Exhibit 99.1
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FOR IMMEDIATE RELEASE |
Harvest Natural Resources
Provides an Operational Update
HOUSTON, April 4, 2013 /PRNewswire/ — Harvest Natural Resources, Inc. (NYSE: HNR) (the “Company”) today provided an operational update for its 32-percent-owned Venezuelan affiliate, Petrodelta, S.A. (Petrodelta) as well an update on Harvest’s international exploration activity, reserves and corporate and financial reporting matters.
VENEZUELA
Total proved plus probable reserves on December 31, 2012, net to Harvest’s 32 percent share of Petrodelta, were 100.23 million barrels of oil equivalent (MMBOE), a decrease of 3 percent from 2011. Harvest net interest of Petrodelta’s total proved reserves at year end 2012 were 38.40 MMBOE which was a decline of 11 percent from 2011, reflecting 2.97 MMBOE of production in 2012 and the reclassification of 1.71 MMBOE (4 percent) from proved to probable in compliance with the Securities and Exchange Commission’s “5 year rule from the date of original booking”. Without the reclassification of the 1.71 MMBOE to probable, the proved reserves in Venezuela would have decreased 7 percent to 40.11 MMBOE. All of the reclassified reserves are scheduled to be drilled by 2018. Net probable reserves in Venezuela of 61.83 MMBOE are 2 percent higher than 2011.
During the twelve months ended December 31, 2012, Petrodelta drilled and completed 12 successful development wells compared to 15 development wells in 2011. Petrodelta produced approximately 13.17 MMBO in 2012 compared to 11.39 MMBO during 2011, an increase of 16 percent year over year. In addition, Petrodelta sold 2.17 billion cubic feet (BCF) of natural gas versus 2.26 BCF of natural gas, a decrease of 4 percent over the same period in 2011. Petrodelta produced an average of 35,990 barrels of oil per day (BOPD) during the twelve months ended December 31, 2012. Currently, Petrodelta is operating three drilling rigs; three additional rigs and two workover rigs are being rigged up. Capital expenditures for development drilling and infrastructure are estimated to be $184.2 million in 2012 compared to $139.8 million in 2011.
On June 21, 2012, we announced that we and our wholly owned subsidiary HNR Energia had entered into a Share Purchase Agreement (“SPA”) with PT Pertamina (Persero), a state-owned limited liability company existing under the laws of Indonesia (“Buyer”) under which HNR Energia agreed to sell, indirectly through subsidiaries, all of its interests in Venezuela for a cash purchase price of $725.0 million, subject to adjustment as described in the SPA. After receiving notice from Buyer that Buyer’s sole shareholder, the Government of Indonesia, had decided not to approve the transaction described in the SPA, on February 19, 2013, HNR Energia exercised its right to terminate the SPA in accordance with its terms.
1177 Enclave Parkway, Suite 300 • Houston, Texas 77077 • ph: 281.899.5700 fax: 281.899.5702
The reserve report for the period ending December 31, 2012, has been completed and a summary of the report is provided in Table 1 below. The reserve report for the Venezuela fields assumes an average realized oil price in 2012 of $95.91 per barrel, after adjustment for location and quality, less an adjustment of $32.01 per barrel for the impact of Venezuela Windfall Profit Tax, resulting in a net realized oil price of $ 63.90. The natural gas reserves were based on a contractual price of $1.54 per thousand cubic feet (MCF). Table 2 below provides a comparison of the estimated reserves by category between 2011 and 2012.
