Exhibit 99.2
Harvest Natural Resources, Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Restatement
As discussed in Exhibit 99.3 of this Current Report on Form 8-K under the captionNotes to Consolidated Financial Statements, Note 1 — Organization and Summary of Significant Accounting Policies — RestatementandExhibits and Financial Statement Schedules, Quarterly Financial Data (unaudited), we are restating our historical financial statements for the year ended December 31, 2007 and quarterly information for the quarters ended December 31, 2007, March 31, 2008, June 30, 2008 and September 30, 2008. The restatements relate to the correction of an error in the deferred tax adjustment to reconcile our share of Petrodelta’s Net Income reported under IFRS to that required under GAAP and recorded within Net income from unconsolidated equity affiliates. We are presenting this restatement herein.
The adjustment to record our share of Petrodelta’s Net Income under GAAP should have been limited to deferred tax adjustments related to non-monetary temporary differences impacted by inflationary adjustments under Venezuela law. During the 2008 year end close process, we determined that restatements were necessary because since October 1, 2007 both the monetary and non-monetary temporary differences recorded in Petrodelta’s IFRS financial statements had been adjusted in arriving at our GAAP consolidated financial statements rather than only the non-monetary temporary differences impacted by inflationary adjustments. Accordingly, we had understated our Net income from unconsolidated equity affiliates and Investment in equity affiliates.
The following tables set forth the effect of the adjustments described above on the consolidated statement of operations for the year ended December 31, 2007 and for the consolidated balance sheet as of December 31, 2007. There was no impact on net cash used in operating activities in the consolidated statements of cash flows.
Consolidated Statements of Operations
| December 31, 2007 | ||||||||||||
| As Previously | ||||||||||||
| Reported | Adjustment | As Restated | ||||||||||
| (in thousands, except per share data) | ||||||||||||
| Income from Consolidated Companies Before Income Taxes | $ | 30,914 | $ | — | $ | 30,914 | ||||||
| Income Tax Expense | 6,312 | — | 6,312 | |||||||||
| Income from Consolidated Companies | 24,602 | — | 24,602 | |||||||||
| Net Income from Unconsolidated Equity Affiliates | 51,695 | 3,602 | 55,297 | |||||||||
| Net Income | 76,297 | 3,602 | 79,899 | |||||||||
| Less: Net Income Attributable to Noncontrolling Interest | 19,060 | 721 | 19,781 | |||||||||
| Net Income Attributable to Harvest | $ | 57,237 | $ | 2,881 | $ | 60,118 | ||||||
| Net Income Attributable to Harvest Per Common Share: | ||||||||||||
| Basic | $ | 1.57 | $ | 0.08 | $ | 1.65 | ||||||
| Diluted | $ | 1.51 | $ | 0.08 | $ | 1.59 | ||||||
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Consolidated Balance Sheets
| December 31, 2007 | ||||||||||||
| As Previously | ||||||||||||
| Reported | Adjustment | As Restated | ||||||||||
| (in thousands) | ||||||||||||
| Investment in Equity Affiliates | $ | 251,173 | $ | 3,602 | $ | 254,775 | ||||||
| Total Assets | 413,469 | 3,602 | 417,071 | |||||||||
| Retained Earnings | 147,934 | 2,881 | 150,815 | |||||||||
| Total Harvest Shareholders’ Equity | 313,766 | 2,881 | 316,647 | |||||||||
| Noncontrolling Interest | 56,825 | 721 | 57,546 | |||||||||
| Total Equity | 370,591 | 3,602 | 374,193 | |||||||||
| Total Liabilities and Equity | 413,469 | 3,602 | 417,071 | |||||||||
Operations
We had a loss attributable to Harvest of $21.5 million, or $0.63 per diluted share, for the twelve months ended December 31, 2008 compared to earnings attributable to Harvest of $60.1 million, or $1.59 per diluted share, for 2007. Net loss attributable to Harvest for the year ended December 31, 2008 includes $16.4 million of exploration expense, $10.8 million of dry hole expense and the net equity income from Petrodelta’s operations of $35.9 million. Net income attributable to Harvest for the year ended December 31, 2007 includes the net equity income from Petrodelta’s operations from April 1, 2006 through December 31, 2007 of $55.7 million, and gains from the exchange of financial securities of $49.6 million.
Petrodelta — Venezuela
During 2008, Petrodelta drilled and completed eight successful development wells and suspended one well due to problems with the well, produced approximately 5.5 million barrels of oil and sold 10.7 billion cubic feet (BCF) of natural gas. Petrodelta has been advised by the Venezuelan government that the 2009 production objective will be approximately 16,000 barrels of oil per day effective January 1, 2009, following the December 17, 2008 OPEC meeting establishing new production quotas. Petrodelta’s production output for the first quarter of 2009 is projected to be 18,000 barrels per day to comply with the Venezuelan government’s market allocations of the OPEC quota for the country.
