had cash, cash equivalents, and cash restricted of $108.1 million (December 2010 – $280.9 million), of which $39.3 million (December 2010 - $47.3 million) was restricted. In addition, we also had $11.8 million equivalent of PGK in short term treasury bills issued by the Bank of Papua New Guinea (December 2010 – nil). Of the total cash restricted of $39.3 million, $33.0 million (December 2010 - $40.7 million) was restricted pursuant to the BNP Paribas working capital facility utilization requirements, $5.9 million (December 2010 – $6.3 million) was restricted as a cash deposit on the OPIC secured loan relating to our half yearly instalment of $4.5 million and the related interest that will be payable with the next instalment on June 30, 2012, and the balance was made up of a cash deposit on office premises together with term deposits on our PPLs.
Our cash inflows from operations for the year ended December 31, 2011 were $62.7 million compared with outflows of $13.6 million for the year ended December 31, 2010, a net increase in cash inflows of $76.3 million. This increase in cash inflows is mainly due to a $26.2 million change in cash generated by operations prior to changes in operating working capital, related to net profits generated from operations less any non-cash expenses for the year. There was also a $50.1 million decrease in working capital associated with trade receivables, inventories and accounts payables.
Cash outflows for investing activities for the year ended December 31, 2011 were $204.2 million compared with $111.2 million for the year ended December 31, 2010. These outflows mainly relate to the net cash expenditure on exploration, appraisal and development activities (net of IPI cash calls) of $134.1 million, expenditure on plant and equipment of $42.1 million, acquisition of FLEX LNG shares net of transaction costs of $7.5 million, investments in short term PGK treasury bills of $11.8 million, a $10.0 million increase in trade receivables and a $6.7 million decrease in working capital requirements of development segments relating to the timing of receipts and payments. These outflows were partly offset by a decrease of $8.0 million in the restricted cash balance under the BNP Paribas working capital facility.
Management Discussion and Analysis INTEROIL CORPORATION 13 |
Cash outflows from financing activities for the year ended December 31, 2011 amounted to $27.2 million, compared with $311.8 million inflows for the year ended December 31, 2010. These cash outflows include two repayments of the OPIC secured loan of $9.0 million and $34.8 million repayments of the working capital facility. These outflows have been partly offset by receipts of cash contributions from Mitsui for the Condensate Stripping Project of $9.9 million, receipts from PNG LNG cash call of $2.2 million, and receipts of cash from the exercise of stock options of $4.5 million. The cash inflows/outflows associated with the working capital facility drawdown/repayments are due to the timing of cash flows and the use of working capital. The inflows from financing activities in the prior year relate primarily to the receipt of cash from the concurrent common shares and 2.75% convertible notes offerings in November 2010.
Summary of Consolidated Quarterly Financial Results for Past Eight Quarters
The following is a table containing the consolidated results for the eight quarters ended December 31, 2011 by business segment, and on a consolidated basis. Our IFRS transition date was January 1, 2010 and as such, the 2010 comparative information in the table below has been restated in accordance with IFRS.
2011 | 2010 | |||||||||||||||||||||||||||||||
Quarters ended ($ thousands except per share data) | Dec-31 | Sep-30 | Jun-30 | Mar-31 | Dec-31 | Sep-30 | Jun-30 | Mar-31 | ||||||||||||||||||||||||
Upstream | 1,891 | 2,645 | 4,638 | 668 | 245 | 714 | 1,349 | 998 | ||||||||||||||||||||||||
Midstream – Refining | 237,640 | 231,455 | 262,111 | 217,743 | 158,092 | 173,379 | 194,016 | 152,093 | ||||||||||||||||||||||||
Midstream – Liquefaction | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Downstream | 209,678 | 186,304 | 191,431 | 157,709 | 143,364 | 133,508 | 119,300 | 109,687 | ||||||||||||||||||||||||
Corporate | 21,831 | 25,078 | 26,548 | 18,659 | 15,213 | 18,295 | 11,321 | 12,093 | ||||||||||||||||||||||||
Consolidation entries | (181,428 | ) | (163,584 | ) | (180,945 | ) | (151,125 | ) | (122,545 | ) | (117,437 | ) | (100,637 | ) | (96,053 | ) | ||||||||||||||||
Total revenues | 289,612 | 281,898 | 303,783 | 243,654 | 194,369 | 208,459 | 225,349 | 178,818 | ||||||||||||||||||||||||
Upstream | 665 | (6,169 | ) | 593 | (10,957 | ) | (41,681 | ) | (11,753 | ) | (3,498 | ) | (1,964 | ) | ||||||||||||||||||
Midstream – Refining | 2,604 | 3,461 | 27,967 | 26,632 | 13,780 | 15,785 | 16,962 | 4,402 | ||||||||||||||||||||||||
Midstream – Liquefaction | (4,123 | ) | (3,602 | ) | (4,035 | ) | (2,375 | ) | (1,959 | ) | (4,588 | ) | (3 | ) | (563 | ) | ||||||||||||||||
Downstream | 6,808 | 3,570 | 5,777 | 8,744 | 4,709 | 1,674 | 7,060 | 4,492 | ||||||||||||||||||||||||
Corporate | 10,134 | 1,548 | 13,940 | 5,223 | 4,566 | (4,510 | ) | 1,751 | 4,402 | |||||||||||||||||||||||
Consolidation entries | (11,280 | ) | (10,263 | ) | (5,270 | ) | (9,200 | ) | (7,004 | ) | (5,229 | ) | (7,384 | ) | (5,911 | ) | ||||||||||||||||
EBITDA(1) | 4,808 | (11,455 | ) | 38,972 | 18,067 | (27,589 | ) | (8,621 | ) | 14,888 | 4,858 | |||||||||||||||||||||
Upstream | (9,402 | ) | (15,080 | ) | (6,703 | ) | (17,949 | ) | (47,845 | ) | (16,585 | ) | (7,943 | ) | (6,182 | ) | ||||||||||||||||
Midstream – Refining | 15,684 | (1,201 | ) | 17,314 | 14,894 | 9,504 | 11,998 | 12,056 | (74 | ) | ||||||||||||||||||||||
Midstream – Liquefaction | (4,574 | ) | (3,980 | ) | (4,309 | ) | (2,604 | ) | (2,114 | ) | (4,970 | ) | (360 | ) | (911 | ) | ||||||||||||||||
Downstream | 3,621 | 1,146 | 2,306 | 4,491 | 2,643 | (325 | ) | 3,719 | 671 | |||||||||||||||||||||||
Corporate | 7,616 | (473 | ) | 11,275 | 3,463 | 3,381 | (5,398 | ) | 1,796 | 3,544 | ||||||||||||||||||||||
Consolidation entries | 252 | (190 | ) | 3,657 | (1,596 | ) | (401 | ) | 908 | (1,435 | ) | (190 | ) | |||||||||||||||||||
Net profit/(loss) | 13,197 | (19,778 | ) | 23,540 | 699 | (34,832 | ) | (14,372 | ) | 7,833 | (3,142 | ) | ||||||||||||||||||||
Net profit/(loss) per share (dollars) | ||||||||||||||||||||||||||||||||
Per Share – Basic | 0.27 | (0.41 | ) | 0.49 | 0.01 | (0.76 | ) | (0.33 | ) | 0.18 | (0.07 | ) | ||||||||||||||||||||
Per Share – Diluted | 0.27 | (0.41 | ) | 0.48 | 0.01 | (0.76 | ) | (0.33 | ) | 0.17 | (0.07 | ) |
(1) | EBITDA is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
Management Discussion and Analysis INTEROIL CORPORATION 14 |
YEAR AND QUARTER IN REVIEW
The following section provides a review of the year and quarter ended December 31, 2011 for each of our business segments.
UPSTREAM – YEAR AND QUARTER IN REVIEW
Upstream – Operating results | Year ended December 31, | |||||||
($ thousands) | 2011 | 2010 | ||||||
Other non-allocated revenue | 9,841 | 3,305 | ||||||
Total revenue | 9,841 | 3,305 | ||||||
Office and administration and other expenses | (5,122 | ) | (13,746 | ) | ||||
Exploration costs | (18,435 | ) | (16,982 | ) | ||||
Gain on sale of oil and gas properties | - | 2,141 | ||||||
Loss on extinguishment of IPI liability | - | (30,569 | ) | |||||
Foreign exchange loss | (2,153 | ) | (3,044 | ) | ||||
EBITDA(1) | (15,869 | ) | (58,895 | ) | ||||
Depreciation and amortization | (3,255 | ) | (1,132 | ) | ||||
Interest expense | (30,013 | ) | (18,528 | ) | ||||
Loss before income taxes | (49,137 | ) | (78,555 | ) | ||||
Income tax expense | - | - | ||||||
Net loss | (49,137 | ) | (78,555 | ) |
(1) | EBITDA is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
Analysis of Upstream Financial Results Comparing Year and Quarter Ended December 31, 2011 and 2010
The following analysis outlines the key movements, the net of which primarily explains the difference in the results between the years and quarters ended December 31, 2011 and 2010.
Yearly Variance ($ millions) | Quarterly Variance ($ millions) | |||||||||||
$ | 29.4 | $ | 38.4 | Net profit/(loss) variance for the comparative periods primarily due to: | ||||||||
Ø | $ | 6.5 | $ | 1.6 | Increase in other non-allocated revenue driven by higher recovery of construction and related equipment charges on their better utilization during the period on LNG Project related civil works and related infrastructure development. Recoveries in relation to our percentage interest of the development projects are offset against the relevant expenses, while the recoveries of the portion relating to external party interests in the development projects are classified under other non-allocated revenue. | |||||||
Ø | $ | (1.5 | ) | $ | 11.8 | Higher exploration costs for seismic activity during the year on PPL 236. The majority of the seismic costs were incurred during the first three quarters of 2011 and the fourth quarter of 2010. These seismic costs were expensed as incurred under the successful efforts method of accounting. | ||||||
Ø | $ | (2.1 | ) | - | Gain recognized on the sale of our 15% interest in PPL 244 in the year ended December 31, 2010. |
Management Discussion and Analysis INTEROIL CORPORATION 15 |
Ø | $ | 30.6 | $ | 21.8 | Loss on extinguishment of IPI liability in 2010 in relation to the buyback of IPI interests amounting to 1.4%, 1.0% of which was purchased in the fourth quarter of 2010. There have been no such buybacks during 2011. | |||||||
Ø | $ | 8.6 | $ | 7.0 | Reduction in office and administration expenses as more expenses have been capitalized (mainly relating to rig expenditure associated with corrosion caused by drilling mud, and expenditure associated with rig standby on the Triceratops 2 well drilling due to delays in finalization of the location of the well and weather associated delays). | |||||||
Ø | $ | (11.5 | ) | $ | (3.2 | ) | Higher interest expense due to an increase in inter-company loan balances provided to fund exploration and development activities. |
MIDSTREAM - REFINING – YEAR AND QUARTER IN REVIEW
Midstream Refining – Operating results | Year ended December 31, | |||||||
($ thousands) | 2011 | 2010 | ||||||
External sales | 362,606 | 298,071 | ||||||
Inter-segment revenue - Sales | 576,672 | 376,066 | ||||||
Inter-segment revenue - Recharges | 8,841 | 3,278 | ||||||
Interest and other revenue | 831 | 166 | ||||||
Total segment revenue | 948,950 | 677,581 | ||||||
Cost of sales and operating expenses | (897,825 | ) | (605,603 | ) | ||||
Office and administration and other expenses | (18,939 | ) | (11,940 | ) | ||||
Derivative gain/(loss) | 2,018 | (1,592 | ) | |||||
Foreign exchange gain/(loss) | 26,458 | (7,518 | ) | |||||
EBITDA(1) | 60,662 | 50,928 | ||||||
Depreciation and amortization | (11,254 | ) | (10,355 | ) | ||||
Interest expense | (9,664 | ) | (6,585 | ) | ||||
Profit before income taxes | 39,744 | 33,988 | ||||||
Income tax benefit/(expense) | 6,946 | (505 | ) | |||||
Net profit | 46,690 | 33,483 | ||||||
Gross Margin(2) | 41,453 | 68,534 |
(1) | EBITDA is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
(2) | Gross margin is a non-GAAP measure and is “external sales” and “inter-segment revenue – sales” less “cost of sales and operating expenses” and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
Management Discussion and Analysis INTEROIL CORPORATION 16 |
Midstream - Refining Operating Review
Quarter ended December 31, | Year ended December 31, | |||||||||||||||
Key Refining Metrics | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Throughput (barrels per day)(1) | 24,644 | 21,550 | 24,856 | 24,682 | ||||||||||||
Capacity utilization (based on 36,500 barrels per day operating capacity) | 50 | % | 34 | % | 54 | % | 53 | % | ||||||||
Cost of production per barrel(2) | $ | 5.18 | $ | 3.66 | $ | 4.58 | $ | 2.84 | ||||||||
Working capital financing cost per barrel of production(2) | $ | 0.76 | $ | 0.58 | $ | 0.73 | $ | 0.47 | ||||||||
Distillates as percentage of production | 57.1 | % | 58.70 | % | 57.5 | % | 51.00 | % |
(1) | Throughput per day has been calculated excluding shut down days. During 2011 and 2010, the refinery was shut down for 82 days and 81 days, respectively. |
(2) | Our cost of production per barrel and working capital financing cost per barrel have been calculated based on a notional throughput. Our actual throughput has been adjusted to include the throughput that would have been necessary to produce the equivalent amount of finished product that we imported during the year. The increase in the cost of production per barrel for the current periods is mainly due to the depreciation of the USD against the PGK and AUD, the currencies in which we incur our operating expenditures, and a general inflationary increase, higher personnel costs and system and IT upgrades performed during the current periods. |
During the second half of 2011, the PNG Customs Service commenced an audit of our petroleum product imports into Papua New Guinea for the years 2007 to 2010. We received a letter in November 2011 from the then Commissioner of Customs setting out certain findings from the audit. This letter included comments alleging that payment of import goods and services taxes (“GST”) was required and had not been made on imports of certain refined products. As well as requiring payment of GST, the letter noted that administrative penalties were able to be levied by Customs in the range of 50% to 200% of the assessed amounts as per the PNG Customs Act. We have since met with the Customs Service and provided it with supporting documentation to demonstrate that the GST amounts claimed in their letter have all been paid. We have currently made a provision based on our best estimate in relation to this matter and are working closely with the authority to provide all requested information in order to finalize the audit.
