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 20,620 barrels of oil per day during the six months ended June 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 taken actions to reduce both operating and capital expenditures. On April 23, 2009, Petrodelta's board of directors endorsed a 2009 budget for Petrodelta's Business Plan. The proposed 2009 budget has been submitted to Petrodelta's shareholders for approval. For 2009, the 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 presently non-producing Isleņo and El Salto fields. However, Petrodelta reduced its rig count to one drilling rig for most of the second quarter. Petrodelta began the appraisal and testing of its large portfolio of undeveloped resources in the second quarter of 2009. On April 30, 2009, Petrodelta began drilling in the El Salto field, which is currently undeveloped, and drilled two successful appraisal wells. The results of these wells are currently under evaluation by Petrodelta. Pilot production has recently commenced from one of the appraisal wells through temporary facilities. The second appraisal well is waiting on permits from the Ministry of the People's Power for Energy and Petroleum ("MENPET") for testing.
PDVSA purchases all of Petrodelta's oil production. PDVSA and its affiliates have reported shortfalls in meeting their cash requirements for operations and planned capital expenditures, and PDVSA has fallen behind in certain of its payment obligations to its contractors, including contractors engaged by PDVSA to provide services to Petrodelta. In addition, PDVSA has fallen behind in certain of its payment obligations to Petrodelta, which payments Petrodelta would otherwise use to pay its contractors. As a result, Petrodelta has experienced, and may continue to experience, difficulty in retaining contractors who provide services for Petrodelta's operations. We cannot provide any assurance as to whether or when PDVSA will become current on its payment obligations. Inability to retain contractors or to pay them on a timely basis is having an adverse effect on Petrodelta's operations and on Petrodelta's ability to carry out its business plan.
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.
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 Petroleos de Venezuela, S.A. ("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. For the six months ended June 30, 2009, Petrodelta's potential share for LOCTI contributions is $4.8 million, $2.4 million net of tax ($0.8 million net to our 32 percent interest). Although the OHL requires the recording of LOCTI contributions, in the second quarter 2009, Harvest management reversed the accrual, of which $2.4 million, $1.2 million net of tax ($0.4 million net to our 32 percent interest), related to the first quarter of 2009, as Harvest management expects that PDVSA will continue requesting and receiving waivers.
During the first quarter of 2009, PDVSA completed an actuarial study for their pension and retirement plan. This pension and retirement plan covers all PDVSA employees and mixed companies. In May 2009, upon completion of the review of this actuarial study, PDVSA sent a statement to Petrodelta for its respective costs associated with the pension and retirement plan. The pension adjustment was for past service costs covering the period from January 2008, when the Harvest Vinccler employees were migrated to PDVSA payroll, through May 2009. It is a non-recurring adjustment. Pension costs at June 30, 2009 reasonably reflect Petrodelta's employee demographic and plan conditions. The additional pension cost is not tax deductible until future periods when the pension is settled in cash. Petrodelta is not required to reimburse the pension costs to PDVSA until PDVSA pays the pension benefits to employees. Petrodelta recorded additional pension expense of $15.6 million ($5.0 million

net to our 32 percent interest) in the three month period ended June 30, 2009 based on the statement received. Following this true-up, future pension expense will be based on current service incurred.
In June 2009, CVP issued instructions to Petrodelta to set up a reserve within the equity section of the balance sheet for deferred tax assets. Although this reserve has no effect on Petrodelta's financial position, results of operation or cash flows, it has the effect of limiting future dividends to net income adjusted for deferred tax assets. Past dividends received from Petrodelta represented Petrodelta's net income as reported under International Financial Reporting Standards ("IFRS"). However, Article 307 of the Venezuelan Commerce Code states that distributions and payments of dividends must meet two conditions: 1) the retained earnings of the entity should be liquid and realizable, and 2) the entity has enough cash to pay and distribute the dividend. Deferred taxes are not liquid or realizable as cash until the items giving rise to the deferred tax are recognized in the entity's tax return. Therefore, CVP's instructions are to ensure future dividends are declared and paid as stated under Venezuelan law. Article 307 also states that shareholders are not obligated to restore dividends that have been distributed in good faith according to the entity's balances and sets the statute of limitations for an entity to claim restoration of dividends at five years.
Certain operating statistics for the three and six months ended June 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         Six Months Ended
                                                      June 30,                  June 30,
                                                  2009          2008        2009         2008
Oil production (million barrels)                    2.0          1.2          3.7         2.4
Natural gas production (billion cubic feet)         1.3          3.0          2.7         6.2
Barrels of oil equivalent                           2.2          1.7          4.2         3.5
Operating expense ($millions)                      20.8         18.9         32.5        33.2
Capital expenditures ($millions)                    7.7          7.3         37.4         9.4

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 $53.39 and $47.48 per barrel for the three and six months ended June 30, 2009, respectively. Market prices for crude oil of the type produced in the fields operated by Petrodelta averaged approximately $83.12 and $81.09 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 six months ended June 30, 2008, respectively. The price for natural gas is $1.54 per thousand cubic feet. The decrease in gas production is due to reservoir management.
United States
Gulf Coast - West Bay
During the six months ended June 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 project was completed in second quarter 2009 and resulted in the identification of a revised set of drilling leads and prospects for the project. The AMI participants are currently evaluating the leads and prospects to determine priorities and drilling plans for the project.
Based on the initial concepts for the project and prior to completion of the 3-D data interpretation, we submitted an Application to Install Structures to Drill and Produce Oil and Gas ("Application to Install Structures") with the U.S. Army Corps of Engineers - Galveston District ("Corps of Engineers") for the project on Dec 8, 2008. On April 7, 2009, the Corps of Engineers completed internal review of the permit application. Upon completion of the interpretation of the 3-D data and review of the revised drilling leads and prospects, and in consultation with the Corps of Engineers, we determined that the resulting changes in the scope and plans for the project resulted in our Application to Install Structures no longer being valid. As a result, we withdrew the Application to Install Structures in June 2009. As noted previously, the AMI participants are currently developing drilling plans for the project. Dependent on the selected drilling prospects and locations, the drilling may or may not require permits from the Corps of Engineers. We expect to firm up plans for initial drilling on the project during the third quarter 2009, with the expectation of initial drilling on the project in early 2010. During the six months ended June 30, 2009, we incurred $1.4 million for seismic interpretation.