Petrodelta shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. The management and board of Petrodelta have taken actions to reduce both operating and capital expenditures. Currently, Petrodelta has two drilling rigs operating in the Uracoa field and one drilling rig in the Temblador field and has released three additional drilling rigs. For 2009, the initial drilling program includes utilizing two rigs to drill development and appraisal wells for both maintaining production capacity and appraising the substantial resource bases in the presently non-producing Isleño and El Salto fields. Petrodelta’s results and operating information is more fully described in Exhibit 99.3 of this Current Report on Form 8-K under the captionNotes to the Consolidated Financial Statements, Note 7 — Investment in Equity Affiliates — Petrodelta, S.A.
Diversification
Beginning in 2005, we recognized the need to diversify our asset base as part of our strategy. We broadened our strategy from our primary focus on Venezuela to identify, access and integrate hydrocarbon assets to include organic growth through exploration in basins globally with proven hydrocarbon systems. We seek to leverage our Venezuelan experience as well as our recently expanded business development and technical platform to create a diversified resource base. With the addition of technical resources, opening of our London office, the 2008 opening of our Singapore office, as well as our noncontrolling equity investment in Fusion, we have made significant investments to provide the necessary foundation and global reach required for an organic growth focus. Our organic growth is focused on undeveloped or underdeveloped fields, field redevelopments and exploration. While exploration will become a larger part of our overall portfolio, we will generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles. Exploration will be technically driven with a low entry cost and high resource potential that provides sustainable growth. We will continue to seek opportunities
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where perceived geopolitical risk may provide high reward opportunities in the long term. Our exploration expense increased due to a project screening effort which culminated in the opening of our Singapore office and the increase in staff to manage our new United States activities. In 2008, we acquired very attractive exploration assets in Gabon, Indonesia and the United States that fit our strategy.
United States
In March 2008, we executed an AMI agreement with a private third party for an area in the upper Gulf Coast Region of the United States. We are the operator and have an initial working interest of 55 percent in the AMI. The AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana, including state waters. The private third party contributed two prospects, including the leases and proprietary 3-D seismic data sets, and numerous leads generated over the last three decades of regional geological focus. We will fund the first $20 million of new lease acquisitions, geological and geophysical studies, seismic reprocessing and drilling costs. The parties focused on two initial prospects for evaluation and completed essentially all leasing of each prospect area during 2008. The other party is obligated to evaluate and present additional opportunities at their sole cost. As each prospect is accepted it will be covered by the AMI. At year end 2008, we have met $16.4 million of the total $20 million funding obligation under the terms of the AMI. After the remainder of the $20 million funding obligation is met, all subsequent costs will be shared by the parties in proportion to their working interests as defined in the AMI agreement.
In September 2008, we spud an exploratory well on the Starks prospect, the first prospect in the Gulf Coast AMI, in Calcasieu Parish, Louisiana. The Harvest Hunter #1 well was drilled to a depth of 12,290 feet and three prospective reservoir horizons were tested. On January 9, 2009, the well was determined to not have commercial quantities of hydrocarbons and was plugged and abandoned. Through December 31, 2008, $10.8 million was expended for the drilling of the well which was written off to dry hole costs as of December 31, 2008.
During the year ended December 31, 2008, operational activities in the West Bay prospect, the second exploratory prospect in the AMI, included re-processing of 3-D seismic, site surveying, and preparation of preliminary engineering documents. On December 8, 2008, we submitted an Application to Install Structures to Drill and Produce Oil and Gas with the U. S. Army Corps of Engineers — Galveston District. At December 31, 2008, the permit application was under review by the Corps of Engineers. Drilling is expected to commence upon receipt of the requisite permit from the Corps of Engineers, which we expect to obtain in late 2009 or early 2010. During the year ended December 31, 2008, we incurred $5.4 million for land acquisition, seismic, surveying and permitting. The expected budget for this project in 2009 is $0.5 million.
In October 2007, we entered into the JEDA with a private party to pursue a lease acquisition program and drilling program on the Antelope project in the Western United States. We are the operator and have a working interest of 50 percent in the project. The other party is obligated to assemble the lease position on the project. We will earn our 50 percent working interest in the project by compensating the other party for leases acquired in accordance with terms defined in the JEDA, and by drilling one deep natural gas test well at our sole expense. The Antelope project is targeted to explore for and develop oil and natural gas from multiple reservoir horizons in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties. Leads and/or prospects have been identified in three prospective reservoir horizons in preparation for anticipated drilling of one or more prospects in 2009. Operational activities during 2008 on the Antelope project were focused primarily on leasing. In addition to leasing activities, other operational activities during 2008 were focused on preparations for anticipated drilling in 2009. We opened a small field office and hired two employees in Roosevelt, Utah in September 2008 to support field activities. Other activities included surveying, preliminary engineering, and preparations for permitting. In December 2008, we filed Applications for Permits to Drill eight shallow oil wells with the State of Utah Department of Natural Resources Division of Oil, Gas, and Mining. The permit applications were still being processed as of February 27, 2009. The cost of the eight shallow oil wells will be borne 50 percent by us and 50 percent by the other party participating in the project. Drilling of the shallow oil wells will not materially contribute to meeting our lease earning obligation under the Agreement. Through December 31, 2008, we have incurred $8.4 million for lease acquisition and permitting. The projected 2009 budget for leasehold acquisition and exploratory drilling is $18.3 million.