Analysis of Midstream - Refining Financial Results Comparing the Year and Quarter Ended December 31, 2011 and 2010
The following analysis outlines the key changes, the net of which primarily explains the variance in the results between the years and quarters ended December 31, 2011 and 2010.
Yearly Variance ($ millions) | Quarterly Variance ($ millions) | |||||||||||
$ | 13.2 | $ | 6.2 | Net profit/(loss) variance for the comparative periods primarily due to: | ||||||||
Ø | $ | (27.1 | ) | $ | (19.9 | ) | Decrease in gross margin for the year mainly due to the following contributing factors: - Decreases in export product crack spreads due to increase in crude costs and reduced demand for export products + Increases in crude and product flat pricing over the year contributing to increased inventory gains for all products + Better crude mix resulting in increased distillate yield percentage | |||||
Ø | $ | 34.0 | $ | 8.0 | Increase in foreign exchange gain due to the strengthening of the PGK against the USD. The PGK strengthened against the USD from 0.3785 at the start of the year to 0.4665 as at December 31, 2011. As part of our foreign exchange risk management strategy, we have begun holding more PGK cash balances in PNG to partly mitigate the risk of a rising PGK affecting our operations. |
Management Discussion and Analysis INTEROIL CORPORATION 17 |
Ø | $ | (1.4 | ) | $ | (0.8 | ) | Increase in office and administration costs net of recharge revenue for the year was driven by higher salaries, wages and share compensation expenses, which were to a large extent impacted by the strengthening of the PGK and Australian Dollar (“AUD”) against the USD during the period. | |||||
Ø | $ | 3.6 | $ | 1.3 | Movement in gains from derivative contracts that were not accounted for as hedge accounted contracts. | |||||||
Ø | $ | (3.1 | ) | $ | (1.8 | ) | Increase in interest expense on higher utilization of the working capital facilities. | |||||
Ø | $ | 7.5 | $ | 19.3 | Decrease in income tax expense in 2011 primarily from the impact of foreign exchange movements impacting temporary differences on translation of the nonmonetary assets of the refinery operation using period end rates, offset by income tax expense on profits generated by the operations. |
MIDSTREAM - LIQUEFACTION – YEAR AND QUARTER IN REVIEW
Year ended December 31, | ||||||||
Midstream Liquefaction – Operating results ($ thousands) | 2011 | 2010 | ||||||
Interest and other revenue | - | 1 | ||||||
Total segment revenue | - | 1 | ||||||
Office and administration and other expenses | (14,121 | ) | (7,023 | ) | ||||
Foreign exchange loss | (13 | ) | (90 | ) | ||||
EBITDA(1) | (14,134 | ) | (7,112 | ) | ||||
Depreciation and amortization | (26 | ) | (25 | ) | ||||
Interest expense | (1,308 | ) | (1,253 | ) | ||||
Loss before income taxes | (15,468 | ) | (8,390 | ) | ||||
Income tax benefit | - | 36 | ||||||
Net loss | (15,468 | ) | (8,354 | ) |
(1)EBITDA is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”.
Analysis of Midstream - Liquefaction Financial Results Comparing the Year and Quarter Ended December 31, 2011 and 2010
This segment’s results include the proportionate consolidation of our interest in the joint venture development of the proposed midstream facilities of the LNG Project. The development of these facilities is being progressed in joint venture with Pac LNG through PNG LNG. We currently have an economic interest of 84.582% in this Joint Venture Company. This interest was reduced from 86.66% in December 2011 following the receipt of cash calls from Pac LNG.
All costs incurred in connection with the LNG Project, subsequent to the execution of the shareholders’ agreement governing the development of the midstream facilities of the LNG Project on July 31, 2007, and through the pre-acquisition and feasibility stage have been expensed as incurred, unless they were directly identified as property, plant and equipment. Since the execution of the LNG Project Agreement with the State in December 2009, all project-related direct costs have been capitalized, other than overheads and other costs that are incurred in the normal course of running the business, which are expensed.
The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the years and quarters ended December 31, 2011 and 2010.
Management Discussion and Analysis INTEROIL CORPORATION 18 |
Yearly Variance ($ millions) | Quarterly Variance ($ millions) | |||||||||||
$ | (7.1 | ) | $ | (2.5 | ) | Net profit/(loss) variance for the comparative periods primarily due to: | ||||||
Ø | $ | (7.7 | ) | $ | (3.1 | ) | Increase in office, administration and other expenses for the year due to higher management expenses and share compensation costs related to the midstream facilities of the LNG Project development which are not capitalized. The increases are the result of increased activities undertaken to negotiate long term LNG offtake agreements, pre-feed work being undertaken for the LNG Project’s proposed land based liquefaction and fixed-floating liquefaction facilities, and also further the discussions with the State to achieve approvals. | |||||
Ø | $ | 0.6 | $ | 0.6 | Gain on proportionate consolidation of PNG LNG following a reduction in ownership from 86.66% to 84.582% in December 2011. |
DOWNSTREAM – YEAR AND QUARTER IN REVIEW
Downstream – Operating results | Year ended December 31, | |||||||
($ thousands) | 2011 | 2010 | ||||||
External sales | 743,663 | 504,303 | ||||||
Inter-segment revenue - Sales | 197 | 483 | ||||||
Interest and other revenue | 1,263 | 1,072 | ||||||
Total segment revenue | 745,123 | 505,858 | ||||||
Cost of sales and operating expenses | (704,213 | ) | (470,772 | ) | ||||
Office and administration and other expenses | (15,780 | ) | (15,975 | ) | ||||
Foreign exchange loss | (229 | ) | (1,176 | ) | ||||
EBITDA(1) | 24,901 | 17,935 | ||||||
Depreciation and amortization | (4,026 | ) | (2,787 | ) | ||||
Interest expense | (4,346 | ) | (3,739 | ) | ||||
Profit before income taxes | 16,529 | 11,409 | ||||||
Income tax expense | (4,962 | ) | (4,701 | ) | ||||
Net profit | 11,567 | 6,708 | ||||||
Gross Margin(2) | 39,647 | 34,014 |
(1) | EBITDA is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
(2) | Gross margin is a non-GAAP measure and is “external sales” and “inter-segment revenue - sales” less “cost of sales and operating expenses” and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
Downstream Operating Review
Key Downstream Metrics | Quarter ended December 31, | Year ended December 31, | ||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Sales volumes (millions of liters) | 187.7 | 170.2 | 678.0 | 626.5 | ||||||||||||
Average sales price per liter (PGK) | 2.43 | 2.07 | 2.55 | 2.19 |
Management Discussion and Analysis INTEROIL CORPORATION 19 |
Analysis of Downstream Financial Results Comparing the Year and Quarter Ended December 31, 2011 and 2010
The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the years and quarters ended December 31, 2011 and 2010.
Yearly Variance ($ millions) | Quarterly Variance ($ millions) | |||||||||||
$ | 4.9 | $ | 1.0 | Net profit/(loss) variance for the comparative periods primarily due to: | ||||||||
Ø | $ | 5.6 | $ | (0.1 | ) | Gross margins increased compared to the prior year mainly due to an increase in domestic sales volumes resulting from various development projects being undertaken in Papua New Guinea, the impact of the revised pricing formula that came into effect in late 2010, and the increasing price environment during the period leading to higher margins on inventories sold. | ||||||
Ø | $ | 0.9 | $ | 1.8 | Increase in foreign exchange gain due to the strengthening of the PGK against the USD. The PGK strengthened against the USD from 0.3785 at the start of the year to 0.4665 as at December 31, 2011. | |||||||
Ø | $ | (1.2 | ) | $ | (0.7 | ) | Increase in depreciation and amortization expenses due to the impact of capital additions over the past year related primarily to office refurbishment and upgrade projects across various terminals and depots. | |||||
Ø | $ | (0.6 | ) | $ | (0.3 | ) | Increase in interest expense due to the increased utilization of the working capital facility during the year. |
CORPORATE – YEAR AND QUARTER IN REVIEW
Corporate – Operating results | Year ended December 31, | |||||||
($ thousands) | 2011 | 2010 | ||||||
External sales | 266 | - | ||||||
Inter-segment revenue - Sales | 13,859 | 402 | ||||||
Inter-segment revenue - Recharges | 39,503 | 32,162 | ||||||
Interest revenue | 38,512 | 24,335 | ||||||
Other non-allocated revenue | (23 | ) | 23 | |||||
Total revenue | 92,117 | 56,922 | ||||||
Cost of sales and operating expenses | (11,421 | ) | - | |||||
Office and administration and other expenses | (47,371 | ) | (40,291 | ) | ||||
Derivative (loss)/gain | (11 | ) | 527 | |||||
Foreign exchange gain | 954 | 1,051 | ||||||
Loss on Flex LNG investment | (3,420 | ) | - | |||||
Litigation settlement expense | - | (12,000 | ) | |||||
EBITDA(1) | 30,848 | 6,209 | ||||||
Depreciation and amortization | (1,706 | ) | (106 | ) | ||||
Interest expense | (6,012 | ) | (1,541 | ) | ||||
Profit before income taxes | 23,130 | 4,562 | ||||||
Income tax expense | (1,248 | ) | (1,240 | ) | ||||
Net profit | 21,882 | 3,322 |
(1) | EBITDA is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
Management Discussion and Analysis INTEROIL CORPORATION 20 |
Analysis of Corporate Financial Results Comparing the Year and Quarter Ended December 31, 2011 and 2010
During 2011, our Corporate segment took over the management of our shipping business from Downstream operations. We currently operate two vessels transporting petroleum products for our Downstream segment and external customers, both within PNG and for export in the South Pacific region. External sales above relates to the shipping charges billed to external customers, and inter-segment revenue - sales relates to shipping charges billed to our Downstream segment.
The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the years and quarters ended December 31, 2011 and 2010.