Table 1: Estimated, Proved, Probable and Possible Reserves in Venezuela, net to Harvest Natural Resources, as of December 31, 2012
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| Producing | Non-Producing | Undeveloped | Total | |||||||||||||
| Proved Reserves |
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| Oil (Mbls) |
12,126 | 360 | 22,043 | 34,529 | ||||||||||||
| Gas (MMcf) |
15,573 | 2,333 | 5,303 | 23,210 | ||||||||||||
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| MBOE |
14,722 | 749 | 22,927 | 38,397 | ||||||||||||
| Probable Reserves |
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| Oil (Mbls) |
8 | — | 54,668 | 54,676 | ||||||||||||
| Gas (MMcf) |
0.5 | — | 42,924 | 42,925 | ||||||||||||
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| MBOE |
8 | 61,822 | 61,830 | |||||||||||||
| Possible Reserves |
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| Oil (Mbls) |
— | — | 99,463 | 99,463 | ||||||||||||
| Gas (MMcf) |
— | — | 29,444 | 29,444 | ||||||||||||
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| MBOE |
— | — | 104,370 | 104,370 | ||||||||||||
Table 2: Changes in estimated Proved, Probable and Possible Reserves in Venezuela, net to Harvest Natural Resources
| December 31, 2011 | December 31, 2012 | % Change | ||||||||||
| Oil Reserves (MMBbl) |
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| Proved |
38.7 | 34.5 | -11 | % | ||||||||
| Probable |
53.5 | 54.7 | 2 | % | ||||||||
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| Proved + Probable |
92.1 | 89.2 | -3 | % | ||||||||
| Possible |
101.9 | 99.5 | -2 | % | ||||||||
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| Total 3P |
194.0 | 188.7 | -3 | % | ||||||||
| Gas Reserves (Bcf) |
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| Proved |
27.8 | 23.2 | -17 | % | ||||||||
| Probable |
41.9 | 42.9 | 2 | % | ||||||||
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| Proved + Probable |
69.8 | 66.1 | -5 | % | ||||||||
| Possible |
29.5 | 29.4 | 0 | % | ||||||||
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| Total 3P |
99.3 | 95.6 | -4 | % | ||||||||
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| After Tax Discounted Future |
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| Net Income @ 10% ($MM) |
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| Proved |
$ | 543 | $ | 450 | -17 | % | ||||||
| Probable |
$ | 509 | $ | 467 | -8 | % | ||||||
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| Proved + Probable |
$ | 1,053 | $ | 917 | -13 | % | ||||||
| Possible |
$ | 865 | $ | 730 | -16 | % | ||||||
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| Total 3P |
$ | 1,918 | $ | 1,647 | -14 | % | ||||||
| Equivalent Reserves (Mmboe) |
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| Proved |
43.3 | 38.4 | -11 | % | ||||||||
| Probable |
60.5 | 61.8 | 2 | % | ||||||||
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| Proved + Probable |
103.8 | 100.2 | -3 | % | ||||||||
| Possible |
106.8 | 104.4 | -2 | % | ||||||||
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| Total 3P |
210.5 | 204.6 | -3 | % |
EXPLORATION AND OTHER ACTIVITIES
Dussafu Project – Gabon (“Dussafu PSC”)
In 2012, the Company entered into the third exploration phase of the Dussafu PSC, commenced drilling operations on the exploration well DTM-1 and subsequently drilled an appraisal sidetrack DTM- 1ST1. These wells were drilled with the Saipem Scarabeo 3 semi-submersible drilling unit in a water depth of 380 feet.
On May 28, 2012, the Dussafu PSC partners entered into the third exploration phase of the PSC for a four year period through May 27, 2016. The third exploration phase of the PSC has $7.0 million ($4.7 million net to our 66.667 per cent interest) work commitment over the four year period, which has been exceeded by the 2012 operations.
The DTM-1 well was spud on November 19, 2012, and drilled to test the potential of the pre-salt Gamba and Dentale Formations of the Tortue Prospect. The DTM-1 well reached a vertical depth of 11,260 feet within the Dentale Formation. Log evaluation and pressure data indicate that Harvest discovered approximately 42 feet of pay in a 72 foot oil column within the Gamba Formation and 123 feet of pay in stacked reservoirs within the Dentale Formation.
The Tortue oil discovery was appraised by drilling a sidetrack (DTM-1ST1) approximately 1,800 feet to the southwest to test the lateral extent and structural elevation of both the Gamba and Dentale Formations. The sidetrack was drilled to a Total Depth (TD) in the Dentale of 11,385 feet, 10,790 feet True Vertical Depth Subsea (TVDSS) and found 65 feet of oil pay in the principal Dentale sand with an apparent similar fluid level to that encountered in the vertical well DTM-1. Several other Dentale sands with oil shows were encountered; however, due to a stuck downhole tool, logging operations in the sidetrack were terminated before pressure data could be collected. The DTM-1ST1 well was suspended pending future appraisal and development activities. The drilling rig was released on February 21, 2013.
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The Tortue discovery is the second consecutive discovery made by Harvest and the fourth oil discovery on the block along with Ruche, Walt Whitman and Moubenga. The core and fluid data has been shipped from Gabon for laboratory analysis and the wireline data is being integrated with the seismic in on-going subsurface studies. Specifically, these studies include velocity modeling and depth conversion uncertainty modeling, reservoir characterization and dynamic modeling studies. Our current interpretation of the Tortue discovery indicates a preliminary range of contingent resources between 5 and 45 MMBBL.
This most recent discovery brings the combined mean estimate for contingent resources for the block to 46 MMBBL, including the three other existing oil discoveries in Ruche, Walt Whitman and Moubenga.
A program of subsurface and conceptual engineering studies has commenced with the objective of evaluating the commerciality of Tortue and the other oil discoveries to determine the optimum development options for the block.