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Budong-Budong Project, Indonesia
In November 2008, we opened a small field office in Jakarta, Indonesia and hired four employees to support field activities. In December 2008, the acquisition program of 650 kilometers of 2-D seismic was completed. The data is currently being processed. Interpretation of the data and well planning will take place in the first quarter of 2009. It is expected that the first of two exploration wells will spud in the second half of 2009. In accordance with the farm-in agreement, we expect to fund 100 percent of the well expenditures to earn our 47 percent working interest up to a cap of $10.7 million; thereafter, we will pay in proportion to our working interest. During the year ended December 31, 2008, we incurred $7.7 million including the carry obligation for the 2-D seismic acquisition and other costs. The projected 2009 project expenditures (net to us including our funding commitment) for the exploratory well drilling are $8.1 million.
Dussafu Project — Gabon
In October 2008, the acquisition of 650 kilometers of 2-D seismic was completed which is now being processed to define the syn-rift potential similar to the Lucina and M’Baya fields. In addition, during the three months ended December 31, 2008, we commenced the reprocessing of 1,076 square kilometers of existing 3-D seismic to define the sub-salt structure to unlock the potential of the Gamba play that is producing in the Etame field to the north. We expect the seismic to mature the prospect inventory to make a decision in 2009 for a well in 2010. During the year ended December 31, 2008, we incurred $8.8 million for acreage acquisition and exploration activity. The projected 2009 project expenditures (net to our working interest) for exploration activities are $2.2 million. This includes $1.8 million of well planning and long-lead well items if the decision is made to drill a well.
Other Exploration Projects
Relating to other projects, we incurred $2.7 million during the year ended December 31, 2008. We have budgeted to spend $2.0 million in leasehold acquisition costs, $4.5 million in seismic acquisition and processing costs, $2.8 million on other project related costs in 2009 and $0.4 million in office and computer systems.
Either one of the two exploratory wells to be drilled in 2009 on the Antelope project and the Budong PSC can have a significant impact on our ability to obtain financing, record reserves and generate cash flow in 2010 and beyond.
InItem 1 — BusinessandItem 1A — Risk Factorsin our most recent Annual Report on Form 10-K,we discuss the situation in Venezuela and how the actions of the Venezuelan government have and continue to adversely affect our operations. The recent precipitous drop in oil crude oil prices and the expectation that dividends from Petrodelta will be minimal over the next two years has restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere.
We will use our available cash and future access to capital markets to expand our diversified strategy in a number of countries that fit our strategic investment criteria. In executing our business strategy, we will strive to:
| • | maintain financial prudence and rigorous investment criteria; | ||
| • | access capital markets; | ||
| • | continue to create a diversified portfolio of assets; | ||
| • | preserve our financial flexibility; | ||
| • | use our experience and skills to acquire new projects; and | ||
| • | keep our organizational capabilities in line with our rate of growth. | ||
| To accomplish our strategy, we intend to: |
| • | Diversify our political risk:Acquire oil and natural gas fields in a number of countries to diversify and reduce the overall political risk of our investment portfolio. |
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| • | Seek Operational and Financial Control: We desire control of major decisions for development, production, staffing and financing for each project for a period of time sufficient for us to ensure maximum returns on investments. | ||
| • | Establish a Presence Through Joint Venture Partners and the Use of Local Personnel:We seek to establish a presence in the countries and areas we operate through joint venture partners to facilitate stronger governmental and business relationships. In addition, we use local personnel to help us take advantage of local knowledge and experience and to minimize costs. | ||
| • | Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time:We are willing to agree to minimum capital expenditures or development commitments at the outset of new projects, but we endeavor to structure such commitments to fulfill them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure. | ||
| • | Provide Technical Expertise:We believe there is an advantage in being able to provide geological, geophysical and engineering expertise beyond what many companies or countries possess internally. In addition to our in-house technical capabilities, we acquired a noncontrolling equity investment in Fusion, a technical firm with significant experience in providing leading edge geophysical, geosciences and reservoir engineering services in many places in the world. Through this acquisition we have strategic access to these services. | ||
| • | Maintain A Prudent Financing Plan: We intend to maintain our financial flexibility by closely monitoring spending, holding sufficient cash reserves, minimizing the use of restricted cash, actively seeking opportunities to reduce our weighted average cost of capital and increase our access to debt and equity markets. | ||
| • | Manage Exploration Risks. We seek to manage the higher risk of exploration by diversifying our prospect portfolio, applying state-of-the-art technology for analyzing targets and focusing on opportunities in proven active hydrocarbon systems with infrastructure. | ||
| • | Establish Various Sources of Production. We seek to establish new production from our exploration and development efforts in a number of diverse markets and expect to monetize production through operations or the sale of assets. |
Results of Operations
We included the results of operations of Harvest Vinccler in our consolidated financial statements and reflected the 20 percent ownership interest of OGTC as a noncontrolling interest in 2005 and the first quarter of 2006. Since April 1, 2006, our noncontrolling equity investment in Petrodelta has been reflected under the equity method of accounting. We recorded the cumulative effect from April 1, 2006 to December 31, 2007 in the three months ended December 31, 2007. The year ended December 31, 2008 includes net income from unconsolidated equity affiliates for Petrodelta on a current basis. See Exhibit 99.3 of this Current Report on Form 8-K under the captionNotes to the Consolidated Financial Statements, Note 7 — Investment in Equity Affiliates — Petrodelta, S.A.for Petrodelta’s results of operations which reflect the results for the years ended December 31, 2008 and 2007, comparatively.