Yearly Variance ($ millions) | Quarterly Variance ($ millions) | |||||||||||
$ | 18.6 | $ | 4.2 | Net profit/(loss) variance for the comparative periods primarily due to: | ||||||||
Ø | $ | 12.0 | - | One time litigation settlement expense in the prior year on account of the agreed settlement of the Todd Peters et al litigation for which we issued 199,677 common shares to the plaintiffs. | ||||||||
Ø | $ | (3.4 | ) | $ | (1.6 | ) | Loss recognized on our investment in shares in Flex LNG held by us as part of the framework agreements entered into with FLEX LNG and Samsung Heavy Industries in April 2011. As per the guidance under IFRS, an impairment loss has to be recognized in the income statement if reduction in fair value of the investment is evidenced by significant or prolonged declined in the fair value of the investment. | |||||
Ø | $ | 9.7 | $ | 4.6 | Reduced interest expenses (net of recharged intercompany interest revenue from other segments) due to higher interest charges to other business segments on increased loan balances. | |||||||
Ø | $ | (0.1 | ) | $ | 0.6 | Movement in foreign exchange gain mainly in relation to the strengthening of the AUD and SGD against the USD. |
Management Discussion and Analysis INTEROIL CORPORATION 21 |
CONSOLIDATION ADJUSTMENTS – YEAR AND QUARTER IN REVIEW
Consolidation adjustments – Operating results | Year ended December 31, | |||||||
($ thousands) | 2011 | 2010 | ||||||
Inter-segment revenue - Sales | (590,729 | ) | (376,951 | ) | ||||
Inter-segment revenue - Recharges | (48,344 | ) | (35,440 | ) | ||||
Interest revenue(5) | (38,010 | ) | (24,281 | ) | ||||
Other non-allocated revenue | - | - | ||||||
Total revenue | (677,083 | ) | (436,672 | ) | ||||
Cost of sales and operating expenses(1) | 592,527 | 374,818 | ||||||
Office and administration and other expenses(2) | 48,541 | 36,325 | ||||||
EBITDA(3) | (36,015 | ) | (25,529 | ) | ||||
Depreciation and amortization (4) | 130 | 130 | ||||||
Interest expense (5) | 38,010 | 24,282 | ||||||
Profit/(loss) before income taxes | 2,125 | (1,117 | ) | |||||
Income tax expense | - | - | ||||||
Net profit/(loss) | 2,125 | (1,117 | ) | |||||
Gross Margin(6) | 1,798 | (2,133 | ) |
(1) | Represents the elimination upon consolidation of our refinery sales to other segments and other minor inter-company product sales. |
(2) | Includes the elimination of inter-segment administration service fees. |
(3) | EBITDA is a non-GAAP measure and is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
(4) | Represents the amortization of a portion of costs capitalized to assets on consolidation. |
(5) | Includes the elimination of interest accrued between segments. |
(6) | Gross margin is a non-GAAP measure and is “inter-segment revenue elimination” less “cost of sales and operating expenses” and represents elimination upon consolidation of our refinery sales to other segments. This measure is reconciled to IFRS in the section to this document entitled “Non-GAAP Measures and Reconciliation”. |
Analysis of Consolidation Adjustments Comparing the Year and Quarter Ended December 31, 2011 and 2010
The following table outlines the key movements, the net of which primarily explains the variance in the results between the years and quarters ended December 31, 2011 and 2010.
Yearly Variance ($ millions) | Quarterly Variance ($ millions) | |||||||||||
$ | 3.2 | $ | 0.7 | Net profit/(loss) variance for the comparative periods primarily due to: | ||||||||
Ø | $ | 3.2 | $ | 0.7 | Variance in net income due to changes in intra-group profit eliminated on consolidation between Midstream Refining and Downstream segments in the prior periods relating to the Midstream Refining segment’s profit component of inventory on hand in the Downstream segment at period ends. |
Management Discussion and Analysis INTEROIL CORPORATION 22 |
LIQUIDITY AND CAPITAL RESOURCES
Summary of Debt Facilities
Summarized below are the debt facilities available to us and the balances outstanding as at December 31, 2011.
Organization | Facility | Balance outstanding December 31, 2011 | Effective interest rate | Maturity date | ||||||||||||
OPIC secured loan | $ | 35,500,000 | $ | 35,500,000 | 6.93 | % | December 2015 | |||||||||
BNP Paribas working capital facility | $ | 260,000,000 | (2) | $ | 10,030,131 | (1) | 3.38 | % | January 2012 | (3) | ||||||
Westpac PGK working capital facility | $ | 37,320,000 | (4) | $ | 6,450,372 | 9.65 | % | November 2014 | ||||||||
BSP PGK working capital facility | $ | 23,325,000 | $ | 0 | 9.47 | % | August 2012 | |||||||||
2.75% convertible notes | $ | 70,000,000 | $ | 70,000,000 | 7.91 | %(6) | November 2015 | |||||||||
Mitsui unsecured loan(5) | $ | 10,393,023 | $ | 10,393,023 | 6.23 | % | See detail below |
(1) | Excludes letters of credit totaling $164.9 million, which reduce the available balance of the facility to $85.1 million at December 31, 2011. |
(2) | The facility was increased by $30.0 million during the quarter ended March 31, 2011 from $190.0 million to $220.0 million, and was then increased by a further $10.0 million during the quarter ended June 30, 2011 to $230.0 million. During the quarter ended December 31, 2011 there was a temporary $30.0 million increase to $260.0 million. The facility reverted back to a maximum availability of $230.0 million at the end of January 2012. |
(3) | The facility was extended after the end of the year, and it now matures on January 31, 2013. |
(4) | Subsequent to the year end, the limit on this facility was increased by approximately $4.7 million, with a new limit of approximately $42.0 million. |
(5) | Facility is to fund our share of the Condensate Stripping Project costs as they are incurred pursuant to the JVOA. |
(6) | Effective rate after bifurcating the equity and debt components of the $70 million principal amount of 2.75% convertible senior notes due 2015. |
OPIC Secured Loan (Midstream - Refinery)
In 2001, one of our subsidiaries entered into a loan agreement with OPIC for provision of an $85.0 million project financing facility for the development of our refinery in PNG. The loan is primarily secured by the assets of the refinery. On June 20, 2011, OPIC signed agreements agreeing to release all of the sponsor support collateral and requirements for the loan granted in 2001 in recognition of our financial and operational maturity. The balance outstanding under the loan as at December 31, 2011 was $35.5 million. The interest rate on the loan is equal to the agreed U.S. Government treasury cost applicable to each promissory note that was issued and is outstanding plus 3%, and is payable quarterly in arrears. Principal repayments of $4.5 million each are due on June 30 and December 31 of each year until December 31, 2015. At December 31, 2011, $5.9 million was, and is still, being held on deposit to secure our June 30, 2012 principal and interest payments on the secured loan.
BNP Paribas Working Capital Facility (Midstream - Refinery)
This working capital facility is used to finance purchases of crude feedstock for our refinery. In accordance with the agreement with BNP Paribas, the total facility is split into two components, Facility 1 and Facility 2 which are renewable annually. At December 31, 2011, Facility 1 had a limit of $200.0 million (increased temporarily from $170.0 million during the quarter ended December 31, 2011) and finances the purchases of crude and hydrocarbon products through the issuance of documentary letters of credit and standby letters of credit, short term advances, advances on merchandise, freight loans, and has a sublimit of Euro 18.0 million or the USD equivalent for hedging transactions. At January 31, 2012, the limit on Facility 1 reverted back to $170.0 million. Facility 2 allows borrowings of up to $60.0 million and can be used for partly cash-secured short term advances and for discounting of any monetary receivables acceptable to BNP Paribas in order to reduce Facility 1 balances. The facility is secured by sales contracts, purchase contracts, certain cash accounts associated with the refinery, all crude and refined products of the refinery and trade receivables.
Management Discussion and Analysis INTEROIL CORPORATION 23 |
As of December 31, 2011, $85.1 million remained available for use under the facility. The facility bears interest at LIBOR plus 3.5% on short term advances. The weighted average interest rate under the working capital facility was 3.38% for the year ended December 31, 2011 (compared with 2.69% for the same period of 2010), after including the reduction in interest due to the deposit amounts (restricted cash) maintained as security.
Bank South Pacific and Westpac Working Capital Facility (Downstream)
On October 24, 2008, we secured a PGK 150.0 million (approximately $70.0 million) combined revolving working capital facility for our Downstream wholesale and retail petroleum products distribution business from Bank of South Pacific Limited and Westpac Bank PNG Limited. The facility limit as at December 31, 2011 was PGK 130.0 million (approximately $60.6 million).
The Westpac facility limit is PGK 80.0 million (approximately $37.3 million). This facility was for an initial term of three years and was renewed in November 2011 for a further three years to November 2014. Subsequent to year end, the limit of this facility was increased by PGK 10.0 million (approximately $4.7 million) with an increased limit of PGK 90.0 million (approximately $42.0 million). In addition, a secured loan of $15.0 million was provided as part of this increased facility which is repayable in equal installments over 3.5 years with an interest rate of LIBOR + 4.4% per annum. The BSP facility limit is PGK 50.0 million (approximately $23.3 million), and was renewed in August 2011 for another year. As at December 31, 2011, PGK 13.8 million (approximately $6.5 million) of this combined facility had been utilized.
The weighted average interest rate under the Westpac facility was 10.0% for the quarter and 9.65% for the year ended December 31, 2011, while the weighted average interest rate under the BSP facility was 9.94% for the quarter and 9.47% for the year ended December 31, 2011.
2.75% Convertible Notes (Corporate)
On November 10, 2010, we completed the issuance of $70.0 million unsecured 2.75% convertible notes with a maturity of five years. The convertible notes rank junior to any secured indebtedness and to all existing and future liabilities of us and our subsidiaries, including the BNP Paribas working capital facility, the OPIC secured loan facility, the BSP and Westpac working capital facilities, the Mitsui preliminary financing agreement, trade payables and lease obligations.
We pay interest on the notes semi-annually on May 15 and November 15. The notes are convertible into cash or common shares, based on an initial conversion rate of 10.4575 common shares per $1,000 principal amount, which represents an initial conversion price of approximately $95.625 per common share. The initial conversion price is subject to standard anti-dilution provisions designed to maintain the value of the conversion option in the event we take certain actions with respect to our common shares, such as stock splits, reverse stock splits, stock dividends and cash dividends, that affect all of the holders of our common shares equally and that could have a dilutive effect on the value of the conversion rights of the holders of the notes or that confer a benefit upon our current shareholders not otherwise available to the convertible notes. Upon conversion, holders will receive cash, common shares or a combination thereof, at our option. The convertible notes are redeemable at our option if our share price has been at least 125% ($119.53 per share) of the conversion price for at least 15 trading days during any 20 consecutive trading day period. Upon a fundamental change, which would include a change of control, holders may require us to repurchase their convertible notes for cash at a purchase price equal to the principal amount of the notes to be repurchased, plus accrued and unpaid interest.
Mitsui Unsecured Loan (Upstream)
On April 15, 2010, we entered into preliminary joint venture and financing agreements with Mitsui relating to the Condensate Stripping Project. On August 4, 2010, we entered into the Condensate Stripping Project Joint Venture with Mitsui for the condensate stripping facilities. Mitsui and InterOil hold equal interest in the joint venture. Mitsui is to be responsible for arranging or providing financing for the capital costs of the condensate stripping facility.
Management Discussion and Analysis INTEROIL CORPORATION 24 |
The portion of funding that relates to Mitsui’s share of the Condensate Stripping Project as at December 31, 2011, amounting to approximately $11.4 million, is held in current liabilities as the agreement requires refund of all funds advanced by Mitsui under the preliminary financing agreement if a positive FID is not reached. The portion of funding that relates to our share of the Condensate Stripping Project (amounting to $10.4 million), funded by Mitsui, is classed as an unsecured loan and interest accrues daily based on LIBOR plus a margin of 6%.
While cash flows from operations are expected to be sufficient to cover our operating commitments, should there be a major long term deterioration in refining or wholesale and retail margins, our operations may not generate sufficient cash flows to cover all of the interest and principal payments under our debt facilities noted above. Also, our exploration and development activities require funding beyond our operational cash flows and the cash balances we currently hold. As a result, we will be required to raise additional capital and/or refinance these facilities in the future. We can provide no assurances that we will be able to obtain such additional capital or that our lenders will agree to refinance these debt facilities, or, if available, that the terms of any such capital raising or refinancing will be acceptable to us.
Other Sources of Capital
Currently our share of expenditures on exploration wells, appraisal wells and extended well programs is funded by a combination of contributions made by capital raising activities, operational cash flows, IPI investors and asset sales.
