As an alternative to the use of the official exchange rate, an exemption under the Venezuelan Criminal Exchange Law for transactions in certain securities resulted in an indirect securities transaction market of foreign currency exchange, through which companies could obtain foreign currency legally without requesting it from CADIVI. Publicly available quotes did not exist for the securities transaction exchange rate but such rates could be obtained from brokers. Securities transaction markets were used to move financial securities into and out of Venezuela. In May 2010, the government of Venezuela effectively eliminated this indirect market of foreign currency exchange.exchange and established the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) for exchanging Bolivars. SITME’s purpose is to assist companies and individuals requiring foreign currency (U.S. Dollars) for the import of goods and services into Venezuela. SITME may also be used for buying or selling of Venezuela’s bonds. The elimination of the indirect market for foreign currency exchange and the establishment of SITME has not had, is not expected to have, an impact on our business in Venezuela.

     We record revenue for our U.S. oil and natural gas operations when we deliver our production to the customer and collectability is reasonably assured. Revenues from the production of oil and natural gas on properties in which we have joint ownership are recorded under the sales method. Differences between these sales and our entitled share of production are not significant.

     Cash equivalents include money market funds and short-term certificates of deposit with original maturity dates of less than three months.

     In MayJuly 2010, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-19,2010-20 Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses (“ASU 2010-20”), which is includedamends existing guidance by requiring more robust and disaggregated disclosures by an entity about the credit quality of its financing receivables and its allowance for credit losses. These disclosures will provide financial statement users with additional information about the nature of credit risks inherent in Accounting Standards Codification (“ASC”) under 830, “Foreign Currency” (“ASC 830”).financing receivables, how credit risks are analyzed and assessed in determining allowance for credit losses, and reasons for any changes made in allowance for credit losses. This update addressesis generally effective for interim and annual reporting periods ending on or after December 15, 2010; however, certain aspects of the multiple foreign currency exchange ratesupdate pertaining to activity that occurs during a reporting period are effective for interim and the impact of highly inflationary accounting in Venezuela. Since the U.S. Dollar is the functional andannual reporting currency for all of our Venezuela entities, the adoption of this update didperiods beginning on or after December 15, 2010. We do not expect ASU 2010-20 to have ana material impact on our consolidated financial position, results of operations or cash flows.

Long-term debt consists of the following (in thousands):

     On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible notes. Under the terms of the notes, interest is payable semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2010. The senior convertible notes will mature on March 1, 2013, unless earlier redeemed, repurchased or converted. The notes are convertible into shares of our common stock at a conversion rate of 175.2234 shares of common stock per $1,000 principal amount of senior convertible notes, equivalent to a conversion price of approximately $5.71 per share of common stock. The senior convertible notes are our general unsecured obligations, ranking equally with all of our other unsecured senior indebtedness, if any, and senior in right of payment to any of our subordinated indebtedness, if any. The senior convertible notes are also redeemable in certain circumstances at our option and may be repurchased by us at the purchaser’s option in connection with occurrence of certain events. The net proceeds of the offering to us were approximately $30.0 million, after deducting underwriting discounts, commissions and estimated offering expenses. Financing costs of $2.3$2.1 million associated with this debt offering are being amortized over the remaining life of the debt. These costs are capitalized in Other Assets at JuneSeptember 30, 2010.

     We have incurred $2.9 million in costs related to ongoing negotiations for a future financing. If the financing is successful, these costs will be amortized over the life of the financial instrument. These costs are capitalized in Other Assets at JuneSeptember 30, 2010.

     Liquidity– Based on our cash balance of $31.5$13.3 million at JuneSeptember 30, 2010, we will require additional funds in order to fund our future operating and capital expenditures. As we disclosed in previous filings, our cash is being used to fund oil and gas exploration, appraisal and development projects and to a lesser extent, general and administrative costs. Currently, our primary source of cash is dividends from Petrodelta and to a lesser extent, production from the Monument Butte Extension and Lower Green River/Upper Wasatch projects. In MayAugust 2010, Petrodelta declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest)., which was received on October 22, 2010. However, there is no certainty that Petrodelta will pay additional dividends in 2010 or 2011. Our lack of cash flow and the anticipated level of cash dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance adequate financing can