The following discussion should be read with the results of operations for each of the years in the three-year period ended December 31, 2008 and the financial condition as of December 31, 2008 and 2007 in conjunction with our Consolidated Financial Statements and related Notes thereto.
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Years Ended December 31, 2008 and 2007
We reported a net loss attributable to Harvest of $21.5 million, or $0.63 diluted earnings per share, for 2008 compared to net income attributable to Harvest of $60.1 million, or $1.59 diluted earnings per share, for 2007.
Revenue recorded for the year ended December 31, 2007 reflects the reversal of deferred revenue recorded by Harvest Vinccler for 2005 and first quarter of 2006 deliveries pending clarification on the calculation of crude prices under the Transitory Agreement. See Exhibit 99.3 of this Current Report on Form 8-K under the captionNotes to the Consolidated Financial Statements, Note 1 — Organization and Summary of Significant Account Policies — Revenue Recognition. There were no sales of oil and natural gas in 2008 or 2007 due to the conversion of the OSA to a noncontrolling equity investment in Petrodelta.
Total expenses and other non-operating (income) expense (in millions):
| Year Ended | ||||||||||||
| December 31, | Increase | |||||||||||
| 2008 | 2007 | (Decrease) | ||||||||||
| Exploration expense | $ | 16.4 | $ | 0.9 | $ | 15.5 | ||||||
| Dry hole costs | 10.8 | — | 10.8 | |||||||||
| General and administrative | 27.2 | 29.1 | (1.9 | ) | ||||||||
| Taxes other than on income | (0.2 | ) | 0.4 | (0.6 | ) | |||||||
| Gain on financing transactions | (3.4 | ) | (49.6 | ) | 46.2 | |||||||
| Investment income and other | (3.7 | ) | (9.1 | ) | 5.4 | |||||||
| Interest expense | 1.7 | 8.2 | (6.5 | ) | ||||||||
| Income tax expense | — | 6.3 | (6.3 | ) | ||||||||
In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method. During the year ended December 31, 2008, we incurred $16.4 million of exploration costs related to the purchase and re-processing of seismic related to our United States operations, acquisition of seismic related to our Indonesia operations, and other general business development activities. Also during the year ended December 31, 2008, we incurred $10.8 million of dry hole costs related to the Harvest Hunter #1 well, which in January 2009 was determined to have no commercial quantities of hydrocarbons and was plugged and abandoned. The balance of any costs incurred for the drilling of the Harvest Hunter #1 well will be expensed in 2009 and are not expected to be material. During the year ended December 31, 2007, we incurred $0.9 million of exploration costs related to other foreign general business development.
General and administrative costs were lower in the year ended December 31, 2008, than in the year ended December 31, 2007, primarily due to employee related expenses and lower contract services. Taxes other than income for the year ended December 31, 2008, were lower than the year ended December 31, 2007 due to the reversal of a $1.1 million franchise tax provision that is no longer required.
During the years ended December 31, 2008 and 2007, we entered into securities exchange transactions exchanging U.S. government securities for U.S. Dollar indexed debt issued by the Venezuelan government. These security exchange transactions resulted in a $3.4 million and $49.6 million gain on financing transactions for the years ended December 31, 2008 and 2007, respectively.
Investment earnings and other decreased in the year ended December 31, 2008, as compared to the same period of the prior year due to lower interest rates earned on lower cash balances. Interest expense decreased due to the payment of Harvest Vinccler’s Venezuelan Bolivar (“Bolivar”) denominated debt in July of 2008.
For the year ended December 31, 2008, income tax expense, which is comprised of income tax on our foreign activities and withholding tax on interest income from Harvest Vinccler, was lower than that of the year ended December 31, 2007, partially due to the $49.6 million gain on financing transactions occurring in the year ended December 31, 2007 compared to a $3.4 million gain on financing transactions occurring in the year ended December 31, 2008. The reduction in income tax expense was also partially due to the reduction in the rate of
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withholding tax on the Venezuela interest, which went from 10 percent to 5 percent under the Netherlands-Venezuela double tax treaty. No income tax benefit is recorded for the net operating losses incurred as a full valuation allowance has been placed on the related deferred tax asset as management believes that is more likely than not that additional net losses will not be realized through future taxable income. There was no utilization of net operating loss carryforwards in the year ended December 31, 2008.
Years Ended December 31, 2007 and 2006
We reported net income attributable to Harvest of $60.1 million, or $1.59 diluted earnings per share, for 2007 compared with a net loss attributable to Harvest of $62.5 million, or $1.68 diluted earnings per share, for 2006.
Revenue recorded for the year ended December 31, 2007 reflects the reversal of deferred revenue recorded by Harvest Vinccler for 2005 and first quarter of 2006 deliveries pending clarification on the calculation of crude prices under the Transitory Agreement. See Exhibit 99.3 of this Current Report on Form 8-K under the captionNotes to the Consolidated Financial Statements, Note 1 — Organization and Summary of Significant Account Policies — Revenue Recognition. There were no sales of oil and natural gas in 2007 due to the conversion of the OSA to a noncontrolling equity interest in Petrodelta.