Cash calls are made on IPI investors and Pac LNG (for its 2.5% direct interest in the Elk and Antelope field acquired during 2009) for their share of amounts spent on certain appraisal wells and extended well programs where they participate in such wells and programs pursuant to the relevant agreements in place with them.
Summary of Cash Flows
($ thousands) | Year ended December 31, | |||||||||||
2011 | 2010 | 2009 | ||||||||||
Net cash inflows/(outflows) from: | ||||||||||||
Operations | 62,670 | (13,561 | ) | 44,500 | ||||||||
Investing | (204,241 | ) | (111,158 | ) | (85,567 | ) | ||||||
Financing | (27,165 | ) | 311,846 | 38,546 | ||||||||
Net cash movement | (168,736 | ) | 187,127 | (2,521 | ) | |||||||
Opening cash | 233,577 | 46,450 | 48,971 | |||||||||
Exchange gains on cash and cash equivalents | 4,005 | - | - | |||||||||
Closing cash | 68,846 | 233,577 | 46,450 |
Analysis of Cash Flows Provided By/(Used In) Operating Activities Comparing the Years ended December 31, 2011 and 2010
The following table outlines the key variances in the cash flows from operating activities between the years ended December 31, 2011 and 2010:
Yearly variance ($ millions) | ||||||||
$ | 76.2 | Variance for the comparative periods primarily due to: | ||||||
Ø | $ | 26.1 | Increase in cash generated by operations prior to changes in operating working capital for the year ended December 31, 2011, mainly due to the increased profits from operations adjusted for non cash items mainly relating to the loss on extinguishment of IPI liability and non cash litigation settlement expense in the prior year. |
Management Discussion and Analysis INTEROIL CORPORATION 25 |
Ø | $ | 50.1 | Decrease in cash used by operations relating to changes in operating working capital. The decrease in cash used for the year is due primarily to a $28.0 million decrease in inventories due to timing of crude and export shipments and a $71.6 million increase in accounts payable and accrued liabilities, partially offset by a $43.8 million increase in trade receivables. |
Analysis of Cash Flows Provided By/(Used In) Investing Activities Comparing the Years Ended December 31, 2011 and 2010
The following table outlines the key variances in the cash flows from investing activities between the years ended December 31, 2011 and 2010:
Yearly variance ($ millions) | ||||||||
$ | (93.1 | ) | Variance for the comparative periods primarily due to: | |||||
Ø | $ | (21.8 | ) | Higher cash outflows on exploration and development program expenditures related to seismic activity on PPL 236 and PPL 237, FEED work for the Condensate Stripping Project and LNG Project, and site preparations for the Triceratops 2 field appraisal well. | ||||
Ø | $ | (23.0 | ) | Lower cash calls and related inflows from IPI investors due to activity being focused on seismic activities, for which no contribution is required, rather than appraisal drilling and subsequent work program activities. | ||||
Ø | $ | (19.5 | ) | Higher expenditure on plant and equipment. The expenditures were mainly associated with refurbishment of retail sites, tank upgrades, camp and office refurbishments and, less significantly, relocation of the corporate offices in PNG and Australia. | ||||
Ø | $ | (15.5 | ) | Receipt in 2010 of the final installment of $13.9 million relating to the sale of 2.5% direct working interest in the Elk and Antelope fields to Pac LNG in September 2009 and $1.6 million proceeds from the sale of our interest in PPL 244. | ||||
Ø | $ | (11.8 | ) | Investment in short term PGK Treasury bills. | ||||
Ø | $ | (7.5 | ) | Acquisition of FLEX LNG shares net of transaction costs. | ||||
Ø | $ | 26.0 | Higher cash inflows due to reduction in our cash restricted balances in line with the usage of the BNP working capital facility. | |||||
Ø | $ | (20.0 | ) | Increase in cash used in our Upstream segment for working capital requirements. This working capital relates to movements in accounts receivable, accounts payable and accruals in our Upstream and Midstream Liquefaction operations. |
Analysis of Cash Flows Provided By/(Used In) Financing Activities Comparing the Years Ended December 31, 2011 and 2010
The following table outlines the key variances in the cash flows from financing activities between years ended December 31, 2011 and 2010:
Yearly variance ($ millions) | ||||||||
$ | (339.0 | ) | Variance for the comparative periods primarily due to: | |||||
Ø | $ | (61.4 | ) | Higher repayments of the BNP Paribas working capital facility due to increased working capital requirements. |
Management Discussion and Analysis INTEROIL CORPORATION 26 |
Ø | $ | (206.7 | ) | Net proceeds after transaction costs from the issuance of shares relating to the issuance of 2,800,000 common shares in November 2010. | ||||
Ø | $ | (66.3 | ) | Net proceeds after transaction costs from the issuance of $70.0 million of 2.75% convertible notes in November 2010. | ||||
Ø | $ | 1.4 | Proceeds received from Pac LNG for its share of costs incurred in developing the LNG Project. | |||||
Ø | $ | (2.0 | ) | Reduction in funding received from Mitsui relating to the Condensate Stripping Project. | ||||
Ø | $ | (5.0 | ) | Proceeds received from Petromin for contributions towards cash calls made with respect to development activities for the Elk and Antelope fields. No proceeds were received during 2011. |
Capital Expenditures
Upstream Capital Expenditures
Capital expenditures for exploration in Papua New Guinea for the year to December 31, 2011 were $107.6 million, compared with $82.8 million during the same period of 2010.
The following table outlines the key expenditures in the year ended December 31, 2011:
Yearly ($ millions) | ||||||||
$ | 107.6 | Expenditures in the year ended December 31, 2011 primarily due to: | ||||||
Ø | $ | 7.1 | Completion costs on the Antelope-2 well, mainly relating to expenditure on our drilling rig necessitated by corrosion caused by the use of drilling mud used to conduct the side tracks and complete the well. | |||||
Ø | $ | 16.9 | Costs for early works in respect of the Condensate Stripping Project. | |||||
Ø | $ | 24.2 | Costs associated with the Triceratops 2 well relating to pre-spud and standby costs. | |||||
Ø | $ | 16.7 | Costs for the construction of a road from our Antelope field to our river-based logistics hub on the Purari river. | |||||
Ø | $ | 6.2 | Capital works costs on infrastructure at the river based logistics hub. | |||||
Ø | $ | 36.5 | Other expenditures, including heavy equipment purchases and drilling inventory. |
IPI investors and Pac LNG (2.5% direct interest in Elk and Antelope fields) are presently required to fund 24.3886% of the Elk and Antelope fields extended well program costs to maintain their interest in those fields. The amounts capitalized in our books, or expensed as incurred, in relation to the extended well program are the net amounts after adjusting for these interests.
Petromin had agreed to fund 20.5% of ongoing costs for developing the fields. There were no contributions from Petromin during the year ended December 31, 2011 and therefore the total advance payment received from Petromin remains at $15.4 million. At the end of the 2011 year, the parties agreed that the investment agreement between Petromin and InterOil governing Petromin’s participation in the Elk and Antelope fields should terminate. Petromin remains the State’s nominee to acquire the State’s interest in the Elk and Antelope fields under relevant Papua New Guinean legislation, once a PDL is granted. We have proposed that cash contributions made by Petromin to date to fund the development will be held and credited against the State’s obligation to contribute its portion of sunk costs upon grant of the PDL.
The preliminary financing agreement entered into with Mitsui provides for funding by Mitsui of all the costs relating to the Condensate Stripping Project. 50% of the funding is for Mitsui’s share of the project and the other 50% is funding by Mitsui of our share of the project. Mitsui contributed $9.9 million during the year for both Mitsui’s and our share, and has contributed $21.8 million in aggregate. In the event that a positive FID is not reached or made, we will be required to refund all of Mitsui’s contributions (i.e. for our share and Mitsui’s) within a specified period.
Management Discussion and Analysis INTEROIL CORPORATION 27 |
Midstream Capital Expenditures
Capital expenditures totaled $15.9 million in our Midstream Refining segment for the year ended December 31, 2011, mainly associated with camp and office building works, motor vehicles and heavy pumper tanker purchases.
Following the signing of the LNG Project Agreement with the State in December 2009, $5.3 million of costs incurred during the year in relation to the Midstream - Liquefaction segment have been capitalized.
Downstream Capital Expenditures
Capital expenditures for the Downstream segment totaled $10.2 million for the year ended December 31, 2011. These expenditures mainly related to a number of upgrade projects across various terminals and depots, and office refurbishments.
Corporate Capital Expenditures
Capital expenditures for the Corporate segment totaled $3.1 million for the year ended December 31, 2011. These expenditures mainly related to project costs in relation to the new business system implementation in the Downstream business and costs associated with relocation of the corporate office in Cairns, Australia.
Capital Requirements
The oil and gas exploration and development, refining and liquefaction industries are capital intensive and our business plans necessarily involve raising additional capital. The availability and cost of such capital is highly dependent on market conditions at the time we raise such capital. No assurance can be given that we will be successful in obtaining new capital on terms that are acceptable to us, particularly given current market volatility.
The majority of our “net cash from operating activities” adjusted for “proceeds from/(repayments of) working capital facilities” is used in our appraisal and development programs for the Elk and Antelope, and Triceratops fields in PNG. Our net cash from working activities is not sufficient to fund those appraisal and development programs.
Upstream
We are required under our $125.0 million IPI Agreement of 2005 to drill eight exploration wells. We have drilled four wells to date. As at December 31, 2011, we are committed under the terms of our exploration licenses or PPL’s to spend a further $61.9 million through 2015. As at December 31, 2011, management estimates that satisfying these license commitments with the expenditure of $61.9 million would also satisfy our commitments to the IPI investors in relation to drilling the final four wells and satisfy the commitments in relation to the IPI agreement.
In addition, the terms of grant of PRL 15 require us to spend a further $73.0 million on the development of the Elk and Antelope fields by the end of 2014.
We do not have sufficient funds to complete planned exploration and development and we will need to raise additional funds in order for us to complete the programs and meet our exploration commitments. Therefore, we must extend or secure sufficient funding through renewed borrowings, equity raising and or asset sales to enable the availability of sufficient cash to meet these obligations over time and complete these long term plans. No assurances can be given that we will be successful in obtaining new capital on terms acceptable to us, particularly given recent market volatility.
We will also be required to obtain substantial amounts of financing for the development of the Elk and Antelope fields, condensate stripping and associated facilities, pipelines and LNG export terminal facilities, and it will take a number of years to complete these projects. In the event that positive FID is reached in respect of these projects, we seek to be in a position to access the capital markets and/or sell an interest in our upstream properties in order to raise adequate capital. In September 2011, we retained financial advisors to help solicit and evaluate proposals from potential strategic partners to acquire interests in our Elk and Antelope fields, LNG Project and exploration licenses. The solicitation process is now under way and we believe, it will, if successful, provide a further source of funds for exploration and development activities. No assurances can be given that we will be able to attract strategic partners on terms acceptable to us.
Management Discussion and Analysis INTEROIL CORPORATION 28 |
The availability and cost of various sources of financing is highly dependent on market conditions and our condition at the time we raise such capital and we can provide no assurances that we will be able to obtain such financing or conduct such sales on terms that are acceptable.
Midstream - Refining
We believe that we will have sufficient funds from our operating cash flows to pay our estimated capital expenditures associated with our Midstream Refining segment in 2012. We also believe cash flows from operations will be sufficient to cover the costs of operating our refinery and the financing charges incurred under our crude import facility. Should there be a long term deterioration in refining margins, our refinery may not generate sufficient cash flows to cover all of the interest and principal payments under our secured loan agreements. As a result, we may be required to raise additional capital and/or refinance these facilities in the future.
Midstream - Liquefaction
On September 28, 2010, we and LNGL (a wholly owned subsidiary of PNG LNG) signed a heads of agreement with EWC to construct a three mtpa land based liquefaction facility in the Gulf Province of Papua New Guinea. Following this agreement, on February 2, 2011, the parties signed certain conditional framework agreements defining certain parameters for the aforementioned development, construction, financing and the operation of the planned land-based liquefaction facilities. These facilities are intended to be developed in phases and further definitive agreements are contemplated.
The LNG facilities are intended to be developed in two phases, an initial two mtpa followed by a one mtpa expansion. In return for its commitment to fully fund the construction of the facilities, EWC is to be entitled to a fee of 14.5% of the proceeds from LNG revenue from these facilities, less agreed deductions, and subject to adjustments based on timing and execution.
