Harvest Natural Resources Operational Update

HOUSTON, March 6, 2012 /PRNewswire/ -- Harvest Natural Resources, Inc. (NYSE: HNR) today provided an operational update for its 32-percent-owned Venezuelan affiliate, Petrodelta, S.A. (Petrodelta) as well as Harvest's international exploration activity, as well as reserves and corporate and financial reporting matters.

Venezuela

  • In the twelve months ended December 31, 2011, Petrodelta drilled and completed 15 wells and executed two well re-entries;  
  • Production was approximately 11.39 million barrels of oil (MMBO) for a daily average of approximately 31,205 barrels per day, an increase of 33 percent over the same period in 2010;  
  • Capital expenditures were estimated to be $137.5 million in 2011, compared to $98.7 million in 2010;
  • Petrodelta's average production rate for 2012 to date is approximately 32,500 barrels of oil per day (BOPD);
  • Petrodelta's proved plus probable reserves on December 31, 2011, net to HNR are 103.7 million barrels oil equivalent (MMBOE), essentially unchanged from 2010;
  • Harvest has commenced exclusive negotiations with a third party for the possible sale of its 32 percent interest in Petrodelta.  There can be no assurance that such negotiations will be successful.

Gabon

  • Harvest drilled Dussafu Ruche Marin 1 (DRM-1) exploration well and two appraisal sidetracks during 2011;
  • Harvest announced a discovery after drilling the DRM-1 well upon reaching a vertical depth of 9,953 feet.  Log evaluation indicated a discovery of approximately 55 feet of pay in a 90 foot oil column within its primary objective, the Gamba Formation;
  • DRM-1 well was deepened to reach a TVDSS of 11, 355 feet and discovered a second oil accumulation with approximately 35 feet of oil within the Middle Dentale Formation;
  • Approximately 545 square kilometers of 3-D seismic was acquired during the fourth quarter.

Indonesia

Lariang Sub-Basin

  • The Lariang LG-1 well spud on January 6, 2011 in the Budong Budong Block, West Sulawesi;
  • The LG-1 well was drilled to a total depth of 5,311 feet and encountered multiple hydrocarbon shows and overpressure in Miocene formations requiring up to 16.5 pound per gallon mud weight.  After encountering difficulty in controlling the well due to high pressures, the well was plugged and abandoned on April 8, 2011;
  • The test confirmed the presence of hydrocarbons as well as the existence of an effective trap and seal in the Lariang sub-basin;

Karama Sub-Basin

  • The KD-1 well, the second exploration well of a two well program on the Budong PSC, spud on June 20, 2011, and initially drilled to a total depth of 11,880 feet and logged;
  • Evaluation of cuttings, log and sidewall cores demonstrated the presence of oil over a 200 foot section of low permability and low porosity clastic rock in the Miocene;
  • The Company elected to deepen the well to a final TD of 14,437 feet on a sole risk operation and encountered both Oligocene and Eocene stratigraphy before drilling reached the limits of the BOP pressure rating, after which the well was plugged and abandoned.

Oman  

  • The Mafraq South-1 (MFS-1) exploration well was spud on October 29, 2011, the first of a two-well exploratory drilling program; the MFS-1 well reached TD of 10,348 feet.  The logs indicated no presence of hydrocarbons within the stacked reservoir targets and was plugged and abandoned;
  • A second exploration well, Al Ghubar North-1 (AGN-1), was spud on December 23, 2011.  Mudlog and wireline logs indicated no apparent hydrocarbon saturations within the principal stacked Haima targets in the Barik, Miqrat and Amin reservoirs;
  • The AGN-1 was plugged and abandoned on February 6, 2012.

United States

  • Completed sale of Utah assets on May 17, 2011 and received $217.8 million, $205 million net of transaction related costs, achieving a return on investment of 138 percent with a project cycle time of 3 years;

Reserves

  • Total proved plus probable reserves on December 31, 2011 were 103.7 MMBOE, a decrease of 13% from 2010, reflecting the sale of the Utah assets which included 15.3 MMBOE;
  • Total proved reserves on December 31, 2011 were 43.3 MMBOE, a decrease of 21% from 2010, partially reflecting the sale of the Utah assets which included 4.6 MMBOE;
    • Venezuela total proved reserves of 43.3 MMBOE declined 13% from 2010, reflecting the reclassification of 16.1 MMBOE (37%) from proved to probable in compliance with the Securities and Exchange Commission's "5 year rule from the date of original booking" and 2.6 MMBOE of production in 2011;
  • Without the reclassification of the 16.1 MMBOE to probable, proved reserves in Venezuela would have increased 19% to 59.4 MMBOE.  All of the reclassified reserves are scheduled to be drilled by 2016;
  • Probable reserves in Venezuela of 60.4 MMBOE are 13% higher than 2010, making total proved and probable reserves unchanged from 2010.