Total expenses and other non-operating (income) expense (in millions):
| Year Ended | ||||||||||||
| December 31, | Increase | |||||||||||
| 2007 | 2006 | (Decrease) | ||||||||||
| Exploration expense | $ | 0.9 | $ | — | $ | 0.9 | ||||||
| General and administrative | 29.1 | 26.4 | 2.7 | |||||||||
| Contribution to Science and Technology Fund | — | 3.9 | (3.9 | ) | ||||||||
| Taxes other than on income | 0.4 | 3.9 | (3.5 | ) | ||||||||
| Gain on financing transactions | (49.6 | ) | — | (49.6 | ) | |||||||
| Investment income and other | (9.1 | ) | (9.3 | ) | 0.2 | |||||||
| Interest expense | 8.2 | 23.2 | (15.0 | ) | ||||||||
| Income tax expense | 6.3 | 60.9 | (54.6 | ) | ||||||||
In December 2007, we changed our accounting method for oil and gas exploration and development activities to the successful efforts method from the full cost method. During the year ended December 31, 2007, we incurred $0.9 million of exploration costs related to other foreign general business development. Exploration costs incurred during the year ended December 31, 2006 were minimal.
General and administrative expenses increased due to employee related expenses offset by lower contract services. Harvest Vinccler accrued $3.9 million in the year ended December 31, 2006 for the estimated 2006 and 2007 Science and Technology contribution liability which was based on gross revenues for 2005 and 2006. Harvest Vinccler did not have any gross revenue subject to this law after March 31, 2006. Taxes other than on income decreased due to the elimination of municipal taxes which were based on oil deliveries under the OSA.
During the year ended December 31, 2007, we entered into securities exchange transactions exchanging U.S. government securities for U.S. Dollar indexed debt issued by the Venezuelan government. These security exchange transactions resulted in a $49.6 million gain on financing transactions for the year ended December 31, 2008. There were no such financing transactions entered into during the year ended December 31, 2006.
Investment earnings and other decreased due to interest earned on lower cash balances. Interest expense decreased due to the payment of Harvest Vinccler’s Bolivar denominated debt in the year ended December 31, 2007.
Income tax expense decreased due to the recording of Harvest Vinccler’s prior period tax assessments in the year ended December 31, 2006 and the reversal of deferred income taxes provided on Harvest Vinccler’s deferred revenue. We have utilized our current United States general and administrative expenses plus our net operating loss carryovers to offset the gains on financing transactions generated during the year ended December 31, 2007. There was no effect on our effective tax rate.
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Capital Resources and Liquidity
For calendar year 2009, we have preliminarily established an exploration and drilling budget of approximately $38.8 million. We are concentrating a substantial portion of this budget on the development of our Antelope project and Budong PSC. While we can give no assurance, we believe that our cash on hand will provide sufficient capital resources and liquidity to fund our exploration and business development expenditures for at least the next 12 months. We also currently believe that Petrodelta will fund its own operations and continue to pay dividends. InItem 1A — Risk Factorsin our most recent Annual Report on Form 10-K, we discuss a number of variables and risks related to our noncontrolling equity investment in Petrodelta and exploration projects that could significantly utilize our cash balances, affect our capital resources and liquidity. We also point out that the total capital required to develop the fields in Venezuela may exceed Petrodelta’s available cash and financing capabilities, and that there may be operational or contractual consequences due to this inability.
The amount of available capital will affect the scope of our operations and the rate of our growth. Our future rate of capital resource and liquidity growth also depends substantially upon the prevailing prices of oil. Prices also affect the amount of cash flow available for capital expenditures. Our ability to acquire and develop growth opportunities outside of Venezuela is partially dependent upon the ability to receive dividends from Petrodelta and access debt and equity markets.
The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks (see Item 1A — Risk Factors in our most recent Annual Report on Form 10-K). We require capital principally to fund the exploration and development of new oil and gas properties.
Based on our cash balance of $49 million at September 30, 2009, we will be required to raise additional funds in order to fund our 2010 forecasted operating and capital expenditure forecast. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration projects and to a lesser extent general and administrative costs. Through September 30, 2009, our exploration expenditures outside of Venezuela have not resulted in new proved reserves. If we are not able to raise additional capital there will be a need to reduce our projected expenditures which could limit our ability to operate our business. Currently, our only source of cash is dividends from Petrodelta, for which we recently announced an increase in proved reserves net to Harvest from 43.3 million barrels of oil equivalent (MMBOE) at December 31, 2008 to 47.6 MMBOE at August 31, 2009. This increase in Petrodelta proved reserves could potentially provide an increase in cash dividends to Harvest in future years. However, there is no certainty that Petrodelta will pay dividends in 2009 or 2010. Our lack of cash flow and the unpredictability of cash dividends from our Petrodelta joint venture could make it difficult to obtain financing and accordingly there is no assurance adequate financing can be raised. We continue to pursue, as appropriate, additional actions designed to generate liquidity including seeking of financing sources, accessing equity and debt markets, exploration of our properties worldwide, and cost reductions. In addition, we could delay discretionary capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, if necessary. There can be no assurances that any of these possible efforts will be successful or adequate, and if they are not, our financial condition and liquidity could be materially adversely affected.
