Attached files
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EX-31.2 - EX-31.2 - HARVEST NATURAL RESOURCES, INC. | h82145exv31w2.htm |
EX-32.2 - EX-32.2 - HARVEST NATURAL RESOURCES, INC. | h82145exv32w2.htm |
EX-32.1 - EX-32.1 - HARVEST NATURAL RESOURCES, INC. | h82145exv32w1.htm |
EX-31.1 - EX-31.1 - HARVEST NATURAL RESOURCES, INC. | h82145exv31w1.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
þ | Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the Quarterly Period Ended March 31, 2011 or
o | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
for the transition period from _________ to _________
Commission File No. 1-10762
Harvest Natural Resources, Inc.
(Exact Name of Registrant as Specified in Its Charter)
Delaware (State or Other Jurisdiction of Incorporation or Organization) |
77-0196707 (IRS Employer Identification No.) |
|
1177 Enclave Parkway, Suite 300 | ||
Houston, Texas (Address of Principal Executive Offices) |
77077 (Zip Code) |
(281) 899-5700
(Registrants Telephone Number, Including Area Code)
(Registrants Telephone Number, Including Area Code)
Not Applicable
(Former name, former address and former fiscal year, if changed since last report)
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files).
Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a smaller reporting company. See the definition of large accelerated filer, accelerated
filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer o | Accelerated Filer þ | Non-Accelerated Filer o | Smaller Reporting Company o | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act).
Yes o No þ
At April 29, 2011, 33,974,691 shares of the Registrants Common Stock were outstanding.
HARVEST NATURAL RESOURCES, INC.
FORM 10-Q
TABLE OF CONTENTS
2
Table of Contents
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
ASSETS |
||||||||
CURRENT ASSETS: |
||||||||
Cash and cash equivalents |
$ | 24,664 | $ | 58,703 | ||||
Restricted cash |
4,490 | | ||||||
Accounts and notes receivable, net: |
||||||||
Oil and gas revenue receivable |
3,724 | 1,907 | ||||||
Dividend receivable equity affiliate |
12,200 | | ||||||
Joint interest and other |
4,369 | 2,325 | ||||||
Note receivable |
3,255 | 3,420 | ||||||
Advances to equity affiliate |
1,852 | 1,706 | ||||||
Assets held for sale (See Note 3) |
102,544 | 88,774 | ||||||
Prepaid expenses and other |
2,193 | 4,793 | ||||||
TOTAL CURRENT ASSETS |
159,291 | 161,628 | ||||||
OTHER ASSETS |
2,293 | 2,477 | ||||||
INVESTMENT IN EQUITY AFFILIATES |
292,564 | 287,933 | ||||||
PROPERTY AND EQUIPMENT: |
||||||||
Oil and gas properties (successful efforts method) |
46,589 | 34,679 | ||||||
Other administrative property |
3,250 | 3,209 | ||||||
49,839 | 37,888 | |||||||
Accumulated depletion, depreciation and amortization |
(1,805 | ) | (1,682 | ) | ||||
48,034 | 36,206 | |||||||
$ | 502,182 | $ | 488,244 | |||||
LIABILITIES AND EQUITY |
||||||||
CURRENT LIABILITIES: |
||||||||
Joint interest and royalty payable |
$ | 1,771 | $ | 675 | ||||
Accounts payable, trade and other |
3,553 | 2,530 | ||||||
Accounts payable carry obligation |
4,910 | 8,395 | ||||||
Accrued expenses |
24,284 | 15,087 | ||||||
Liabilities held for sale (See Note 3) |
599 | 663 | ||||||
Accrued interest |
237 | 896 | ||||||
Income taxes payable |
283 | 72 | ||||||
TOTAL CURRENT LIABILITIES |
35,637 | 28,318 | ||||||
OTHER LONG-TERM LIABILITIES |
2,268 | 1,834 | ||||||
LONG-TERM DEBT |
81,775 | 81,237 | ||||||
COMMITMENTS AND CONTINGENCIES (See Note 6) |
| | ||||||
EQUITY |
||||||||
STOCKHOLDERS EQUITY: |
||||||||
Preferred stock, par value $0.01 a share; authorized 5,000 shares;
outstanding, none |
| | ||||||
Common stock, par value $0.01 a share; authorized 80,000 shares at March 31,
2011 and December 31, 2010, respectively; issued 40,195 shares and 40,103
shares at March 31, 2011 and December 31, 2010, respectively |
401 | 401 | ||||||
Additional paid-in capital |
231,890 | 230,362 | ||||||
Retained earnings |
142,354 | 141,584 | ||||||
Treasury stock, at cost, 6,475 shares at March 31, 2011 and December 31, 2010,
respectively |
(65,543 | ) | (65,543 | ) | ||||
TOTAL HARVEST STOCKHOLDERS EQUITY |
309,102 | 306,804 | ||||||
NONCONTROLLING INTEREST |
73,400 | 70,051 | ||||||
TOTAL EQUITY |
382,502 | 376,855 | ||||||
$ | 502,182 | $ | 488,244 | |||||
See accompanying notes to consolidated financial statements.