Corporate and Financial Reporting

  • Paid off $60.0 million bridge loan on May 17, 2011.  Reduced outstanding debt to approximately $31.5 million;
  • The Company will revise previous historical financial statements reported in the 2011 Form 10-K to correct a non-cash error relating to deferred taxes for Petrodelta, having a cumulative impact from 2007 to 2010 of decreasing our equity income by $2.2 million;
  • Harvest will also revise the 2011 quarterly results for the deferred tax error reducing our equity income by $0.3 million and an error in accounting for taxes related to the Utah transaction which reduces 2011 tax expense by $5.5 million.;
  • The cumulative net impact of these adjustments is an increase of $3.0 million in net income to Harvest.

Harvest President and Chief Executive Officer, James A. Edmiston, said:  "Petrodelta continued its growth trajectory increasing production 33% year on year in spite of investment delays and facility constraints.  As facility expansion advances, we expect to see that level of growth continue to increase.  In 2011, we also advanced our exploration programs drilling wells in Gabon, Indonesia and Oman.  These efforts resulted in an oil discovery in Gabon, which along with two previous discoveries will anchor our future development efforts on the block.  In Indonesia, our exploratory efforts on our Budong Budong block proved the working hydrocarbon systems in both the Lariang and Karama sub-basins, providing a substantial inventory of future prospectivity.  In Oman, while both wells in our Block 64 failed to discover gas, the operational performance of the team was outstanding and both wells were drilled well ahead of the curve and under budget."

Edmiston continued, "In 2012, along with our continued focus on seeing that Petrodelta reaches its full potential, we will advance our plans on the development of the Dussafu Block in Gabon, beginning with the evaluation of the new 3-D seismic acquired in the fourth quarter in order to optimize our future drilling and development activities."

"Finally, with the sale of our Utah assets, the Company was able to reduce debt by over 60 percent and completely fund our exploration drilling program while improving liquidity in 2011."

VENEZUELA

During the twelve months ended December 31, 2011, Petrodelta drilled and completed 15 successful development wells compared to 16 development wells in 2010.  Petrodelta produced approximately 11.39 MMBO in 2011 compared to 8.56 MMBO during 2010, which represents an increase of 33 percent year over year.  In addition, Petrodelta sold 2.27 billion cubic feet (BCF) of natural gas versus 2.20 BCF, an increase of 3 percent over the same period in 2010.  Petrodelta produced an average of 31,205 BOPD during the twelve months ended December 31, 2011.  Currently, Petrodelta is operating three drilling rigs and one workover rig.  Capital expenditures for development drilling and infrastructure are estimated to be $137.5 million in 2011 compared to $98.7 million in 2010.

On March 5, 2012, the Company commenced exclusive negotiations for a specified time period with a third party for the possible sale of the Company's 32 percent interest in its Venezuelan asset, Petrodelta S.A.  There can be no assurance that these negotiations will result in a transaction to sell the Company's interests in Venezuela.

The reserve report for the period ending December 31, 2011, has been completed and a summary of the report is provided in Table 1 below.  The reserve report for the Venezuela fields assumes the average realized oil price in 2011 of $98.37 per barrel, after adjustment for location and quality, less an adjustment of $32.10 per barrel for the impact of Venezuela Windfall Profit Tax, resulting in a net realized oil price of $66.27.  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 2010 and 2011.

Table 1:  Estimated Proved, Probable and Possible Reserves in Venezuela, net to Harvest Natural Resources, as of December 31, 2011





Developed





Proved Reserves


Producing


Non-Producing


Undeveloped


Total

Oil (MBbls)


12,425


1,292


24,948


38,665

Gas (MMcf)


17,552


2,739


7,549


27,840

MBOE


15,350


1,749


26,206


43,305










Probable Reserves









Oil (MBbls)


93


34


53,341


53,468

Gas (MMcf)


73


9


41,829


41,910

MBOE


105


36


60,312


60,453










Possible Reserves









Oil (MBbls)


-


-


101,855


101,855

Gas (MMcf)


-


-


29,548


29,548

MBOE


-


-


106,780


106,780





































Table 2:  Changes in Estimated Proved, Probable and Possible Reserves in Venezuela, net to Harvest Natural Resources












December 31, 2010


December 31, 2011


% Change



Oil Reserves (MMBbl):









Proved


41.7


38.7


-7%



Probable


51.0


53.4


5%



Proved + Probable


92.7


92.1


-1%












Possible


111.6


101.9


-9%



Total 3P


204.3


194.0


-5%












Gas Reserves (Bcf):