     On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange Agreement, which established new exchange rates for the Bolivar/U.S. Dollar currencies that entered into force on January 11, 2010. SeeNote 2 – Summary of Significant Accounting Policies, Reporting and Functional Currency. At December 31, 2009, Petrodelta revaluedremeasured the appropriate monetary accounts that were Bolivar-denominated toassets and liabilities at the official exchange rate of 2.15 Bolivars per U.S. Dollars,Dollar, Petrodelta’s functional and reporting currency,currency. On January 31, 2010, Petrodelta remeasured the appropriate monetary assets and liabilities at the publishednew official exchange rate of 4.30 Bolivars per U.S. Dollar. In general,Petrodelta recorded a $0.1 million remeasurement loss and a $120.5 million remeasurement gain, before tax, during the three and nine months ended September 30, 2010, respectively, on revaluation of monetary assets based inand liabilities. The remeasurement gain for Petrodelta was calculated as the difference between the old official exchange rate of 2.15 Bolivars would be revalued to a lowerper U.S. Dollar balance on Petrodelta’s balance sheet resulting in a currencyand the new official exchange rate loss on the income statement, and monetary liabilities based inof 4.30 Bolivars would revalue to a lowerper U.S. Dollar balance in Petrodelta’s balance sheet resulting in a gain on exchange rates in the income statement.dollar. The primary factor in Petrodelta’s gain on currency exchange rates is that Petrodelta had substantially higher Bolivar denominated monetary liabilities than Bolivar denominated monetary assets. During the three and six months ended JuneAt September 30, 2010, Petrodelta recorded a $1.9 million and $120.7 million, before tax, ($0.6 million and $38.6 million, before tax, net to our 32 percent interest) remeasurement gain on revaluation ofthe balances in Petrodelta’s Bolivar denominated monetary assets and liabilities respectively.

     Petrodelta’s reporting and functional currency is the U.S. Dollar. HNR Finance owns a 40 percent interest in Petrodelta. Petrodelta’s financial information is prepared in accordance with IFRS, which we have adjusted to conform to GAAP. All amounts through Net Income (Loss) represent 100 percent of Petrodelta. Summary financial information has been presented below at JuneSeptember 30, 2010 and December 31, 2009 and for the three and sixnine months ended JuneSeptember 30, 2010 and 2009 (in thousands):

     In 2008, we acquired a 47 percent interest in the Budong-Budong Production Sharing Contract (“Budong PSC”) by committing to fund the first phase of the exploration program including the acquisition of 2-D seismic and drilling of the first two exploration wells. This commitment is capped at $17.2 million. The commitment is comprised of $6.5 million for the acquisition of seismic and $10.7 million for the drilling of the first two exploratory wells. After the commitment of each component is met, all subsequent costs will be shared by the parties in proportion to their ownership interests. The $6.5 million carry obligation for the 2-D seismic acquisition was met in December 2008. Prior to drilling the first exploration well, subject to the estimated cost of that well, our partner will have a one-time option to increase the level of the carried interest to a maximum of $20.0 million, and as compensation for the increase, we will increase our participation to a maximum of 54.65 percent. This equates to a total carried cost for the farm-in of $9.1 million. Our partner intends to exercise their option to increase the level of the carried interest and is currently reviewing the amount of the increase. Our partner will be the operator through the exploration phase as required by the terms of the Budong PSC. We will have control of major decisions and financing for the project with an option to become operator if approved by BP Migas, Indonesia’s oil and gas regulatory authority, in the subsequent development and production phase.

     The commitment to fund the first phase of the exploration program is capped at $17.2 million. The commitment is comprised of $6.5 million for the acquisition of seismic and $10.7 million for the drilling of the first two exploratory wells. After the commitment of each component is met, all subsequent costs will be shared by the parties in proportion to their ownership interests. Prior to drilling the first exploration well, subject to the estimated

     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 Block 64 EPSA area. The 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. We have an obligation to drill two wells over a three-year period with a funding commitment of $22.0 million. We expect to drill the first of the two exploratory wells in the second half of 2011. Current activities include geological studies, baseline environmental and social study and 3-D pre-stack depth migration reprocessing of approximately 1,000 square kilometers of existing 3-D seismic data. The Block 64 EPSA represents $4.2 million and $3.8 million of unproved oil and gas properties as of JuneSeptember 30, 2010 and December 31, 2009, respectively.

Western United States –— Antelope

     OnIn July 28, 2010, our Board of Directors approvedwe executed a farm-out agreement with the private third party in the JEDA for the acquisition of an incremental 10 percent interest in the Antelope Project from our partner through a farmout.with an effective date of July 1, 2010. This acquisition includes all leases, the Mesaverde, Gas Exploration and Appraisal Project and the Lower Green River/Upper Wasatch Oil Delineation and Development Project.Project (“Lower Green River/Upper Wasatch”) and the Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”). The acquisition excludes the initial eight wells previously drilled in the Monument Butte Extension Appraisal and Development Project.Extension. Total consideration for the incremental 10 percent interest is $20.0 million, of which (1) $3.0 million was paid on August 2, 2010 (closing date),(the closing date of the acquisition); (2) $3.0 million to be paidused as a credit against future joint interest billings or if joint interest billings do not accumulate to $3.0 million by October 1, 2010, at the sole election of the private third party, the balance is to be paid by us within 15 days of receipt of written request from the private third party; and (3) a capped $14.0 million carry of a portion of our partner’s exploration and development cost obligations in the upcoming Lower Green River/Upper Wasatch and Monument Butte Extension drilling programs in the Antelope project. On October 1, 2010, the private third party elected to receive in cash the remaining balance of the joint interest billing credit of $2.4 million. At September 30, 2010, the outstanding balance on the $14.0 million exploration and development cost obligation carry is $12.7 million. Based on current plans, we anticipate the full carry obligation will be met in the first half of 2011. This acquisition increases our ownership in the Antelope project to 70 percent.

