target is approximately 16,000 barrels of oil per day following the December 17, 2008 OPEC meeting establishing new production quotas. However, Petrodelta has been allowed to produce at capacity to help fulfill other companies' production shortfalls, thus averaging 20,771 barrels of oil per day during the nine months ended September 30, 2009.
Petrodelta shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. The management and board of directors of Petrodelta have had to take actions to reduce both operating and capital expenditures. See Item 1A - Risk Factors in Part II of this Quarterly Report on Form 10-Q for additional information regarding Petroleos de Venezuela, S.A. ("PDVSA"). Due to the situation described in Item 1A - Risk Factors, Petrodelta's working capital position continues to deteriorate.
Petrodelta's 2009 drilling program was to utilize two rigs to drill development and appraisal wells for both maintaining production capacity and appraising the substantial resource bases in the El Salto field and presently non-producing Isleņo field. However, Petrodelta had to reduce its rig count to one drilling rig for most of the second and all of the third quarter 2009 while rigs and drilling contracts are renegotiated. Petrodelta is expected to utilize only one rig during the fourth quarter of 2009 to drill both development wells and appraisal wells. Petrodelta's management is reviewing options to hire an additional drilling rig and a workover rig for early 2010.
Petrodelta began the appraisal and testing of its large portfolio of undeveloped resources in the second quarter of 2009. During the second quarter 2009, Petrodelta drilled two successful appraisal wells in the El Salto field, and pilot production commenced from one of the appraisal wells through temporary facilities. The well commenced production on July 18, 2009 and has produced 243,000 barrels of oil through the end of October 2009. The second appraisal well is still waiting on permits from the Ministry of Energy and Petroleum ("MENPET") for testing.
During the third quarter 2009, we commissioned an interim reserve report for Petrodelta to assess and secure the growth potential of the Temblador and El Salto fields. The reserve report reflects a 10 percent increase in proved reserves to 47.6 million barrels of oil equivalent (MMBOE) (net to our 32 percent interest) at August 31, 2009, as compared to year-end 2008. The increase was driven primarily by the drilling of the two appraisal wells in Petrodelta's largely undeveloped El Salto field.
In our Annual Report on Form 10-K for the year ended December 31, 2008, we reported that Petrodelta had not received all information regarding production during the conversion period for the Temblador field in order to invoice all volumes produced in that field during that period. As Temblador production was handled in PDVSA system, PDVSA had allocated only partial, estimated production to Petrodelta. As a result, Petrodelta had not, and still has not, received full credit for the Temblador field production. Discussions are ongoing to settle figures. During the third quarter 2009, Petrodelta completed the facilities and pipelines to segregate approximately 80 percent of the Temblador field's production out of PDVSA's system.
In 2005, Venezuela modified the Science and Technology Law (referred to as "LOCTI" in Venezuela) to require companies doing business in Venezuela to invest, contribute, or spend a percentage of their gross revenue on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. LOCTI requires major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon Law ("OHL") to contribute two percent of their gross revenue generated in Venezuela from activities specified in the OHL. The contribution is based on the previous year's gross revenue and is due the following year. LOCTI requires that each company file a separate declaration stating how much has been contributed; however, waivers have been granted in the past to allow PDVSA to file a declaration on a consolidated basis covering all of its and its consolidating entities liabilities. PDVSA was granted a waiver to file its 2008 declaration on a consolidated basis, and based on this waiver, Petrodelta reversed $12.4 million, $6.2 million net of tax ($2.0 million net to our 32 percent interest) for contributions to LOCTI in the fourth quarter 2008. The waiver to file the declaration on a consolidated basis has to be requested each year and granted each year. Since Petrodelta expects PDVSA to continue requesting and receiving waivers, Petrodelta has not accrued a liability to LOCTI for the nine months ended September 30, 2009. The potential exposure to LOCTI for the nine months ended September 30, 2009 is $7.1 million, $3.6 million net of tax ($1.1 million net to our 32 percent interest).
Certain operating statistics for the three and nine months ended September 30, 2009 and 2008 for the Petrodelta fields operated by Petrodelta are set forth below. This information is provided at 100 percent. This information may not be representative of future results.