On February 5, 2003, Venezuela imposed currency controls and created the Commission for Administration of Foreign Currency with the task of establishing the detailed rules and regulations and generally administering the exchange control regime. These controls fix the exchange rate between the Bolivar and the U.S. Dollar and restrict the ability to exchange Bolivars for U.S. Dollars and vice versa. The Bolivar is not readily convertible into the U.S. Dollar. The Venezuelan currency conversion restriction has not adversely affected our ability to meet short-term loan obligations and operating requirements for the foreseeable future.
Working Capital.Our capital resources and liquidity are affected by the ability of Petrodelta to pay dividends. In May 2008, Petrodelta declared and paid a dividend of $181 million, $72.5 million net to HNR Finance ($58 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the period of April 1, 2006 through December 31, 2007. In October 2008, Petrodelta paid an advance dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the six months ended June 30, 2008. We expect to receive future dividends from Petrodelta; however, we expect the amount of any future dividends to be much lower over the next several years as Petrodelta reinvests more of its earnings into the company in support of its drilling and appraisal activities. In June 2009, CVP issued instructions to all mixed companies regarding the accounting for deferred tax assets. The mixed companies have been instructed to set up a reserve within the equity section of the balance sheet for deferred tax assets. The setting up of the reserve had no effect on Petrodelta’s financial position, results of operation or cash flows. However, the new reserve could have a negative impact on the amount of dividends received in the future. In addition to reinvesting earnings into the company in support of its drilling and appraisal activities, the recent decline in the price per barrel affects Petrodelta’s ability to pay dividends. Until oil prices increase, all available cash will be used to meet current operating requirements and will not be available for dividends. SeeItem 1 — BusinessandItem 1A — Risk Factorsin our most recent Annual Report on Form 10-K andManagement’s Discussion and Analysis of Financial Condition and Results of Operations.
Our current cash and cash equivalents include money market funds and short term certificates of deposits with original maturity dates of less than three months. These investments are highly liquid and should not be impacted by the current credit crisis.
The net funds raised and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:
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| Year Ended December 31, | ||||||||||||
| (in thousands except as indicated) | ||||||||||||
| 2007 | ||||||||||||
| 2008 | (restated) | 2006 | ||||||||||
| Net cash provided by (used in) operating activities | $ | 50,380 | $ | (20,655 | ) | $ | (24,448 | ) | ||||
| Net cash provided by (used in) investing activities | (23,055 | ) | 69,960 | (90,556 | ) | |||||||
| Net cash provided by (used in) financing activities | (51,001 | ) | (76,543 | ) | 100,064 | |||||||
| Net decrease in cash | $ | (23,676 | ) | $ | (27,238 | ) | $ | (14,940 | ) | |||
| Working Capital | 77,010 | 111,534 | 117,564 | |||||||||
| Current Ratio | 3.0 | 3.6 | 2.4 | |||||||||
| Total Cash, including restricted cash | 97,165 | 127,610 | 236,968 | |||||||||
| Total Debt | — | 9,302 | 104,651 | |||||||||
The decrease in working capital of $34.5 million was primarily due to the payment of the accounts payable related party, repurchase of treasury stock, payment of a dividend to our noncontrolling equity partner in Harvest-Vinccler Dutch Holding, B.V., expenditures for drilling of an exploratory well and lease acquisition costs offset by the receipts of a $72.5 million dividend net to HNR Finance ($58 million net to our 32 percent interest) from our unconsolidated equity affiliate and payment of advances by PDVSA.
Cash Flow from Operating Activities. During the year ended December 31, 2008, net cash provided by operating activities was approximately $50.4 million. During the year ended December 31, 2007, net cash used in operating activities was approximately $20.7 million. The $71.1 million increase was primarily due to the receipts of a $72.5 million dividend net to HNR Finance ($58.0 million net to our 32 percent interest) and advance dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest) from our unconsolidated equity affiliate and payment of advances by PDVSA offset by payment of the accounts payable related party, repurchase of treasury stock, payment of a dividend to our noncontrolling equity partner in Harvest-Vinccler Dutch Holding, B.V., expenditures for drilling of an exploratory well and lease acquisition costs.
Cash Flow from Investing Activities.During the year ended December 31, 2008, we had cash capital expenditures of approximately $26.3 million. Of the 2008 expenditures, $0.1 million was attributable to exploration activity on the Budong PSC, $5.3 million was attributable to exploration activity on the Dussafu PSC, $4.2 million was attributable to exploration activity on the Antelope project, $4.7 million was attributable to exploration activity on the Gulf Coast prospects, $10.8 million was attributable to drilling costs for the Harvest Hunter #1 exploration well, and $1.2 million was for other projects. During the year ended December 31, 2007, we had limited production-related expenditures due to the pending formation of Petrodelta. In January 2007, we purchased a 45 percent noncontrolling equity interest in Fusion for $4.6 million. In October 2008, we increased our noncontrolling equity investment in Fusion by purchasing an additional two percent interest for $2.2 million. During the years ended December 31, 2008 and 2007, we had $6.8 million and $82.1 million, respectively, of restricted cash returned to us. We no longer have any cash that is restricted to our use. We incurred $1.3 million and $4.1 million of investigatory costs related to various international and domestic exploration studies during the years ended December 31, 2008 and 2007, respectively.