3
Table of Contents
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
(in thousands, except per share data) | ||||||||
EXPENSES |
||||||||
Depreciation and amortization |
$ | 124 | $ | 101 | ||||
Exploration expense |
1,189 | 1,246 | ||||||
General and administrative |
6,707 | 5,317 | ||||||
Taxes other than on income |
349 | 300 | ||||||
8,369 | 6,964 | |||||||
LOSS FROM OPERATIONS |
(8,369 | ) | (6,964 | ) | ||||
OTHER NON-OPERATING INCOME (EXPENSE) |
||||||||
Investment earnings and other |
145 | 131 | ||||||
Interest expense |
(2,212 | ) | (416 | ) | ||||
Other non-operating expenses |
(431 | ) | | |||||
Loss on exchange rates |
(11 | ) | (1,527 | ) | ||||
(2,509 | ) | (1,812 | ) | |||||
LOSS FROM CONSOLIDATED COMPANIES CONTINUING OPERATIONS
BEFORE INCOME TAXES |
(10,878 | ) | (8,776 | ) | ||||
INCOME TAX EXPENSE (BENEFIT) |
222 | (19 | ) | |||||
LOSS FROM CONSOLIDATED COMPANIES CONTINUING OPERATIONS |
(11,100 | ) | (8,757 | ) | ||||
NET INCOME FROM UNCONSOLIDATED EQUITY AFFILIATES |
18,104 | 38,367 | ||||||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS |
7,004 | 29,610 | ||||||
DISCONTINUED OPERATIONS |
(2,885 | ) | 2,315 | |||||
NET INCOME (LOSS) |
4,119 | 31,925 | ||||||
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST |
3,349 | 7,335 | ||||||
NET INCOME ATTRIBUTABLE TO HARVEST |
$ | 770 | $ | 24,590 | ||||
NET INCOME ATTRIBUTABLE TO HARVEST PER COMMON SHARE (See Note 2 Summary of Significant Accounting Policies, Earnings Per Share): |
||||||||
Basic |
$ | 0.02 | $ | 0.74 | ||||
Diluted |
$ | 0.02 | $ | 0.64 | ||||
See accompanying notes to consolidated financial statements.
4
Table of Contents
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended March 31, | ||||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
Net Income |
$ | 4,119 | $ | 31,925 | ||||
Adjustments to reconcile net income to net cash used in operating
activities: |
||||||||
Depletion, depreciation and amortization |
934 | 566 | ||||||
Impairment
of long-lived assets |
1,440 | | ||||||
Amortization of debt financing costs |
270 | 108 | ||||||
Amortization of discount on debt |
538 | | ||||||
Net income from unconsolidated equity affiliates |
(18,104 | ) | (38,367 | ) | ||||
Non-cash compensation related charges |
1,114 | 853 | ||||||
Changes in Operating Assets and Liabilities: |
||||||||
Accounts and notes receivable |
(3,696 | ) | 4,616 | |||||
Advances to equity affiliate |
(146 | ) | 1,066 | |||||
Prepaid expenses and other |
2,600 | 350 | ||||||
Revenue and royalty payable |
1,096 | 134 | ||||||
Accounts payable |
1,023 | 1,405 | ||||||
Accrued expenses |
2,071 | 423 | ||||||
Accrued interest |
(925 | ) | (4,383 | ) | ||||
Other long-term liabilities |
434 | 370 | ||||||
Income taxes payable |
211 | (490 | ) | |||||
NET CASH USED IN OPERATING ACTIVITIES |
(7,021 | ) | (1,424 | ) | ||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
Additions of property and equipment |
(8,361 | ) | (13,495 | ) | ||||
Additions to assets held for sale |
(15,633 | ) | | |||||
Proceeds from sale of equity affiliates |
1,273 | | ||||||
Increase in restricted cash |
(4,490 | ) | (1,000 | ) | ||||
Investment costs |
(34 | ) | (1,656 | ) | ||||
NET CASH USED IN INVESTING ACTIVITIES |
(27,245 | ) | (16,151 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
Net proceeds from issuances of common stock |
416 | | ||||||
Proceeds from issuance of long-term debt |
| 32,000 | ||||||
Financing costs |
(189 | ) | (2,627 | ) | ||||
NET CASH PROVIDED BY FINANCING ACTIVITIES |
227 | 29,373 | ||||||
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS |
(34,039 | ) | 11,798 | |||||
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD |
58,703 | 32,317 | ||||||
CASH AND CASH EQUIVALENTS AT END OF PERIOD |
$ | 24,664 | $ | 44,115 | ||||
Supplemental Schedule of Noncash Investing and Financing Activities:
During the three months ended March 31, 2010, some of our employees elected to pay withholding
tax on restricted stock grants on a cashless basis which resulted in 20,831 shares being added to
treasury stock at cost.