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. 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
During the six months ended June 30, 2009, operational activities in the Antelope prospect primarily focused on continuing leasing activities, concentrating primarily on Allottee leases administered by the Bureau of Indian Affairs. Other operational activities included surveying, preliminary engineering, and permitting preparations for a deep natural gas test well that commenced drilling on June 15, 2009. On February 10, 2009, we filed a Request for Agency Action with the Board of the State of Utah Department of Natural Resources Division of Oil, Gas, and Mining ("DOGM") requesting establishment of 640 acre spacing of the lands associated with the deep natural gas test well. This proposal was accepted on May 27, 2009, by the DOGM. Also on February 10, 2009, we filed a Request for Agency Action with the Board of DOGM requesting Force Pooling of the non-consenting interests in the deep test well. We have since reached an agreement with the non-consenting interests and no hearing is necessary. On April 21, 2009, we filed an Application for Permit to Drill the deep natural gas test well with DOGM. The Permit to Drill was approved on May 27, 2009 and drilling of the Bar F #1-20-3-2 well ("Bar F") commenced on June 15, 2009. The Bar F is currently estimated to reach total depth in September 2009. During the six months ended June 30, 2009, we incurred $7.6 million for drilling, lease acquisition, surveying, permitting and site preparation and $0.3 million for seismic program planning. The expected remaining 2009 budget for this project is $9.5 million.
In December 2008, we filed Applications for Permits to Drill eight shallow oil wells with DOGM. On April 22, 2009, the Board of DOGM approved our proposal establishing 40 acre spacing for the eight shallow oil wells. We expect to receive the permits to drill the eight shallow oil wells in the near future. We are currently in negotiations with a previously non-consenting third party regarding a potential joint drilling project in the area covering these eight wells, and we believe that an agreement will be reached. If the negotiations on the joint project are successful, our average working interest in the eight wells will be approximately 33 percent. If these negotiations are successful, there will still be a requirement for Force Pooling of the remaining non-consenting interests in the eight proposed shallow oil wells. The Board of DOGM is scheduled to consider this request at a hearing in August 2009. 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 eight shallow oil wells in the next 12 months. Budong-Budong Project, Indonesia ("Budong PSC") The acquisition program of 650 kilometers of 2-D seismic was completed in 2008. Processing of this 2-D seismic data was completed in the second quarter 2009 and current activities include interpretation of the data and 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 six months ended June 30, 2009, we incurred $1.0 million for seismic processing and interpretation and began well planning. 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 acquisition of 650 kilometers of 2-D seismic was completed in 2008. Current activities include the continued processing 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 both the 2-D and 3-D seismic should be completed in the third quarter 2009. We expect the seismic to mature the prospect inventory to make a decision in 2009 for a well in 2010. During the six months ended June 30, 2009, we incurred $0.1 million related to Dussafu PSC commitment costs and $0.5 million for seismic processing and reprocessing.

The projected 2009 project expenditures (net to our working interest) for exploration activities are $2.0 million. This includes $1.8 million of well planning and long-lead well items if the decision is made to drill a well. 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 will have a 100 percent working interest in the EPSA during the exploration phase. Oman Oil Company will have the option to back-in to up to a 20 percent interest in the block 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. During the six months ended June 30, 2009, we incurred $2.2 million for costs associated with signing the license, including signature bonus and data compilation. The projected 2009 project expenditures for exploration activities are $2.3 million in 2009 for geological studies, reprocessing and interpretation of existing 3-D seismic and drilling preparations. 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 $1.4 million during the six months ended June 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.

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:

                                                         Six Months Ended June 30,
                                                           2009               2008
                                                               (in thousands)
 Net cash provided by (used in) operating activities   $     (19,847 )     $   64,304
 Net cash used in investing activities                       (11,651 )         (9,126 )
 Net cash used in financing activities                        (1,276 )        (18,815 )

 Net increase (decrease) in cash                       $     (32,774 )     $   36,363

At June 30, 2009, we had current assets of $82.6 million and current liabilities of $17.4 million, resulting in working capital of $65.2 million and a current ratio of 4.8:1. 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 $11.8 million was primarily due to a reduction in cash and cash equivalents, primarily for capital expenditures.
Cash Flow from Operating Activities. During the six months ended June 30, 2009, net cash used in operating activities was approximately $19.8 million. During the six months ended June 30, 2008, net cash provided by operating activities was approximately $64.3 million. The $84.1 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 six months ended June 30, 2009, we had cash capital expenditures of approximately $11.3 million. Of the 2009 expenditures, $7.6 million was attributable to activity on the Antelope project, $2.2 million to Block 64 EPSA, $0.1 million to the Dussafu PSC and $1.4 million to other projects. During the six months ended June 30, 2008, we had cash capital expenditures of approximately $11.2 million. Of the 2008 expenditures, $3.2 million was attributable to activity on the West Bay project, . . .