On April 11, 2011, we and Pac LNG entered into certain conditional framework agreements with FLEX LNG and Samsung Heavy Industries for the proposed construction of a 1.8 mtpa or 2 mtpa fixed-floating liquefied natural gas vessel. Such a vessel is expected to integrate with and augment the land-based modules to be developed with EWC. The framework agreements provided that the parties were to undertake project specific FEED work and negotiate final binding agreements in time for a FID decision in mid-December 2011. Project specific FEED work was carried out. However, as FID was not reached by mid-December 2011, these framework agreements with FLEX LNG and Samsung lapsed and were not extended. We are continuing to negotiate with FLEX LNG.
The fixed-floating project is intended to integrate with and augment proposed on-shore infrastructure to transport LNG from the onshore Elk and Antelope fields in the Gulf Province of Papua New Guinea pursuant to arrangements with EWC and Mitsui.
In September 2011, we retained financial advisors to help solicit and evaluate proposals from potential strategic partners to, amongst other things, obtain an interest in, operate and help finance the development of the LNG Project. No assurances can be given that we will be able to attract strategic partners on terms acceptable to us, how such an agreement will affect our current LNG Project plans or whether such a partner will be acceptable to the PNG government.
Completion of the LNG Project will require substantial amounts of financing and construction will take a number of years to complete. As a joint venture partner in development, if the project is completed, we would be required to fund our share of certain common facilities of the development. No assurances can be given that we will be able to source sufficient gas, successfully construct such a facility, or as to the timing of such construction. The availability and cost of capital is highly dependent on market conditions and our circumstances at the time we raise such capital.
Management Discussion and Analysis INTEROIL CORPORATION 29 |
Downstream
We believe on the basis of current market conditions and the status of our business that our cash flows from operations will be sufficient to meet our estimated capital expenditures for our wholesale and retail distribution business segment for 2012.
Contractual Obligations and Commitments
The following table contains information on payments required to meet contracted exploration and debt obligations due for each of the next five years and thereafter. It should be read in conjunction with our financial statements for the year ended December 31, 2011 and the notes thereto:
Payments Due by Period | ||||||||||||||||||||||||||||
Contractual obligations ($ thousands) | Total | Less than 1 year | 1 - 2 years | 2 - 3 years | 3 - 4 years | 4 - 5 years | More than 5 years | |||||||||||||||||||||
Petroleum prospecting and retention licenses(a) | 134,900 | 44,400 | 36,350 | 44,050 | 9,900 | 200 | - | |||||||||||||||||||||
Secured and unsecured loans(b) | 51,586 | 21,727 | 10,749 | 10,131 | 8,979 | - | - | |||||||||||||||||||||
2.75% Convertible notes obligations | 77,540 | 1,925 | 1,925 | 1,925 | 71,765 | - | - | |||||||||||||||||||||
Indirect participation interest - PNGDV | 1,384 | 540 | 844 | - | - | - | - | |||||||||||||||||||||
Total | 265,410 | 68,592 | 49,868 | 56,106 | 90,644 | 200 | - |
(a) | The amount pertaining to the petroleum prospecting and retention licenses represents the amount we have committed as a condition on renewal of these licenses. We are committed to spend a further $61.9 million as a condition of renewal of our petroleum prospecting licenses through 2014 under our exploration licenses. As at December 31, 2011, management estimates that satisfying this license commitment with the expenditure of $61.9 million would also satisfy our commitments to the IPI investors in relation to drilling the final four wells and satisfy the commitments in relation to the IPI agreement. In addition, the terms of grant of PRL15, requires us to spend a further $73.0 million on the development of the Elk and Antelope fields by the end of 2014. |
(b) | The effective interest rate on these loans for the year ended December 31, 2011 was 6.93%. |
The following table contains information on payments required to meet our operating lease commitments. It should be read in conjunction with our financial statements for the year ended December 31, 2011 and the notes thereto:
Year ended December 31, | ||||||||
($ thousands) | 2011 | 2010 | ||||||
Not later than 1 year | 6,983 | 6,257 | ||||||
Later than 1 year and not later than 5 years | 6,560 | 8,558 | ||||||
Later than 5 years | 2,958 | 458 | ||||||
Total | 16,501 | 15,273 |
Off Balance Sheet Arrangements
Neither during the year ended, nor as at December 31, 2011, did we have any off balance sheet arrangements or any relationships with unconsolidated entities or financial partnerships.
Management Discussion and Analysis INTEROIL CORPORATION 30 |
Transactions with Related Parties
Petroleum Independent and Exploration Corporation, is owned by Mr. Mulacek, our Chairman and Chief Executive Officer. Prior to 2011, Petroleum Independent and Exploration Corporation received a management fee in its capacity as the General Manager of one of our subsidiaries, S.P. InterOil LDC, in compliance with OPIC loan requirements. During the year ended December 31, 2010, Petroleum Independent and Exploration Corporation received $150,000. On June 20, 2011, OPIC signed agreements agreeing to release all of the sponsor support collateral and requirements for the loan granted to us in 2001 in recognition of our financial and operational maturity. As a result, no fees were paid to Petroleum Independent and Exploration Corporation in the year ended December 31, 2011. In November of 2011, we elected to exchange the 5,000 shares held in S.P. InterOil LDC by Petroleum Independent and Exploration Corporation for 5,000 shares in InterOil Corporation. The sponsor agreements were terminated with Petroleum Independent and Exploration Corporation on exchange of the share holding interest in S.P. InterOil LDC. Subsequent to year end, S.P. InterOil LDC has been renamed South Pacific Refining Limited.
Breckland Limited, a company controlled by Mr. Roger Grundy, one of our directors, previously provided technical and advisory services to us on normal commercial terms. Amounts paid or payable to Breckland for technical services during the year ended December 31, 2011 amounted to $nil (December 2010 - $21,923).
Share Capital
Our authorized share capital consists of an unlimited number of common shares and unlimited number of preferred shares, of which 1,035,554 series A preferred shares are authorized (none of which are outstanding). As of December 31, 2011, we had 48,121,071 common shares (50,833,593 common shares on a fully diluted basis) and no preferred shares outstanding. The potential dilutive instruments outstanding as at December 31, 2011 included employee stock options and restricted stock in respect of 1,640,017 common shares, IPI conversion rights to 340,480 common shares and 732,025 common shares relating to the $70.0 million principal amount 2.75% convertible senior notes due November 15, 2015. The 5,000 common shares previously recorded as potentially dilutive instruments were issued to Petroleum Independent and Exploration Corporation in the quarter ended December 31, 2011 in exchange for the 5,000 shares it held in our subsidiary, S.P. InterOil LDC.
Derivative Instruments
Our revenues are derived from the sale of refined products. Prices for refined products and crude feedstocks can be volatile and sometimes experience large fluctuations over short periods of time as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions. Due to the nature of our business, there is always a time difference between the purchase of a crude feedstock and its arrival at the refinery and the supply of finished products to the various markets.
Generally, we purchase crude feedstock two months in advance, whereas the supply/export of finished products will take place after the crude feedstock is discharged and processed. Due to the fluctuation in prices during this period, we use various derivative instruments as a tool to reduce the risks of changes in the relative prices of our crude feedstocks and refined products. These derivatives, which we use to manage our price risk, effectively enable us to lock-in the refinery margin such that we are protected in the event that the difference between our sale price of the refined products and the acquisition price of our crude feedstocks contracts is reduced. Conversely, when we have locked-in the refinery margin and if the difference between our sales price of the refined products and our acquisition price of crude feedstocks expands or increases, then the benefits would be limited to the locked-in margin
The derivative instruments which we generally use are the over-the-counter swaps. The swap transactions are concluded between counterparties in the derivatives swaps market, unlike futures which are transacted on the International Petroleum Exchange and Nymex Exchanges. We believe these hedge counterparties to be credit worthy. It is common place among refiners and trading companies in the Asia Pacific market to use derivatives swaps as a tool to hedge their price exposures and margins. Due to the wide usage of derivatives tools in the Asia Pacific region, the swaps market generally provides sufficient liquidity for the hedging and risk management activities. The derivatives swap instrument covers commodities or products such as jet and kerosene, diesel, naphtha, and also bench-mark crudes such as Tapis and Dubai. By using these tools, we actively engage in hedging activities to lock in margins. Occasionally, there is insufficient liquidity in the crude swaps market and we then use other derivative instruments such as Brent futures on the IPE to hedge our crude costs.
Management Discussion and Analysis INTEROIL CORPORATION 31 |
At December 31, 2011, we had a net receivable of $0.6 million (December 2010 – payable of $0.2 million) relating to open contracts to sell gasoil crack swaps and sell dated Brent swaps for which hedge accounting has not been applied, and Brent swaps that have been priced out and will be settled in January and February 2012.
A gain of $2.0 million was recognized on the non-hedge accounted derivative contracts for the year ended December 31, 2011 (December 2010 – $1.6 million loss).
In addition to the commodity derivative contracts, we have also entered into foreign exchange derivative contracts to manage our foreign exchange risk in relation to AUD. As at December 31, 2011, we had $11,457 payable (December 2010 - nil) relating to our foreign currency derivatives. An $11,457 loss has been recognized on foreign exchange derivative contracts for the year ended December 31, 2011 (December 2011 - $0.5 million gain).
INDUSTRY TRENDS AND KEY EVENTS
Competitive Environment and Regulated Pricing
We are currently the sole refiner of hydrocarbons in Papua New Guinea although there is no legal restraint upon other refineries being established. The PNG Government has agreed to ensure that all domestic distributors purchase their refined petroleum products from our refinery, or any other refinery which is constructed in Papua New Guinea, at an Import Parity Price (“IPP”). The IPP is monitored by the ICCC. In general, the IPP is the price that would be paid in Papua New Guinea for a refined product being imported. For all price controlled products (diesel, unleaded petrol, kerosene and aviation fuel) produced and sold locally in Papua New Guinea, the IPP is calculated by adding the costs that would typically be incurred to import such product to Mean of Platts Singapore (“MOPS”) which is the benchmark price for refined products in the region in which we operate.
In our refining business, we compete with several companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. Many of our competitors obtain a significant portion of their feedstocks from company-owned production, which may enable them to obtain feedstocks at a lower cost. The high cost of transporting goods to and from Papua New Guinea reduces the availability of alternate fuel sources and retail outlets for our refined products. Competitors that have their own production or extensive distribution networks are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, new technology is making refining more efficient, which could lead to lower prices and reduced margins. We cannot be certain that we will be able to implement new technologies in a timely basis or at a cost that is acceptable to us.
We are also a significant participant in the retail and wholesale distribution business in Papua New Guinea. The ICCC regulates the maximum prices and margins that may be charged by the wholesale and retail hydrocarbon distribution industry in Papua New Guinea. Margins were last reviewed by the ICCC in 2010 and will be further reviewed in 2014. We and our competitors may charge less than the maximum margin set by the ICCC in order to maintain competitiveness.
Our main competitor in the wholesale and retail distribution business in Papua New Guinea is ExxonMobil. We also compete with smaller local distributors of petroleum products. Our competitors source small quantities from our refinery from both the refinery gantry for the Port Moresby market and by tanker vessel for the markets outside Port Moresby. Our major competitive advantage is the large widespread distribution network we maintain with adequate storage capacity that services most areas of PNG. We also believe that our commitment to the distribution business in Papua New Guinea at a time when major-integrated oil and gas companies exited the Papua New Guinea fuel distribution market provides us with a competitive advantage. However, major-integrated oil and gas companies such as ExxonMobil have greater resources than we do and could if they decided to do so, expand much more rapidly in this market than we can.
Management Discussion and Analysis INTEROIL CORPORATION 32 |
Our proposed LNG Project faces competition, including competing liquefaction facilities and related infrastructure, from competitors with far greater resources, including major international energy companies. Many competing companies have secured access to, or are pursuing development or acquisition of, liquefaction facilities to serve the same markets we intend to target. In addition, competitors have developed or reopened additional liquefaction facilities in other international markets, which may also compete with our LNG Project. Almost all of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to natural gas and LNG supplies than we do. The superior resources that these competitors have available for deployment could allow them to compete successfully against our LNG businesses, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
Financing Arrangements
We continue to monitor liquidity risk by setting of acceptable gearing levels and ensuring they are monitored. Our aim is to maintain our debt-to-capital ratio, or gearing levels, (debt/(shareholders’ equity + debt)) at 50% or less. This was achieved throughout 2011 and 2010. Gearing levels were 12% in December 2011 and 13% in December 2010.