Proved


50.1


27.8


-44%



Probable


15.4


41.9


172%



Proved + Probable


65.4


69.7


6%












Possible


32.4


29.6


-9%



Total 3P


97.8


99.3


2%












After Tax Discounted Future









Net Income @ 10% ($MM):









Proved


$505


$    543


7%



Probable


$442


$    509


15%



Proved + Probable


$    947


$ 1,052


11%












Possible


$878


$    865


-2%



Total 3P


$ 1,826


$ 1,917


5%





















Equivalent Reserves (Mmboe)









Proved


50.0


43.3


-13%



Probable


53.6


60.4


13%



Proved + Probable


103.6


103.7


0%












Possible


117.0


106.8


-9%



Total 3P


220.6


210.5


-5%














EXPLORATION AND OTHER ACTIVITIES

Dussafu Project - Gabon ("Dussafu PSC")

In 2011 the Company drilled one exploration well, DRM-1, and two appraisal sidetracks, DRM-1-ST and the DRM-2ST, in the Dussafu Marin PSC, in the offshore waters of Gabon.  These wells were drilled with the Transocean Sedneth 701 semi-submersible drilling unit in approximately 380 feet of water.

The DRM-1 spud on April 28, 2011 and drilled to test the potential of the pre-salt Gamba and Dentale Formation.  The DRM-1 reached a vertical depth of 9,953 feet within the Upper Dentale Formation.  Log evaluation, pressure data and samples indicate that Harvest discovered approximately 55 feet of pay in a 90 foot oil column within its primary objective, the Gamba Formation.

Subsequently the DRM-1 well was deepened to reach a TVDSS of 11,355 feet to test the prospectivity of the Middle and Lower Dentale Formations.  Log evaluation, pressure data and a fluid sample indicate that Harvest discovered a second oil accumulation with approximately 35 feet of oil pay within the secondary objective of the Middle Dentale Formation.

The first appraisal sidetrack (DRM-1ST1) three quarters of a mile to the southwest was drilled to a TD in the Upper Dentale of 11,562 feet (9,428 feet TVDSS) and found 19 feet of oil pay in the Gamba reservoir.

The second sidetrack (DRM-1ST2) half a mile to the northwest of the original DRM-1 wellbore was drilled to a TD in the Upper Dentale of 10,615 feet (9,429 feet TVDSS) and found 40 feet of oil pay in the Gamba reservoir.

The Ruche discovery is the third oil discovery on the block, along with Walt Whitman and Moubenga.  The current estimate of gross unrisked contingent resources for the three oil discoveries is 26 MMBBL.

Approximately 545 square kilometers of 3-D seismic was acquired during the fourth quarter.  The data was acquired in an area between the existing 3-D surveys and the area including the 2-D seismic Harvest acquired in 2008, to define exploration targets within the pre-salt section.  A seismic test line using the latest acquisition technology was acquired over the Ruche discovery to determine if the sub-salt image can be improved over the current data acquired in 1994.

Drilling operations have been suspended pending further exploration and development activities, including the processing and interpretation of the newly acquired 3-D seismic.  Reservoir and concept engineering studies have started with the aim of evaluating the commerciality of the discovered oil in Ruche and the optimum development options.

Harvest operates the Dussafu PSC, holding a 66.667 percent interest.

Indonesia

Lariang Sub-Basin

The Lariang LG-1 well, the first of two planned exploration wells, was spud on January 6, 2011 in the Budong-Budong Block, West Sulawesi and drilled to a depth of 5,311 feet.  Multiple oil and gas shows were encountered within the secondary Miocene objective.  Wireline logs and samples of reservoir fluids have confirmed the presence of hydrocarbons, trap and seal thus greatly de-risking the exploration potential of the license.  Due to high formation pressures and losses of heavy drilling mud into the formation, the well was plugged and abandoned for safety reasons on April 8, 2011.  The primary Eocene targets had not yet been reached, as the well was planned for a total measured depth of approximately 7,200 feet.

Since January 2012, after completion of drilling of the KD-1, all information gathered from the drilling of the LG-1 and KD-1 is being evaluated in connection with plans for the Budong PSC and overall corporate strategy.  Based on this evaluation, it was determined that the original LG-1 well bore would not be used for re-entry.  Since plans for the Budong PSC no longer include re-entry of the LG-1 well bore, the drilling costs of $14.0 million related to the drilling of the LG-1 have been expensed to dry hole costs as of December 31, 2011.  Based on the multiple oil and gas shows encountered in both the LG-1 and KD-1, we are working on an exploration program targeting the Pliocene and Miocene targets encountered in the previous two wells.