In other parts of the block, activities during 2012 included completion in July of the Pre-Stack Time Migration (“PSTM”) processing of 545 square kilometers of Central 3-D seismic, which was acquired in the fourth quarter of 2011. Pre-Stack Depth processing and reprocessing of the new Central 3-D together with the 2005 Inboard 3-D seismic, approximately 1,300 square kilometers, commenced in June 2012. The Pre-Stack Depth processing of the merged 3-D project is expected to be completed in the second quarter of 2013.
Harvest operates the Dussafu PSC, holding a 66.667 percent interest.
Indonesia
Operational activities during the year ended 2012 included a review of geological and geophysical data obtained from the drilling of LG-1 and KD-1 wells to upgrade the prospectivity of the block and to define a prospect for potential drilling in 2013. Based on multiple oil and gas shows encountered in both LG-1 and KD-1, we are working on an exploration program targeting the Pliocene and Miocene sands encountered in the previous two wells. We have completed remapping of both the Lariang and Karama Basins with eight leads in the Lariang Basin and five leads in the Karama Basin having been identified in the Pliocene, Middle-Late Miocene and Eocene sands. The identification of these leads is the basis for the four-year extension request of the first six-year exploration term. The partners have technically recommended the drilling of the Madjene prospect in the Lariang Basin, targeting stacked Pliocene and Miocene clastic reservoirs for an exploration well in late 2013. Preliminary well planning activities commenced in October 2012.
The initial exploration term of the Budong PSC was due to expire on January 15, 2013. In September 2012, the operator of the Budong PSC, on behalf of us and the other co-venturer, submitted a request to BPMIGAS under the terms of the Budong PSC for a four-year extension of the initial six-year exploration term of the Budong PSC. In January 2013, we received written approval from SKK Migas of the four-year extension of the initial six-year exploration term.
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In December 2012, we signed a farmout agreement with the operator of the Budong PSC to acquire an additional 7.1 percent participating interest and to become operator of the Budong PSC. We assumed the role of interim operator effective January 16, 2013. Closing of this acquisition will increase our participating ownership interest in the Budong PSC to 71.5 percent with our cost sharing interest becoming 72 percent until first commercial production. The consideration for this recent acquisition is that we will fund 100 percent of the costs of the first exploration well of the four-year extension to the Budong PSC. If the exploration well is not drilled within 18 months of the date of approval from the Government of Indonesia of this transaction, our partner has the right to give notice that the consideration be paid in cash, or $3.2 million. The acquisition of the additional participating interest is subject to approval by the Government of Indonesia.
We have satisfied all work commitments for the current exploration phase of the Budong PSC. However, the extension of the initial exploration term includes an exploration well, which if not drilled by January 2016, results in the termination of the Budong PSC.
Oman Block 64 EPSA
Both the work and financial commitments on Block 64 EPSA have been fulfilled. Operational activities during the year ended December 31, 2012, included post-well evaluation and review of geological and geophysical data obtained from the drilling of MFS-1 and AGN-1 wells. On March 5, 2013, we elected to not request an extension of the First Phase or enter the Second Phase of Block 64 EPSA. The carrying value of Block 64 EPSA of $6.3 million was written off to dry hole costs at December 31, 2012.
During the year ended December 31, 2012, we incurred $6.0 million for drilling and plugging and abandonment costs (2011: $10.2 million for well planning, drilling and plugging and abandonment costs). The 2013 budget for Block 64 EPSA is minimal, consisting of costs required to terminate operations.
Harvest will be closing the office and exiting the country in the second quarter of 2013.
WAB 21, South China Sea
Due to a lack of activity and the ongoing border dispute between People’s Republic of China and Socialist Republic of Vietnam over the WAB-21 contract area, the Company expensed $2.9 million which represented the book value of the block as of the end of December 31, 2012. Harvest maintains its interest in the block and continues as the operator.
Corporate and Financial Reporting
Debt
In October 2012, we announced the sale of $79.8 million aggregate principal amount of 11 percent senior unsecured notes due October 11, 2014, and warrants to purchase up to 0.8 million shares of our common stock with an exercise price of $10.00 per share. The net cash proceeds of the offering were approximately $63.5 million after deducting the issuance discount, placement fees, and other transaction costs.