On November 10, 2010, we completed concurrent public offerings of $70.0 million aggregate principal amount of 2.75% convertible senior notes due 2015 and 2,800,000 common shares at a price of $75.00 per share for proceeds of $210.0 million, raising gross proceeds of $280.0 million from the combined offerings.
No financing arrangements were entered into in 2011.
For details of other financial arrangements in place, see “Liquidity and Capital Resources – Summary of Debt Facilities”.
We had cash, cash equivalents and cash restricted of $108.1 million as at December 31, 2011, of which $39.3 million was restricted (as governed by BNP working capital facility utilization requirements and OPIC secured loan facility). In addition, we also had $11.8 million equivalent of PGK in short term treasury bills issued by the Bank of Papua New Guinea. With regard to our cash and cash equivalents, we invest in bankers acceptances and money market instruments with major financial institutions that we believe are creditworthy. We also had $85.1 million of the combined BNP working capital facility available for use in our Midstream – Refining operations, and $54.2 million of the Westpac/BSP combined working capital facility available for use in our Downstream operations.
Crude Prices
Crude prices increased steadily throughout 2011, with the price of Dated Brent crude oil (as quoted by Platts) starting the year at $97 per bbl and closing the year at $108 per bbl. The average price for Dated Brent for 2011 was $111 per bbl compared with $79 per bbl for Dated Brent for 2010.
At year end we had $85.1 million of the combined BNP working capital facility available for use in our Midstream – Refining operations, and approximately $54.2 million of the Westpac/BSP combined working capital facility available for use in our Downstream operations. Any increase in prices will have an impact on the utilization of our working capital facilities, and related interest and financing charges on the utilized amounts.
Any volatility of crude prices means that we face significant timing and margin risk on our crude cargos. A significant portion of this timing and margin risk is managed by us through short and long term hedges. There was a net receivable of $0.6 million relating to open contracts to sell gasoil crack swaps and sell Dated Brent swaps for which hedge accounting has not been applied, and Brent swaps that have been priced out and were settled in January and February of 2012.
Management Discussion and Analysis INTEROIL CORPORATION 33 |
Refining Margin
The distillation process used by our refinery to convert crude feedstocks into refined products is commonly referred to as hydroskimming. While the Singapore Tapis hydroskimming margin is a useful indicator of the general margin available for hydroskimming refineries in the region in which we operate, it should be noted that the differences in our approach to crude selection, transportation costs and IPP pricing work so that our realized margin generally differs to some extent.
Distillate margins to Dated Brent strengthened during 2011 compared with historical levels due to increasing demand. Naphtha crack spreads were negative for all of 2011, which has negatively affected our gross margin for the period.
Domestic Demand
Sales results for our refinery for 2011 indicate that Papua New Guinea’s domestic demand for middle distillates (which includes diesel and jet fuels) from the refinery has increased by approximately 6.4% compared with 2010. However, the total volume of all products sold by us was 7.4 million barrels for fiscal year 2011 compared with 7.5 million barrels in 2010. Total volume of PNG domestic sales only for 2011 was 4.9 million barrels as compared with 4.6 million barrels in 2010.
The refinery on average sold 12,649 bbls per day of refined petroleum products to the domestic market during fiscal year 2011 compared with 11,780 bbls per day in 2010.
Interest Rates
The LIBOR USD overnight rate is the benchmark floating rate used in our midstream working capital facility and therefore accounts for a significant proportion of our interest rate exposure. The LIBOR USD overnight rate remained constant at between 0.2% and 0.3% for 2010 and then reduced to between 0.15% and 0.2% for the majority of 2011. Any rate increases would add additional cost to financing our crude cargoes and vice versa as our BNP Paribas working capital facility is linked to LIBOR rates. See “Liquidity and Capital Resources – Summary of Debt Facilities”.
Exchange Rates
Changes in the PGK to USD exchange rate can affect our Midstream Refinery results as there is a timing difference between the foreign exchange rates utilized when setting the monthly IPP, which is set in PGK, and the foreign exchange rate used to convert the subsequent receipt of PGK proceeds to USD to repay our crude cargo borrowings. The PGK has strengthened against the USD every month during the year ended December 31, 2011 (from 0.3785 to 0.4665).
Changes in the AUD and SGD to USD exchange rate can affect our Corporate results as the expenses of the Corporate offices in Australia and Singapore are incurred in the respective local currencies. The AUD and SGD exposures are minimal currently as funds are transferred to AUD and SGD from USD as required. No material balances are held in AUD or SGD. However, we are exposed to translation risks resulting from AUD and SGD fluctuations as in country costs are being incurred in AUD and SGD and reporting for those costs being in USD. We have entered into AUD to USD foreign currency forward contracts to manage the foreign exchange risk in relation to the expenses to be incurred in AUD.
RISK FACTORS
Our business operations and financial position are subject to a range of risks. A summary of the key risks that may impact upon the matters addressed in this document have been included under section “Forward Looking Statements” above. Detailed risk factors can be found under the heading “Risk Factors” in our 2011 Annual Information Form available atwww.sedar.com.
Management Discussion and Analysis INTEROIL CORPORATION 34 |
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with IFRS requires our management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The effect of changes in estimates on future periods have not been disclosed in the consolidated financial statements as estimating it is impracticable. The following accounting policies involve estimates that are considered critical due to the level of sensitivity and judgment involved, as well as the impact on our consolidated financial position and results of operations. The information about our critical accounting estimates should be read in conjunction with Note 2 of the notes to our consolidated financial statements for the year ended December 31, 2011, available atwww.sedar.com which summarizes our significant accounting policies.
Income Taxes
We use the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the deferred tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date of enactment. In considering the recoverability of deferred tax assets and liabilities, we consider a number of factors, including the consistency of profits generated from the refinery, likelihood of production from Upstream operations to utilize the carried forward exploration costs, etc. If actual results differ from the estimates or we adjust the estimates in future periods, a reduction in our deferred tax assets will result in a corresponding increase in deferred tax expenses.
Oil and Gas Properties
We use the successful-efforts method to account for our oil and gas exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. We continue to carry as an asset the cost of drilling exploratory wells if the required capital expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near future, or when exploration and evaluation activities have not yet reached a stage to allow reasonable assessment regarding the existence of economical reserves. Capitalized costs for producing wells will be subject to depletion using the units-of-production method. Geological and geophysical costs are expensed as incurred. If our plans change or we adjust our estimates in future periods, a reduction in our oil and gas properties asset will result in a corresponding increase in the amount of our exploration expenses.
Asset Retirement Obligations
A liability is recognized for future legal or constructive retirement obligations associated with the Company’s property, plant and equipment. The amount recognized is the net present value of the estimated costs of future dismantlement, site restoration and abandonment of properties based upon current regulations and economic circumstances at period end. During the quarter ended June 30, 2011, Management received the results of an independent assessment of the potential asset retirement obligations of the refinery. As a result of this assessment, Management has recognized an asset retirement obligation at December 31, 2011 of $4,562,269. If we adjust the estimates in future periods, it may result in increased capital expenditures and a corresponding increase in liabilities.
Environmental Remediation
Remediation costs are accrued based on estimates of known environmental remediation exposure. Ongoing environmental compliance costs, including maintenance and monitoring costs, are expensed as incurred. Provisions are determined on an assessment of current costs, current legal requirements and current technology. Changes in estimates are dealt with on a prospective basis. We currently do not have any amounts accrued for environmental remediation obligations as current legislation does not require it. Future legislative action and regulatory initiatives could result in changes to our operating permits which may result in increased capital expenditures and operating costs.
Management Discussion and Analysis INTEROIL CORPORATION 35 |
Impairment of Long-Lived Assets
We are required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas assets, and goodwill for potential impairment. We test long-lived assets for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to earnings. In order to determine fair value, our management must make certain estimates and assumptions including, among other things, an assessment of market conditions (including estimation of gross refining margins, crude price environments and its impact on IPP, etc), projected cash flows, investment rates, interest/equity rates and growth rates, that could significantly impact the fair value of the asset being tested for impairment. Due to the significant subjectivity of the assumptions used to test for recoverability and to determine fair value, changes in market conditions could result in significant impairment charges in the future, thus affecting our earnings. Our impairment evaluations are based on assumptions that are consistent with our business plans.
Legal and Other Contingent Matters
We are required to determine whether a loss is probable based on judgment and interpretation of laws and regulations and whether the loss can reasonably be estimated. When the amount of a contingent loss is determined it is charged to earnings. Our management continually monitors known and potential contingent matters and makes appropriate provisions by charges to earnings when warranted by circumstances.
During the second half of 2011, the PNG Customs Service commenced an audit of our petroleum product imports into Papua New Guinea for the years 2007 to 2010. We received a letter in November 2011 from the then Commissioner of Customs setting out certain findings from the audit. This letter included comments alleging that payment of import GST was required and had not been made on imports of certain refined products. As well as requiring payment of GST, the letter noted that administrative penalties were able to be levied by Customs in the range of 50% to 200% of the assessed amounts as per the PNG Customs Act. We have since met with the Customs Service and provided it with supporting documentation to demonstrate that the GST amounts claimed in their letter have all been paid. We have currently made a provision based on our best estimate in relation to this matter and are working closely with the authority to provide all requested information in order to finalize the audit.
NEW ACCOUNTING STANDARDS
New accounting standards not yet applicable as at December 31, 2011
The following new standards have been issued but are not yet effective for the financial year beginning January 1, 2011 and have not been early adopted:
- | IFRS 9 ‘Financial Instruments’(effective from January 1, 2015): This addresses the classification and measurement of financial assets. The standard is not applicable until January 1, 2013 but is available for early adoption. We have yet to assess IFRS 9’s full impact. We have not yet decided to adopt IFRS 9 early. |
- | IFRS 10 'Consolidated Financial Statements'(effective from January 1, 2013): This builds on existing principles by identifying the concept of control as the determining factor in whether an entity should be included within the consolidated financial statements. The standard provides additional guidance to assist in determining control where this is difficult to assess. This new standard might impact the entities that a group consolidates as its subsidiaries. We have yet to assess IFRS 10’s full impact. |
Management Discussion and Analysis INTEROIL CORPORATION 36 |
- | IFRS 11 'Joint Arrangements' (effective from January 1, 2013): This provides for a more realistic reflection of joint arrangements by focusing on the rights and obligations of the arrangement, rather than its legal form. There are two types of joint arrangements: joint operations and joint ventures. Joint operations arise where a joint operator has rights to the assets and obligations relating to the arrangement and hence accounts for its interest in assets, liabilities, revenue and expenses. Joint ventures arise where the joint operator has rights to the net assets of the arrangement and hence equity accounts for its interest. Proportional consolidation of joint ventures is no longer allowed. We have yet to assess IFRS 11’s full impact. |
- | IFRS 12 'Disclosure of Interests in Other Entities'(effective from January 1, 2013): This standard is a new standard on disclosure requirements for all forms of interests in other entities, including joint arrangements, associates, special purpose vehicles and other off balance sheet vehicles. We have yet to assess IFRS 12’s full impact. |
- | IFRS 13 ‘Fair Value Measurement’(effective from January 1, 2013): This aims to improve consistency and reduce complexity by providing a precise definition of fair value and a single source of fair value measurement and disclosure requirements for use across IFRS. We have yet to assess IFRS 13’s full impact. |
- | IAS 27 ‘Separate Financial Statements’(effective from January 1, 2013): This includes the provisions on separate financial statements that are left after the control provisions of IAS 27 have been included in the new IFRS 10. We have yet to assess IAS 27’s full impact. |
- | IAS 28 ‘Investments in Associates and Joint Ventures’(effective from January 1, 2013): This now includes the requirements for joint ventures, as well as associates, to be equity accounted following the issue of IFRS 11. We have yet to assess IAS 28’s full impact. |
- | IAS 1 ‘Presentation of financial statements’(amendment): The IASB has issued an amendment to IAS 1, which changes the disclosure of items presented in other comprehensive income (OCI) in the statement of comprehensive income. The IASB originally proposed that all entities should present profit or loss and OCI together in a single statement of comprehensive income. The proposal has been withdrawn and IAS 1 will still permit profit or loss and OCI to be presented in either a single statement or in two consecutive statements. The amendment was developed jointly with the FASB, which has removed the option in US generally accepted accounting principles to present OCI in the statement of changes in equity. The amendment is effective for annual periods starting on or after July 1, 2012, subject to EU endorsement. This amendment will not have any material impact on our financial statements. |
Changeover to International Financial Reporting Standards
The AcSB adopted IFRS as issued by IASB as GAAP, effective January 1, 2011, with a transition date of January 1, 2010. We have adopted IFRS and have prepared our financial statements for the year ended December 31, 2011 in accordance with IFRS and restated our financial statements for the year ended December 31, 2010 to comply with IFRS. The financial information contained in this MD&A that relates to periods prior to January 1, 2010 has been prepared under our previous GAAP and has not been restated.