Karama Sub-Basin

The Karama KD-1 well, the second exploratory well of a two well program on the Budong PSC, spud on June 20, 2011 to drill and test the stacked Miocene and Eocene targets within a thrusted anticline.  The well was initially drilled to a depth of 9,633 feet and sidetracked after the drill string was severed.  The sidetrack KD-1ST was initially drilled to a total depth of 11,880 feet and logged.  The evaluation of cuttings, logs and sidewall cores demonstrated the presence of oil over a 200 foot section of low permeability and low porosity clastic rocks in the Miocene.  The oil shows have proven the existence of a working petroleum system in the Karama Basin.  

On a sole risk operation basis, Harvest elected to deepen the well to a final total depth of 14,437 feet to explore for the main Eocene objective.  As the drilling operations reached the BOP pressure limits, the well encountered both Oligocene and Eocene stratigraphy; however, the primary Eocene reservoir target had not yet been reached.  Biostratigraphy indicates the section at TD to be Eocene deep water shales.  Nearby within the basin are a number of Eocene outcrops with known fluvial reservoir and source rocks, along with oil and gas seeps.  The well was plugged and abandoned.  Harvest expects to expense a dry hole cost of $26.0 million in the fourth quarter of 2011.

Tately Budong-Budong N.V. is the operator of the Budong-Budong Block.  Harvest owns a 64.4 percent working interest in the Budong-Budong PSC.

Oman Block 64 EPSA

On October 29, 2011, Harvest spud the Mafraq South-1 (MFS-1) exploration well onshore Oman.  This is the first of a two-well exploratory program utilizing the MB Petroleum Services LLC Rig #113 drilling unit.  The MFS-1 well tested the Mafraq South structure, which is a large salt-supported high with stacked reservoir targets in the Barik, Miqrat and Amin reservoirs.  The primary targets are both in the footwall and hanging wall fault blocks which comprise four segments (north, west, south and east).

The MFS-1 exploration well was drilled to a total depth of 10,348 feet.  Although the quality of the Barik and the Amin reservoirs was better than expected, the logs did not indicate the presence of hydrocarbons within the stacked reservoir targets in the Barik, Miqrat and Amin reservoirs, and the well was plugged and abandoned.  Drilling days to TD were 28 days ahead of forecast resulting in reduced dry hole cost.  Harvest expects to expense $6.9 million in the fourth quarter of 2011.

On December 21, 2011, the Al Ghubar North-1 (AGN-1) exploration well spud on the Qarn Alam Block 64, onshore Oman.  This is the second of a two-well exploratory program utilizing the MB Petroleum Services LLC Rig #113 drilling unit.  

The AGN-1 exploration well was drilled to a TD of 10,482 feet.  Interpretation of the mudlog and wireline logs indicates no apparent hydrocarbon saturations within the principal stacked Haima targets in the Barik, Miqrat and Amin reservoirs; however, gas shows and residual hydrocarbons indicate that the structure was charged and failure is attributed to seal effectiveness.  The well was plugged and abandoned on February 6, 2012 with gas shows.

The total estimated dry hole cost for the well was $7.6 million, of which $2.8 million was expensed in 2011 and the remainder in 2012.

Harvest has an 80 percent interest in Block 64 onshore Oman.  Block 64 has an area of 3,874 square kilometers and was extracted from a pre-existing block (PDO's Block 6) to accelerate exploration for gas and gas condensate by the Omani Ministry of Oil and Gas.

UNITED STATES - Antelope Project - Utah

On May 17, 2011, the Company completed the sale of its oil and gas assets in Utah's Uinta Basin to an affiliate of Newfield Exploration Company (Newfield).  The Company received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs.  The sale had an effective date of March 1, 2011.  The net proceeds from the sale were approximately $205.0 million after deductions for transaction related costs.

Corporate and Financial Reporting

Debt

On May 17, 2011, Harvest repaid the $60.0 million term loan facility with MSD Energy Investments Private II, LLC, an affiliate of MSD Capital, L.P.  The repayment included the repayment of the principal, accrued interest, and other fees related to the early repayment of the debt and repurchase of certain warrants.  Also during 2011, approximately $500,000 of the Senior Convertible Debt was converted into common stock at the predetermined conversion rate, leaving approximately $31.5 million of the debt facility outstanding.

Financial Reporting

The Company will revise previous historical financial statements reported in the 2011 Form 10K to correct a non-cash error in accounting for deferred taxes related to Petrodelta which has a cumulative impact from 2007 to 2010 of decreasing our equity income by $2.2 million.  Harvest will also revise our 2011 quarterly results for the deferred tax error, reducing our equity income by $0.3 million and an error in accounting for the taxes related to the Utah transaction which will reduce our 2011 tax expense by $5.5 million.  The cumulative net impact of these adjustments is an increase of $3.0 million in net income to Harvest.

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 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, China and Oman and business development offices in Singapore and the United Kingdom.  For more information visit the Company's website at www.harvestnr.com.

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 2010 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.  

SOURCE Harvest Natural Resources



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