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Financial Reporting and Control Issues
During the December 31, 2012 year end audit process, the following material weaknesses were identified. Due to these weaknesses, the following errors were identified and adjustments will be made in current and previous SEC filings:
| • | In certain areas, the Company did not maintain a sufficient complement of resources with an appropriate level of accounting knowledge, experience and training commensurate with our financial reporting requirements. |
| • | The Company did not maintain effective internal control over the accuracy, valuation and application of generally accepted accounting principles related to the capitalization, classification and impairment of certain costs related to oil and gas properties. |
| • | The Company did not maintain effective controls to provide reasonable assurance that journal entries were appropriately recorded or that they were properly reviewed for validity, accuracy and completeness. |
| • | The Company did not maintain effective controls over the preparation and review of the statement of cash flows. |
| • | The Company did not maintain effective controls over significant and complex debt and equity transactions. |
In connection with the preparation of our Annual Report on Form 10-K for the year ended December 31, 2012, the Company concluded that there were errors in previously filed financial statements. These errors are outlined below:
| • | Certain warrants issued in 2010 in connection with our $60 million term loan facility (the “Warrants”) were improperly valued at inception and improperly classified as equity instruments rather than liability instruments. As a result of the improper classification of the Warrants, the debt discount and associated interest expense related to the amortization of the debt discount was understated for all periods in which the associated debt was outstanding. Additionally, the consolidated statement of operations and comprehensive income (loss) for each reporting period was misstated by the omission of the changes in fair value of the Warrants as a liability instrument. |
| • | As a result of the errors related to the Warrants described above, loss on extinguishment of debt was understated for the year ended December 31, 2011 and the quarters ended June 30, 2011, September 30, 2011 and December 31, 2011. |
| • | Certain exploration overhead was incorrectly capitalized to unproved properties, which under the successful efforts method of accounting should have been expensed, and certain leasehold maintenance and other costs were improperly capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed. |
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| • | In addition, advances to equity affiliate were improperly classified as an operating activity rather than an investing activity and certain costs were improperly classified as an investing activity rather than an operating activity on the consolidated statement of cash flows. |
| • | Additionally, an error was identified in the calculation of earnings (loss) per diluted share for the year ended December 31, 2011 and the quarterly period ended June 30, 2011. |
| • | The Company will also correct the financial statements for previously identified immaterial errors and an income statement reclassification between exploration expense and impairment of oil and gas properties for the year ended December 31, 2011 and the quarterly period ended September 30, 2011. |
| • | An additional error was identified related to the improper expensing of costs associated with debt conversions that should have been recorded to equity for the quarters ended March 31, 2012 and September 30, 2012. |
Any adjustments made related to the above issues will have a non-cash impact to the Company.
The Company is also evaluating the permanent reinvestment assertion related to certain tax matters. Many of these corrections are period to period adjustments and will have a non-cash impact to the Company.
The Company intends to file amendments to its quarterly reports on Form 10-Q/A for each fiscal quarter ended March 31, 2012, June 30, 2012 and September 30, 2012, which will also include amendments to the quarters ended March 31, 2011, June 30, 2011, and September 30, 2011. The Company intends to restate its financial statements for the Restated Periods in the 2012 Form 10-K which the Company currently expects to file with the Securities and Exchange Commission as soon as reasonably practicable to correct the accounting treatment for the items discussed above.
On an absolute dollar basis, none of the adjustments made to date are material. However, because our net income (loss) in some periods was close to a breakeven point, on a quantitative basis as a percentage of net income (loss), the adjustments are considered to be material.
Going Concern
The Company’s financial statements for the year ended December 31, 2012 have been prepared under the assumption that Harvest will continue as a going concern. Our audit report will include an explanatory paragraph expressing substantial doubt about our ability to continue as a going concern.
Reserves Disclosure
The proved, probable and possible reserves included herein were prepared by Ryder Scott and conform to the definitions as set forth in the Securities and Exchange Commission’s (SEC) Regulations Part 210.4-10(a). The hydrocarbon prices used are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the reserve report, determined as the unweighted arithmetic averages of the prices in effect on the first day of the month for each month within such period, unless prices were defined by contractual
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arrangements. Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.
Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.
The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.
Reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.
About Harvest Natural Resources:
Harvest Natural Resources, Inc., headquartered in Houston, Texas, is an independent energy company with principal operations in Venezuela, exploration assets in Indonesia, West Africa, and China and business development offices in Singapore and the United Kingdom. For more information visit the Company’s website at www.harvestnr.com.
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CONTACT:
Stephen C. Haynes
Vice President, Chief Financial Officer
(281) 899-5716
This press release may contain projections and other forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. They include estimates and timing of expected oil and gas production, oil and gas reserve projections of future oil pricing, future expenses, planned capital expenditures, anticipated cash flow and our business strategy. All statements other than statements of historical facts may constitute forward-looking statements. Although Harvest believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Actual results may differ materially from Harvest’s expectations as a result of factors discussed in Harvest’s 2011 Annual Report on Form 10-K and other public filings.
Harvest may use certain terms such as resource base, contingent resources, prospective resources, probable reserves, possible reserves, non-proved reserves or other descriptions of volumes of reserves. These estimates are by their nature more speculative than estimates of proved reserves and accordingly, are subject to substantially greater risk of being actually realized by the Company.
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