(i) Application of IFRS 1:
Our financial statements for the year ended December 31, 2011, are the first annual financial statements prepared in compliance with IFRS. We have applied IFRS 1 in preparing the consolidated financial statements for the year ended December 31, 2011.
Our transition date to IFRS was January 1, 2010 and we have prepared our opening IFRS balance sheet at that date. In preparing the consolidated financial statements for the year ended December 31, 2011 in accordance with IFRS 1, we have applied the relevant mandatory exceptions and certain optional exemptions from full retrospective application of IFRS.
Management Discussion and Analysis INTEROIL CORPORATION 37 |
(ii) Exemptions from full retrospective application – elected by the Company
We have elected to apply the following optional exemptions from full retrospective application.
- | Business combinations exemption:A first-time adopter may elect not to apply IFRS 3 - ‘Business Combinations’ (as revised in 2008) retrospectively to past business combinations (business combinations that occurred before the date of transition to IFRS). However, if a first-time adopter restates any business combination to comply with IFRS 3 (as revised in 2008), it shall restate all later business combinations and shall also apply IAS 27 (as amended in 2008) from that same date. We have made the election not to apply IFRS 3 retrospectively to past business combinations. |
- | Fair value as deemed cost exemption:An entity may elect to measure an item of property, plant and equipment at the date of transition to IFRS at its fair value and use that fair value as its deemed cost at that date. We have made the election not to revalue our property, plant and equipment to fair value or deemed cost. Historical cost will be maintained as plant and equipment cost base on transition. |
- | Cumulative translation differences exemption:Consistent with the previous GAAP treatment in prior periods, IAS 21 requires an entity: (a) to recognize some translation differences in other comprehensive income and accumulate these in a separate component of equity; and (b) on disposal of a foreign operation, to reclassify the cumulative translation difference for that foreign operation (including, if applicable, gains and losses on related hedges) from equity to profit or loss as part of the gain or loss on disposal. An election can be made to be exempted from this requirement on transition and start with 'zero' translation differences. We have not made the election to restate our cumulative translation differences balance to zero, and have elected to continue with the current translation differences in comprehensive income as these are already in compliance with IAS 21. |
- | Oil and Gas assets exemption:Oil and Gas industry specific accounting under IFRS or previous GAAP is currently not as comprehensive as the guidance provided under U.S. generally accepted accounting principles accounting for industry specific oil and gas transactions. Paragraph D8A of IFRS 1 provides an exemption in relation to Oil and Gas assets by allowing companies to continue using the same policies as used under the previous GAAP and carrying forward the carrying amounts of the Oil and Gas assets under GAAP into IFRS. We have availed this exemption and elected to maintain our Oil and Gas assets at carrying amount under GAAP treatment in prior periods, which will be the deemed cost under IFRS. |
- | Interests in joint ventures entities exemption:Superseded CICA Section 3055 differs from IAS 31 as IAS 31 permits the use of either the proportionate consolidation method or the equity method to account for joint venture entities. IAS 31 recommends the use of proportionate consolidation as it better reflects the substance and economic reality, however, it does permit the use of equity method. Superseded CICA Section 3055 only allows the use of proportionate consolidation method to account for joint venture entities. We have elected to maintain our joint venture accounting under the proportionate consolidation model for both our incorporated and unincorporated joint venture interests. |
The remaining optional exemptions are not applicable to us.
(iii) Exceptions from full retrospective application followed by the Company
All mandatory exceptions in IFRS 1 were not applicable because there were no significant differences in management’s application of GAAP in these areas.
Impact of adoption of IFRS on financial reporting
Following a review of the IFRS, there were two IFRS adjustments to the opening January 1, 2010 balance sheet:
a) In relation to the deferred gain on contributions to the LNG Project recorded on our balance sheet, under IFRS, we were required to offset these deferred gains against any underlying assets that are carried in relation to these deferred gains. Based on this guidance, we have offset the deferred gains against deferred LNG project costs carried within the plant and equipment in the balance sheet under the Midstream – Liquefaction segment. For further details, please refer to Note 3(b) in the Condensed Consolidated Financial Statements for the year ended December 31, 2011.
Management Discussion and Analysis INTEROIL CORPORATION 38 |
b) In accordance with guidance under IFRS, deferred tax assets have been recognized for temporary differences that arise on translation of the nonmonetary assets held by Midstream refining operations that are translated from the functional currency of the tax return (PGK) to the reporting currency (USD) using period end rates. Previously under GAAP, these temporary differences in relation to functional currency translation of nonmonetary assets were specifically disallowed from recognition.
Other than the transition adjustments affecting the consolidated balance sheets, consolidated income statements, consolidated statements of comprehensive income and consolidated statements of changes in equity as noted above, there were no transition differences noted in relation to consolidated statement of cash flows.
NON-GAAP MEASURES AND RECONCILIATION
Non-GAAP measures, including gross margin and EBITDA, included in this MD&A are not defined nor have a standardized meaning prescribed by IFRS or our previous GAAP; accordingly, they may not be comparable to similar measures provided by other issuers. Gross margin is a non-GAAP measure and is “sales and operating revenues” less “cost of sales and operating expenses”. The following table reconciles sales and operating revenues, a GAAP measure, to Gross margin:
Consolidated – Operating results | Year ended December 31, | |||||||||||
($ thousands) | 2011 | 2010 | 2009(2) | |||||||||
Midstream – Refining | 939,278 | 674,137 | 574,409 | |||||||||
Downstream | 743,860 | 504,786 | 388,991 | |||||||||
Corporate | 14,125 | 402 | 21,194 | |||||||||
Consolidation Entries | (590,729 | ) | (376,951 | ) | (296,115 | ) | ||||||
Sales and operating revenues | 1,106,534 | 802,374 | 688,479 | |||||||||
Midstream – Refining | (897,825 | ) | (605,603 | ) | (516,349 | ) | ||||||
Downstream | (704,213 | ) | (470,772 | ) | (359,623 | ) | ||||||
Corporate(1) | (11,421 | ) | - | - | ||||||||
Consolidation Entries | 592,527 | 374,818 | 273,989 | |||||||||
Cost of sales and operating expenses | (1,020,932 | ) | (701,557 | ) | (601,983 | ) | ||||||
Midstream – Refining | 41,453 | 68,534 | 58,060 | |||||||||
Downstream | 39,647 | 34,014 | 29,368 | |||||||||
Corporate(1) | 2,704 | 402 | 21,194 | |||||||||
Consolidation Entries | 1,798 | (2,133 | ) | (22,126 | ) | |||||||
Gross Margin | 85,602 | 100,817 | 86,496 |
(1) Corporate expenses are classified below the gross margin line and mainly relates to ‘Office and admin and other expenses’ and ‘Interest expense’.
(2) The 2009 financial information was prepared in accordance with the Company’s former GAAP, and has not been restated in accordance with IFRS.
Management Discussion and Analysis INTEROIL CORPORATION 39 |
EBITDA represents our net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is used by us to analyze operating performance. EBITDA does not have a standardized meaning prescribed by GAAP (i.e., IFRS) and, therefore, may not be comparable with the calculation of similar measures for other companies. The items excluded from EBITDA are significant in assessing our operating results. Therefore, EBITDA should not be considered in isolation or as an alternative to net earnings, operating profit, net cash provided from operating activities and other measures of financial performance prepared in accordance with IFRS. Further, EBITDA is not a measure of cash flow under IFRS and should not be considered as such. For reconciliation of EBITDA to the net income (loss) under IFRS, refer to the following table.
The following table reconciles net income (loss), a GAAP measure, to EBITDA, a non-GAAP measure for each of the last eight quarters. Our IFRS transition date was January 1, 2010 and as such, the 2010 comparative information has been restated in accordance with IFRS.
Quarters ended | 2011 | 2010 | ||||||||||||||||||||||||||||||
($ thousands) | Dec-31 | Sep-31 | Jun-30 | Mar-31 | Dec-31 | Sep-30 | Jun-30 | Mar-31 | ||||||||||||||||||||||||
Upstream | 665 | (6,169 | ) | 593 | (10,957 | ) | (41,681 | ) | (11,753 | ) | (3,498 | ) | (1,964 | ) | ||||||||||||||||||
Midstream – Refining | 2,604 | 3,461 | 27,967 | 26,632 | 13,780 | 15,785 | 16,962 | 4,402 | ||||||||||||||||||||||||
Midstream – Liquefaction | (4,123 | ) | (3,602 | ) | (4,035 | ) | (2,375 | ) | (1,959 | ) | (4,588 | ) | (3 | ) | (563 | ) | ||||||||||||||||
Downstream | 6,808 | 3,570 | 5,777 | 8,744 | 4,709 | 1,674 | 7,060 | 4,492 | ||||||||||||||||||||||||
Corporate | 10,134 | 1,548 | 13,940 | 5,223 | 4,566 | (4,510 | ) | 1,751 | 4,402 | |||||||||||||||||||||||
Consolidation Entries | (11,280 | ) | (10,263 | ) | (5,270 | ) | (9,200 | ) | (7,004 | ) | (5,229 | ) | (7,384 | ) | (5,911 | ) | ||||||||||||||||
Earnings before interest, taxes, depreciation and amortization | 4,808 | (11,455 | ) | 38,972 | 18,067 | (27,589 | ) | (8,621 | ) | 14,888 | 4,858 | |||||||||||||||||||||
Subtract: | ||||||||||||||||||||||||||||||||
Upstream | (8,712 | ) | (7,806 | ) | (7,142 | ) | (6,352 | ) | (5,481 | ) | (4,600 | ) | (4,367 | ) | (4,081 | ) | ||||||||||||||||
Midstream – Refining | (3,285 | ) | (2,494 | ) | (2,211 | ) | (1,675 | ) | (1,509 | ) | (1,693 | ) | (1,651 | ) | (1,731 | ) | ||||||||||||||||
Midstream – Liquefaction | (445 | ) | (372 | ) | (268 | ) | (223 | ) | (184 | ) | (376 | ) | (351 | ) | (342 | ) | ||||||||||||||||
Downstream | (1,170 | ) | (1,233 | ) | (1,116 | ) | (826 | ) | (835 | ) | (938 | ) | (1,167 | ) | (800 | ) | ||||||||||||||||
Corporate | (1,498 | ) | (1,477 | ) | (1,641 | ) | (1,395 | ) | (1,158 | ) | (342 | ) | (20 | ) | (20 | ) | ||||||||||||||||
Consolidation Entries | 11,500 | 10,041 | 8,894 | 7,572 | 6,571 | 6,107 | 5,917 | 5,688 | ||||||||||||||||||||||||
Interest expense | (3,610 | ) | (3,341 | ) | (3,484 | ) | (2,899 | ) | (2,596 | ) | (1,842 | ) | (1,639 | ) | (1,286 | ) | ||||||||||||||||
Upstream | 0 | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Midstream – Refining | 19,243 | 678 | (5,677 | ) | (7,298 | ) | (65 | ) | 101 | (366 | ) | (173 | ) | |||||||||||||||||||
Midstream – Liquefaction | 0 | - | - | - | 36 | - | - | - | ||||||||||||||||||||||||
Downstream | (595 | ) | (297 | ) | (1,449 | ) | (2,623 | ) | (495 | ) | (322 | ) | (1,524 | ) | (2,360 | ) | ||||||||||||||||
Corporate | (493 | ) | (195 | ) | (629 | ) | 71 | (11 | ) | (529 | ) | 97 | (797 | ) | ||||||||||||||||||
Consolidation Entries | 0 | 0 | 0 | - | (2 | ) | (2 | ) | (1 | ) | - | |||||||||||||||||||||
Income taxes | 18,155 | 186 | (7,755 | ) | (9,850 | ) | (537 | ) | (752 | ) | (1,794 | ) | (3,330 | ) | ||||||||||||||||||
Upstream | (1,355 | ) | (1,105 | ) | (154 | ) | (641 | ) | (683 | ) | (232 | ) | (78 | ) | (138 | ) | ||||||||||||||||
Midstream – Refining | (2,878 | ) | (2,846 | ) | (2,764 | ) | (2,765 | ) | (2,700 | ) | (2,195 | ) | (2,888 | ) | (2,571 | ) | ||||||||||||||||
Midstream – Liquefaction | (6 | ) | (6 | ) | (6 | ) | (6 | ) | (7 | ) | (6 | ) | (6 | ) | (6 | ) | ||||||||||||||||
Downstream | (1,422 | ) | (894 | ) | (906 | ) | (804 | ) | (737 | ) | (739 | ) | (651 | ) | (660 | ) | ||||||||||||||||
Corporate | (527 | ) | (349 | ) | (395 | ) | (435 | ) | (16 | ) | (17 | ) | (32 | ) | (41 | ) | ||||||||||||||||
Consolidation Entries | 32 | 32 | 32 | 32 | 33 | 32 | 33 | 32 | ||||||||||||||||||||||||
Depreciation and amortisation | (6,156 | ) | (5,168 | ) | (4,193 | ) | (4,619 | ) | (4,110 | ) | (3,157 | ) | (3,622 | ) | (3,384 | ) | ||||||||||||||||
Upstream | (9,402 | ) | (15,080 | ) | (6,703 | ) | (17,949 | ) | (47,845 | ) | (16,585 | ) | (7,943 | ) | (6,182 | ) | ||||||||||||||||
Midstream – Refining | 15,684 | (1,201 | ) | 17,314 | 14,894 | 9,504 | 11,998 | 12,056 | (74 | ) | ||||||||||||||||||||||
Midstream – Liquefaction | (4,574 | ) | (3,980 | ) | (4,309 | ) | (2,604 | ) | (2,114 | ) | (4,970 | ) | (360 | ) | (911 | ) | ||||||||||||||||
Downstream | 3,621 | 1,146 | 2,306 | 4,491 | 2,643 | (325 | ) | 3,719 | 671 | |||||||||||||||||||||||
Corporate | 7,616 | (473 | ) | 11,275 | 3,463 | 3,381 | (5,398 | ) | 1,796 | 3,544 | ||||||||||||||||||||||
Consolidation Entries | 252 | (190 | ) | 3,657 | (1,596 | ) | (401 | ) | 908 | (1,435 | ) | (190 | ) | |||||||||||||||||||
Net profit/(loss) per segment | 13,197 | (19,778 | ) | 23,540 | 699 | (34,832 | ) | (14,372 | ) | 7,833 | (3,142 | ) |
Management Discussion and Analysis INTEROIL CORPORATION 40 |
PUBLIC SECURITIES FILINGS
You may access additional information about us, including our 2011 Annual Information Form, in documents filed with the Canadian Securities Administrators atwww.sedar.com, and in documents, including our Form 40-F, filed with the U.S. Securities and Exchange Commission atwww.sec.gov. Additional information is also available on our websitewww.interoil.com.