With the conversion to Petrodelta, Petrodelta’s capital commitments will be determined by its business plan. Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. Our budgeted capital expenditures of $38.8 million for 2009 for Gabon, Indonesia and United States operations will be funded through our existing cash balances and future Petrodelta dividends.
Cash Flow from Financing Activities.During year ended December 31, 2008, Harvest Vinccler repaid 20 million Bolivars (approximately $9.3 million) of its Bolivar denominated debt, and we redeemed the 20 percent noncontrolling interest in our Barbados affiliate. We also incurred $1.1 million in legal fees associated with prospective financing, and we paid a dividend of $14.9 million to our noncontrolling equity partner in Harvest-Vinccler Dutch Holding, B.V. During the year ended December 31, 2007, Harvest Vinccler repaid 205 million Bolivars (approximately $95.3 million) of its Bolivar denominated debt.
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In June 2007, we announced that our Board of Directors had authorized the purchase of up to $50 million of our common stock from time to time through open market transactions. This repurchase program was completed in June 2008. Under this program, we repurchased 4.6 million shares at an average cost of $10.93 per share, including commissions. In July 2008, our Board of Directors authorized the purchase of up to $20 million of our common stock from time to time through open market transactions. We continue to believe that Harvest stock remains undervalued and that the investment in the shares of our Company represents an attractive alternative to holding cash in excess of our needs. As of December 31, 2008, 1.2 million shares of stock have been purchased at an average cost of $10.17 per share for a total cost of $12.2 million of the $20 million authorization. Federal securities laws and the NYSE regulate the use of public disclosure of corporate inside information. These laws, rules and regulations require that we ensure information about Harvest is not used unlawfully in connection with the purchase and sale of securities. Pursuant to these laws, we are prohibited from purchasing stock while in possession of material non-public information.
Contractual Obligations
We have a lease obligation of approximately $32,000 per month for our Houston office space. This lease runs through April 2014. In addition, Harvest Vinccler has lease obligations for office space in Caracas, Venezuela for approximately $8,000 per month. This lease runs through December 2010. We also have lease commitments for an office in Utah for approximately $6,000 per month and an office in Singapore for approximately $18,000 per month. These leases expire in August and October 2010, respectively.
| Payments (in thousands) Due by Period | ||||||||||||||||||||
| Less than | After | |||||||||||||||||||
| Contractual Obligation | Total | 1 Year | 1-2 Years | 3-4 Years | 4 Years | |||||||||||||||
| Office Leases | $ | 4,334 | $ | 1,109 | $ | 932 | $ | 615 | $ | 1,678 | ||||||||||
Effects of Changing Prices, Foreign Exchange Rates and Inflation
Our results of operations and cash flow are affected by changing oil prices. Fluctuations in oil prices may affect our total planned development activities and capital expenditure program.
Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004 and again in March 2005. The currency conversion restrictions or the adjustment in the exchange rate have not had a material impact on us at this time. Dividends from Petrodelta will be denominated in U.S. Dollars when paid. Within the United States, inflation has had a minimal effect on us, but it is potentially an important factor with respect to results of operations in Venezuela.
During the years ended December 31, 2008 and 2007, our net foreign exchange gains attributable to our international operations were minimal. The U.S. Dollar and Bolivar exchange rates have not been adjusted since March 2005. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our control. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan currency to the U.S. Dollar. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.
An exemption under the Venezuelan Criminal Exchange Law for transactions in certain securities results in an indirect securities transaction market of foreign currency exchange, through which companies may obtain foreign currency legally without requesting it from the Venezuelan government. Publicly available quotes do not exist for the securities transaction exchange rate but such rates may be obtained from brokers. Securities transaction markets are used to move financial securities in and out of Venezuela.
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Critical Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. The equity method of accounting is used for companies and other investments in which we have significant influence. All intercompany profits, transactions and balances have been eliminated.
Investment in Equity Affiliates
Investments in unconsolidated companies in which we have less than a 50 percent interest and have significant influence are accounted for under the equity method of accounting. Investment in Equity Affiliates is increased by additional investment and earnings and decreased by dividends and losses. We review our Investment in Equity Affiliates for impairment under APB 18 whenever events and circumstances indicate a decline in the recoverability of its carrying value.
We own a 49 percent noncontrolling equity interest in Fusion and a 40 percent noncontrolling equity interest in Petrodelta through our 80 percent owned subsidiary HNR Finance. Petrodelta was formed in October 2007, and the net income from unconsolidated equity affiliates from April 1, 2006 to December 31, 2007 was reflected in the three months ended December 31, 2007 consolidated statements of operations. The year ended December 31, 2008 includes net income from unconsolidated equity affiliates for Petrodelta on a current basis. No dividends were declared or paid by Fusion in the years ended December 31, 2008 or 2007. In May 2008, Petrodelta declared and paid a dividend of $181 million, $72.5 million net to HNR Finance ($58.0 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the period of April 1, 2006 through December 31, 2007. In October 2008, Petrodelta paid an advance dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest), which represents Petrodelta’s net income as reported under IFRS for the six months ended June 30, 2008. Until Petrodelta’s board of directors declares a dividend for the year ended December 31, 2008, there is a possibility that all or a portion of the advance dividend could be rescinded; therefore, the advance dividend is reflected as a current liability on the consolidated balance sheets at December 31, 2008.