                                                      Three Months Ended                Nine Months Ended
                                                        September 30,                     September 30,
                                                     2009             2008             2009             2008
Oil production (million barrels)                       1.9             1.5               5.7             3.9
Natural gas production (billion cubic feet)            0.9             2.8               3.6             9.1
Barrels of oil equivalent                              2.1             2.0               6.3             5.5
Operating expense ($millions)                          9.1            20.1              41.6            53.3
Capital expenditures ($millions)                      20.6             9.1              69.6            18.5

Crude oil delivered from the Petrodelta fields to PDVSA is priced with reference to Merey 16 published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Market prices for crude oil of the type produced in the fields operated by Petrodelta averaged approximately $63.33 and $52.89 per barrel for the three and nine months ended September 30, 2009, respectively. Market prices for crude oil of the type produced in the fields operated by Petrodelta averaged approximately $85.21 and $82.66 per barrel net of the impact of the Law of Special Contribution to Extraordinary Prices at the Hydrocarbon International Market ("Windfall Profits Tax") implemented by the Venezuelan government, for the three and nine months ended September 30, 2008, respectively. The Windfall Profits Tax takes effect when the average price of oil exceeds $70 per barrel. The price for natural gas is $1.54 per thousand cubic feet. The decrease in gas production is due to reservoir management. Petrodelta's reporting and functional currency is the U.S. Dollar.
United States
Gulf Coast - West Bay
During the nine months ended September 30, 2009, operational activities in the West Bay prospect, one of the two initial prospects of the AMI, included the interpretation of 3-D seismic, site surveying, and preparation of engineering documents. Interpretation of 3-D seismic data on the West Bay project was completed in the second quarter 2009 and resulted in the identification of a revised set of drilling leads and prospects for the project. On July 14, 2009, we, along with our partner in the AMI, acquired 880 acres of shallow water offshore bay leases representing two separate tracts from the State of Texas General Land Office at a state lease sale for a total gross cost of $0.5 million. Acquisition of these two tracts completes the planned land acquisition activities on the project.
The AMI participants are currently evaluating the leads and prospects to determine priorities and drilling plans for the West Bay project. Depending on the selected drilling prospects and locations, the drilling may or may not require permit(s) from the U.S. Army Corps of Engineers - Galveston District ("Corps of Engineers"). We expect to firm up plans for initial drilling on the West Bay project during the fourth quarter 2009, with the expectation of initial drilling on the West Bay project in 2010. During the nine months ended September 30, 2009, we incurred $0.5 million for lease acquisition, surveying, permitting and site preparation and $1.4 million for seismic interpretation.
There is no expected remaining 2009 budget left for this project exclusive of the cost of preparations for drilling the initial well. Western United States - Antelope
On October 26, 2009, we, along with our partner in the JEDA, acquired 1,304 gross acres (782 acres net to us) of leases representing eight separate tracts from the State of Utah at a state lease sale for a total gross cost of $0.3 million.
During the nine months ended September 30, 2009, operational activities in the Antelope prospect focused on continuing leasing activities on private, Allottee, and tribal land, and surveying, preliminary engineering, permitting preparations, and conducting drilling operations on a deep natural gas test well (the Bar F #1-20-3-2 ["Bar F"]) that commenced drilling on June 15, 2009. The Bar F is a tight hole and is permitted to 18,000 feet. Drilling has been completed. The well reached total depth of 17,566 feet on October 8, 2009 and production casing has been run. Production testing of the well is expected to commence in November 2009 with the expectation that the testing program will be completed in early 2010. During the nine months ended September 30, 2009, we

incurred $17.6 million for drilling, lease acquisition, surveying, permitting and site preparation and $0.3 million for seismic program planning. The expected remaining 2009 budget for the Antelope project is $7.0 million.
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 ("DOGM"). On April 22, 2009, the Board of DOGM approved our proposal establishing 40 acre spacing for the eight shallow oil wells. We have signed a definitive Participation Agreement with a previously non-consenting third party industry partner to undertake a joint drilling project covering an area of 332 acres encompassing these eight wells. The industry partner will be the operator of the eight wells. Our average working interest in the eight wells will be approximately 43 percent. The Board of DOGM approved our request for forced pooling of the remaining non-consenting interests in the 332 acres at a hearing on October 28, 2009. On October 29, 2009, we received the drilling permits for all eight wells. The cost of the eight shallow oil wells will be borne by the parties participating in the drilling project proportionately to their working interest. We expect to commence drilling of the first two of the eight shallow oil wells in the fourth quarter 2009 with the remaining six wells expected to be drilled in late 2009 or early 2010. Budong-Budong Project, Indonesia ("Budong PSC") The interpretation of 650 kilometers of 2-D seismic was completed in the third quarter 2009. Current activities include well planning. It is expected that the first of two exploration wells will spud in the fourth quarter 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 nine months ended September 30, 2009, we incurred $0.1 million for surveying, permitting, engineering and well planning and $1.2 million for seismic processing and interpretation. The projected 2009 project expenditures (net to us including our funding commitment) for the exploratory well drilling are $8.1 million.
Dussafu Project, Gabon ("Dussafu PSC")
The processing of 650 kilometers of 2-D seismic and the reprocessing of 680 kilometers of vintage 2-D seismic was completed in the third quarter 2009. Current activities include the interpretation of the 2-D seismic to define the syn-rift potential similar to the Lucina and M'Bya fields and the pre-stack depth 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. Processing of the 3-D seismic should be completed in the fourth quarter 2009. We expect the seismic to mature the prospect inventory to make a decision in 2009 for a well in 2010. During the nine months ended September 30, 2009, we incurred $0.9 million for seismic processing and reprocessing. The projected remaining 2009 project expenditures (net to our working interest) for exploration activities are $1.4 million. Block 64 Project, Oman ("Block 64 EPSA") On April 11, 2009, we signed an Exploration and Production Sharing Agreement ("EPSA") with the Sultanate of Oman ("Oman") for the Al Ghubar / Qarn Alam license ("Block 64 EPSA"). We have a 100 percent working interest in the Block 64 EPSA during the exploration phase. Oman Oil Company has the option to back-in to up to a 20 percent interest in the Block 64 EPSA after the discovery of gas.
Block 64 EPSA is a newly-created block designated for exploration and production of non-associated gas and condensate which the Oman Ministry of Oil and Gas has carved out of the Block 6 Concession operated by Petroleum Development of Oman ("PDO"). PDO will continue to produce oil from several fields within the Block 64 EPSA area. The 3,867 square kilometer (955,600 acre) block is located in the gas and condensate rich Ghaba Salt Basin in close proximity to the Barik, Saih Rawl and Saih Nihayda gas and condensate fields. Current activities include the compilation of existing data, preparation for 3-D pre-stack depth migration reprocessing and initiation of a baseline environmental survey. During the nine months ended September 30, 2009, we incurred $2.4 million for costs associated with signing the license, including signature bonus and data compilation and $0.1 million for seismic processing and reprocessing. There is no expected remaining 2009 budget left for this project. We have an obligation to drill two wells over a three year period with a funding commitment of $22.0 million.