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING
Our certifying officers have designed disclosure controls and procedures, as such term is defined in National Instrument 52-109 - Certification of Disclosure in Issuer’s Annual and Interim Filings ("National Instrument 52-109"), or caused them to be designed under their supervision. As of December 31, 2011, our Chief Executive Officer (“CEO") and our Chief Financial Officer (“CFO”) carried out an internal evaluation of the effectiveness of our disclosure controls and procedures. Based on that evaluation, our CEO and CFO concluded that the disclosure controls and procedures provide reasonable assurance that all material information relating to us is made known to us by others and all information required to be disclosed in our annual and interim filings is recorded, processed, summarized and reported within the time periods specified in applicable Canadian securities legislation. Our CEO and CFO are responsible for establishing and maintaining internal control over financing reporting ("ICFR"), as such term is defined in National Instrument 52-109. The control framework the CEO and CFO used to design the Company's ICFR is the framework established by the Committee of Sponsoring Organizations entitled – Internals Controls – Integrated Framework (the “COSO Framework”).
Under the supervision of the CEO and the CFO, the Company conducted an evaluation of the effectiveness of our ICFR as at December 31, 2011 based on the COSO Framework. Based on this evaluation, they concluded that as of December 31, 2011, our ICFR provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS.
Effective April 26, 2011, we migrated our downstream segment to the new ERP system, Microsoft Dynamics AX, to complete the roll out of the system implementation which started during 2010 financial year. In addition to the MS Dynamics AX, the downstream segment also implemented MS Dynamics NAV, fuel distribution system to process sales orders and manages inventory and warehousing. This migration has effectively completed the ERP system implementation resulting in all our business segments running on a single ERP platform.
Management has reviewed the internal controls over financial reporting affected by the implementation of the new ERP System and made appropriate changes to internal controls as part of the implementation. Following the implementation, these new controls were evaluated and tested according to our established processes. Based on this evaluation, we believe that we have designed adequate and appropriate internal control over financial reporting to ensure that the financial statements were materially accurate for the year ended December 31, 2011.
During the year ended December 31, 2011, there has been no other change in our internal control over financial reporting that has materially affected, or is reasonably likely to affect, our internal control over financial reporting, other than as noted above.
GLOSSARY OF TERMS
"2011 Annual Information Form"means the Annual Information Form for the year ended December 31, 2011.
"AUD"means Australian dollars.
"Barrel, Bbl" (petroleum)Unit volume measurement used for petroleum and its products.
Management Discussion and Analysis INTEROIL CORPORATION 41 |
"BNP Paribas" means BNP Paribas Capital (Singapore) Limited.
“Board”means the board of directors of InterOil.
"BSP"means Bank of South Pacific Limited.
“CDU” means crude distillation unit.
“CGR”means condensate to gas ratio.
"Condensate"A component of natural gas which is a liquid at surface conditions.
“Convertible notes”means the 2.75% convertible senior notes of InterOil due November 15, 2015.
“Crack spread” The simultaneous purchase or sale of crude against the sale or purchase of refined petroleum products. These spread differentials which represent refining margins are normally quoted in dollars per barrel by converting the product prices into dollars per barrel and subtracting the crude price.
“CRU”means catalytic reformer unit.
“Crude oil” A mixture consisting mainly of pentanes and heavier hydrocarbons that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain small amounts of sulfur and other non-hydrocarbons but does not include liquids obtained from the processing of natural gas.
“CSP Joint Venture” or “CSP JV” means the Joint Venture Operating Agreement (“JVOA”) entered into for the proposed condensate stripping facilities with Mitsui or the joint venture formed to develop and operate the proposed condensate stripping facilities as the context requires.
"Condensate Stripping Project"means the proposed condensate stripping facilities, including gathering and condensate pipeline, condensate storage and associated facilities being progressed in joint venture with Mitsui.
“DST”refers to a drill stem test and is a procedure for isolating and testing the surrounding geological formation through the drill pipe.
“EBITDA”EBITDA represents net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is a non-GAAP measure used to analyze operating performance. See“Non-GAAP Measures and Reconciliation”.
"ERP"means Enterprise Resource Planning System.
“EWC”means Energy World Corporation Limited., a company organized under the laws of Australia.
“FEED”means front end engineering and design.
“Feedstock”means raw material used in a refinery or other processing plant.
“FID”means final investment decision. Such a decision is ordinarily the point at which a decision is made to proceed with a project and it becomes unconditional. However, in some instances the decision may be qualified by certain conditions, including being subject to necessary approvals by the State.
“FLEX LNG” means FLEX LNG Limited, a British Virgin Islands Company listed on the Oslo Stock Exchange.
"GAAP"means Canadian generally accepted accounting principles.
“Gas”means a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs but are gaseous at atmospheric conditions. Natural gas may contain sulfur or other non-hydrocarbon compounds.
Management Discussion and Analysis INTEROIL CORPORATION 42 |
“ICCC”means Papua New Guinea’s competition authority, the Independent Consumer and Competition Commission.
“IFRS” means International Financial Reporting Standards as issued by the International Accounting Standards Board.
“IPI Agreement” means the Amended and Restated Indirect Participation Agreement dated February 25, 2005, as amended.
“IPI holders” means investors holding IPWIs in certain exploration wells required to be drilled pursuant to the IPI Agreement.
“IPP”means import parity price. For each refined product produced and sold locally in Papua New Guinea, IPP is calculated under agreement with the State by adding the costs that would typically be incurred to import such product to an average posted price for such product in Singapore as reported by Platts. The costs added to the reported Platts price include freight costs, insurance costs, landing charges, losses incurred in the transportation of refined products, demurrage and taxes.
“IPWI”means indirect participation working interest.
"LIBOR"means daily reference rate based on the interest rates at which banks borrow unsecured funds from banks in the London wholesale money market.
“LNG”means liquefied natural gas. Natural gas may be converted to a liquid state by pressure and severe cooling for transportation purposes, and then returned to a gaseous state to be used as fuel. LNG, which is predominantly artificially liquefied methane, is not to be confused with NGLs, natural gas liquids, which are heavier fractions that occur naturally as liquids.
“LNGL”means Liquid Niugini Gas Limited, a wholly owned subsidiary of PNG LNG formed in Papua New Guinea to contract with the State and pursue the LNG Project, including construction of the proposed liquefaction facilities.
“LNG Project” means the development by us of liquefaction facilities in the Gulf Province of Papua New Guinea described as our Midstream Liquefaction business segment and being undertaken as a joint venture with Pac LNG and with other potential partners, including the State.
“LNG Project Agreement”means the LNG Project Agreement between the State and LNGL dated December 23, 2009.
“LSWR”means low sulfur waxy residue.
“Mitsui”refers to Mitsui & Co., Ltd., a company organized under the laws of Japan and/or certain of its wholly-owned subsidiaries (as the context requires).
"Mtpa"means million tonnes per annum.
“Naphtha”That portion of the distillate obtained from the refinement of petroleum which is an intermediate between the lighter gasoline and the heavier benzene. It is a feedstock destined either for the petrochemical industry or for gasoline production by reforming or isomerisation within a refinery.
“Natural gas” means a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth's surface, often in association with petroleum. The principal constituent is methane.
“OPIC”meansOverseas Private Investment Corporation, an agency of the United States Government.
Management Discussion and Analysis INTEROIL CORPORATION 43 |
“Pac LNG” means Pacific LNG Operations Ltd., a company incorporated in the Bahamas and affiliated with Clarion Finanz A.G. This company is our joint venture partner in the LNG Project (holding equal voting shares in PNG LNG), holds a 2.5% direct interest in the Elk and Antelope fields, is an IPI holder and a shareholder in PNGDV.
“PDL”meansPetroleum Development License. The right granted by the State to develop a field for commercial production.
“Petromin”means Petromin PNG Holdings Limited, a company incorporated in Papua New Guinea by the State.
“PGK”means the Kina, currency of Papua New Guinea.
“PNGDV”meansPNG Drilling Ventures Limited,an entity with which we entered into an indirect participation agreement in May 2003, as amended.
"PNG LNG" means PNG LNG, Inc., a joint venture company established in 2007 to hold the interests of certain joint venturers in the venture to construct the proposed liquefaction facilities. Shareholders are InterOil LNG Holdings Inc., a wholly-owned subsidiary of InterOil, and Pac LNG.
“PPL”means Petroleum Prospecting License. The tenement given by the State to explore for oil and gas.
“PRL”means Petroleum Retention License. The tenement given by the State to allow the license holder to evaluate the commercial and technical options for the potential development of an oil and/or gas field.
"Samsung Heavy Industries"means Samsung Heavy Industries Co., Ltd., a corporation incorporated and existing under the laws of the Republic of Korea.
"SGD"means Singapore Dollars.
“State”or“PNG”means the Independent State of Papua New Guinea.
"USD"means United States Dollars.
"Westpac"means Westpac Bank PNG Limited.
Management Discussion and Analysis INTEROIL CORPORATION 44 |