     During the sixnine months ended JuneSeptember 30, 2010, we had cash capital expendituresexpenditure of $1.8$5.3 million for leasing activities on the Antelope prospect. TheWe do not anticipate significant leasing activity in the remaining 2010 budget for leasing activities on the Antelope prospect is $8.3 million.three months of 2010. Drilling, completion and testing activities are currently in progress on threetwo separate projects on the Antelope prospect in Duchesne and Uintah Counties, Utah.

     A second project has also been pursued inIn the first quarter of 2010, we completed the drilling and testing of the Bar F exploration well.#1-20-3-2 (“Bar F”) in the Mesaverde formation. After completion of the initial testing program on the Mesaverde deep gas as described above,formation, we moved uphole in the same well to test multiple oil bearing intervals at depths from 8,200 feet to 9,500 feet in the

     Our Board of Directors has authorizedWe began a five-well Lower Green River/Upper Wasatch delineation and development drilling program which is planned to take place beginning in the third quarter of 2010 at a capital cost of $21.2 million (net to Harvest).2010. This five-well program wouldis planned to further delineate and appraise the extent of the Lower Green River/Upper Wasatch discovery made in the Bar F, and is also expected to establish additional production from the Lower Green River/Upper Wasatch reservoirs in at least some of the five appraisal wells. The Lower Green River/Upper Wasatch formations are productive in the Altamont/Bluebell oil field approximately six miles north of the Bar F well. Operational activities during the sixnine months ended JuneSeptember 30, 2010 on the five well Lower Green River/Upper Wasatch delineation program included preparations and well planning and initial drilling and completion activities for the drilling program to bethat is being implemented in the second half of 2010. The first well of the five well delineation program, the Kettle #1-10-3-1 (“Kettle”), spud on July 14, 2010 and is drilling as of August 9, 2010. The five wells are planned to be drilled back-to-back.

     During the sixnine months ended JuneSeptember 30, 2010, we had cash capital expendituresexpenditure of $0.1$3.2 million in well planning.planning and $0.1 million for engineering costs. The remaining 2010 budgetforecast of expenditures for the Lower Green River/Upper Wasatch delineation and development drilling program is $21.0$17.0 million.

     The Monument Butte Extension Appraisal and Development Project (“Monument Butte Extension”) was initiated with an eight-well appraisal and development drilling program to produce oil and natural gas from the Green River formation on the southern portion of our Antelope land position. The Monument Butte Extension is non-operated, and we hold a 43 percent working interest in the initial eight wells. The parties participating in the wells formed a 320 acre AMI, which contained the initial eight drilling locations. Operational activities during the three months ended March 31, 2010 on the Monument Butte Extension focused on drilling and completion activities on the original eight-well program. As of March 31, 2010, all eight wells had been drilled and were on production. Operational activities on these eight wells during the threenine months ended JuneSeptember 30, 2010 consisted of routine production operations from the wells. As of JuneSeptember 30, 2010, the eight producing wells have produced approximately 70,00086,000 barrels of oil (net to Harvest). The eight wells combined are currently producing slightly over 200129 BOPD (net to Harvest). During the sixnine months ended JuneSeptember 30, 2010, we had cash capital expendituresexpenditure of $3.2$3.3 million in well costs. There is no remaining 2010 budgetforecast of expenditures for the initial eight-well program.

     Our Board of Directors has authorized sixFour additional wells in the Monument Butte Extension appraisal and development wells planned to bewere drilled beginning induring the third quarter of 2010. These four wells are the first of a planned six well expansion program being conducted as a follow up to the

     In August 2007,On September 1, 2010, Mr. Karl L. Nesselrode, Vice President, EngineeringAngel Urdaneta was hired by Harvest Vinccler and Business Development of Harvest, accepted a long-term secondmentseconded to Petrodelta as its Operations and Technical Manager. In July 2010, Mr. Nesselrode’s secondment ended, andUrdaneta replaced Mr. G. Michael Morgan, Vice President of Business Development of Harvest, willwho was temporarily replace Mr. Nesselrode asperforming the duties of Petrodelta’s Operations and Technical Manager. Under the terms of the conversion contract, HNR Finance has the right to nominate the Operations and Technical Manager. Mr. Morgan will remain an officer of Harvest.

     Working Capital.Our capital resources and liquidity are affected by the ability of Petrodelta to pay dividends. We expect to receive future dividends from Petrodelta; however, we expect the amount of any future dividends to be lowerthat in the near term as Petrodelta reinvestswill reinvest most of its earnings into the company in support of its drilling and appraisal activities. At CVP’s instructions, Petrodelta has set up a reserve within the equity section of its balance sheet for deferred tax assets. The setting up of the reserve had no effect on Petrodelta’s financial position, results of operationoperations or cash flows. However, the new reserve could have a negative impact on the amount of dividends received in the future. It iswas anticipated that all available cash generated during 2010, and is still