Property and Equipment
Oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered proved commercial reserves. Exploratory drilling costs are capitalized when drilling is completed if it is determined that there is economic producibility supported by either actual production, conclusive formation test or by certain technical data. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the projects is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in production of natural gas and crude oil, are capitalized.
Depreciation, depletion, and amortization of the cost of proved oil and natural gas properties are calculated using the unit of production method. The reserve base used to calculate depletion, depreciation or amortization for leasehold acquisition costs and the cost to acquire proved properties includes only proved developed reserves. With respect to lease and well equipment costs, which include costs and successful exploration drilling costs, the reserve
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base is the sum of proved developed reserves and proved undeveloped reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.
Assets are grouped in accordance with paragraph 30 of Statement of Financial Accounting Standard (“SFAS”) No. 19 Financial Accounting and Reporting by Oil and Gas Producing Companies. The basis for grouping is reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.
We account for impairments under the provisions of SFAS No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field level to the amortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the amortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.
Inventory held for use in the exploration for and development and production of natural gas and crude oil reserves are carried at cost with adjustments made from time to time to recognize any reductions in value.
Income Taxes
Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Reporting and Functional Currency
The U.S. Dollar is our reporting and functional currency. Amounts denominated in non-U.S. Dollar currencies are re-measured in U.S. Dollars, and all currency gains or losses are recorded in the consolidated statement of operations. We attempt to manage our operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence.
New Accounting Pronouncements
In December 2007, the SEC issued Staff Accounting Bulletin (“SAB”) No. 110 (“SAB 110”) which expresses the views of the staff regarding the use of a “simplified” method, as discussed in SAB No. 107, in developing an estimate of expected term of “plain vanilla” share options in accordance with FAS 123 (revised) — Share Based Payment. The staff will continue to accept, under certain circumstances, the use of the simplified method beyond December 31, 2007. SAB 110 was effective January 1, 2008. SAB 110 will not have a material effect on our consolidated financial position, results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (“SFAS Non 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, Business Combinations. SFAS No. 141(R) establishes principles and requirements for how the acquirer recognized and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. SFAS No. (141(R) also recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and determines what information to disclose in the financial statements. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted SFAS No. 141(R) effective January 1, 2009. The adoption
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of SFAS No. 141(R) did not impact our consolidated financial statements, but may have a material impact on our financial statements for businesses we acquire post-adoption.
In December 2007, the FASB issued SFAS 160 — Noncontrolling Interest in Consolidated Financial Statements — an amendment of Accounting Research Bulletin (“ARB”) No. 51 (“SFAS 160”). This new standard requires all entities to report noncontrolling interest in subsidiaries as equity in the consolidated financial statements. SFAS 160 is effective beginning with our first quarter 2009 financial reporting. We adopted SFAS No. 160 effective January 1, 2009. The provisions of SFAS 160 were applied to all noncontrolling interests prospectively except for the presentation and disclosure requirements which were applied retrospectively to all periods presented and have been disclosed as such in our consolidated financial statements contained herein. The adoption of SFAS 160 impacted the presentation of our consolidated financial position, results of operations and cash flows.
In March 2008, the Financial Accounting Standards Board (“FASB”) issued FAS 161 — Disclosures about Derivative Instruments and Hedging Activities (“FAS 161”) which changes the disclosure requirements for derivative instruments and hedging activities. FAS 161 is intended to enhance the current disclosure framework in FAS 133 — Accounting for Derivative Instruments and Hedging Activities. FAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. FAS 161 will not have a material effect on our consolidated financial position, results of operations or cash flows.
In May 2008, the Financial Accounting Standards Board (“FASB”) issued FAS 162 — The Hierarchy of Generally Accepted Accounting Principles (“FAS 162”) which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presenting in conformity with accounting principles generally accepted in the United States of America (“GAAP”). FAS 162 is effective 60 days following the SEC approval of the Public Company Accounting Oversight Board (“PCAOB”) amendments to AU Section 411, The Meaning of “Present Fairly” in Conformity With Generally Accepted Accounting Principles. The adoption of FAS 162 will not have a material effect on our consolidated financial position, results of operation or cash flows.
On December 31, 2008, the SEC issued its revised disclosure requirements for oil and gas reserves contained in its Regulation S-K and Regulation S-X under the Securities Act of 1933, the Securities Exchange Act of 1934 and Industry Guide 2. The final rule and interpretation was published in the Federal Register on January 14, 2009 and is effective January 1, 2010. Voluntary early compliance is not permitted. In short, the rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves. We are assessing the effect, if any, the rule will have in future years on our consolidated financial position, results of operation and cash flows. The SEC is discussing the rule with the FASB staff to align FASB accounting standards with the new SEC rules. These discussions may delay the required compliance date. Absent any change in the effective date, we will comply with the disclosure requirements in our Annual Report on Form 10-K for the year ended December 31, 2009.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
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