Other Exploration Projects
Relating to other projects, we incurred $2.1 million during the nine months ended September 30, 2009. We have budgeted to spend $1.6 million in leasehold acquisition costs, $4.1 million in seismic acquisition and processing costs and $2.8 million on other project related costs in 2009.
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, increase reserves and generate cash flow in the future. Capital Resources and Liquidity
Working Capital. Our capital resources and liquidity are affected by the ability of Petrodelta to pay dividends. On April 23, 2009, Petrodelta's board of directors declared a dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent interest). HNR Finance received the cash related to this dividend in the form of an advance dividend in October 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 most 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. See Item 1A - Risk Factors and Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2008 and Item 1A - Risk Factors in Part II of this Quarterly Report on Form 10-Q for a more complete description of the situation in Venezuela and other matters.
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 expenditures. 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 Petrodelta 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. 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:

                                                                       Nine Months Ended September 30,
                                                                        2009                     2008
                                                                               (in thousands)
Net cash provided by (used in) operating activities               $        (23,776 )       $         44,595
Net cash used in investing activities                                      (23,068 )                (11,611 )
Net cash used in financing activities                                       (1,332 )                (35,540 )

Net decrease in cash                                              $        (48,176 )       $         (2,556 )

At September 30, 2009, we had current assets of $67.7 million and current liabilities of $18.8 million, resulting in working capital of $48.9 million and a current ratio of 3.6:1. This compares with a working capital of $77.0 million and a current ratio of 3.0:1 at December 31, 2008. The decrease in working capital of $28.1 million was primarily due to a reduction in cash and cash equivalents, primarily for capital expenditures and operating expenses.
Cash Flow from Operating Activities. During the nine months ended September 30, 2009, net cash used in operating activities was approximately $23.8 million. During the nine months ended September 30, 2008, net cash provided by operating activities was approximately $44.6 million. The $68.4 million decrease was primarily due to repayments of advances to equity affiliate received by HNR Finance in the first quarter of 2008 and receipt of a dividend from unconsolidated equity affiliate.
Cash Flow from Investing Activities. During the nine months ended September 30, 2009, we had cash capital expenditures of approximately $22.7 million. Of the 2009 expenditures, $17.6 million was attributable to activity on the Antelope project, $2.4 million to Block 64 EPSA, $0.1 million to Budong PSC, $0.5 million to the West Bay project and $2.1 million to other projects. During the nine months ended September 30, 2008, we had cash capital expenditures of approximately $17.2 million. Of the 2008 expenditures, $3.0 million was attributable to activity on the West Bay project, $6.1 million to the Dussafu PSC, $2.7 million to the Antelope project, $3.3 million to the Harvest Hunter #1 project, $1.1 million to the Stark project and $1.0 million was attributable to other projects.
During the nine months ended September 30, 2008, $6.8 million of restricted cash used as collateral for loans which were repaid was returned to us. During the nine months ended September 30, 2009 and 2008, we incurred $0.4 million and $1.1 million, respectively, of investigatory costs related to various international and domestic exploration studies.
With the conversion to Petrodelta, Petrodelta's capital commitments will be determined by their business plan. Petrodelta's capital commitments will be funded by internally generated cash flow. Our expected capital expenditures will be funded through our existing cash balances, future Petrodelta dividends, . . .