See accompanying notes to consolidated financial statements.
5
Table of Contents
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2011 and 2010 (unaudited)
Note 1 Organization
Interim Reporting
In our opinion, the accompanying unaudited consolidated financial statements contain all
adjustments necessary to present fairly the financial position as of March 31, 2011, and the
results of operations and cash flows for the three months ended March 31, 2011 and 2010. The
unaudited consolidated financial statements are presented in accordance with the requirements of
Form 10-Q and do not include all disclosures normally required by accounting principles generally
accepted in the United States of America (GAAP). Reference should be made to our consolidated
financial statements and notes thereto included in our Annual Report on Form 10-K for the year
ended December 31, 2010 which include certain definitions and a summary of significant accounting
policies and should be read in conjunction with this Quarterly Report on Form 10-Q. The results of
operations for any interim period are not necessarily indicative of the results of operations for
the entire year.
Organization
Harvest Natural Resources, Inc. (Harvest) is an independent energy company engaged in the
acquisition, exploration, development, production and disposition of oil and natural gas properties
since 1989, when it was incorporated under Delaware law.
We have significant interests in the Bolivarian Republic of Venezuela (Venezuela). Our
Venezuelan interests are owned through HNR Finance, B.V. (HNR Finance). Our ownership of HNR
Finance is through several corporations in all of which we have direct controlling interests.
Through these corporations, we indirectly own 80 percent of HNR Finance and our partner, Oil & Gas
Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de
Inversiones y Construcciones Clerico, C.A. (Vinccler), indirectly owns the remaining 20 percent
interest in HNR Finance. HNR Finance owns 40 percent of Petrodelta, S.A. (Petrodelta). As we
indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in
Petrodelta, and Vinccler indirectly owns eight percent. Corporación Venezolana del Petroleo S.A.
(CVP) owns the remaining 60 percent of Petrodelta. Petrodelta is governed by its own charter and
bylaws and operates a portfolio of properties in eastern Venezuela including large proven oil
fields as well as properties with substantial opportunities for both development and exploration.
HNR Finance has a direct controlling interest in Harvest Vinccler S.C.A. (Harvest Vinccler).
Harvest Vincclers main business purposes are to assist us in the management of Petrodelta and in
negotiations with Petroleos de Venezuela S.A. (PDVSA). We do not have a business relationship
with Vinccler outside of Venezuela.
In addition to our interests in Venezuela, we have exploration acreage in the Gulf Coast
Region of the United States, mainly onshore in West Sulawesi in the Republic of Indonesia
(Indonesia), offshore of the Republic of Gabon (Gabon), onshore in the Sultanate of Oman
(Oman), and offshore of the Peoples Republic of China (China). Until March 1, 2011, pending
closing of the sale for our Utah Operations (see Note 3 Dispositions), we had developed acreage
in the Antelope project in the Western United States in the Monument Butte Extension Appraisal and
Development Project (Monument Butte Extension) and Lower Green River/Upper Wasatch Oil
Delineation and Development Project (Lower Green River/Upper Wasatch) where we had established
production. See Note 10 United States, Note 11 Indonesia, Note 12 Gabon and Note 13 Oman
and Note 14 China.
Note 2 Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of all wholly-owned and
majority-owned subsidiaries. All intercompany profits, transactions and balances have been
eliminated.
6
Table of Contents
Reporting and Functional Currency
The United States Dollar (U.S. Dollar) is the reporting and functional currency for all of
our controlled subsidiaries and Petrodelta. Amounts denominated in non-U.S. Dollar currencies are
re-measured into U.S. Dollars, and all currency gains or losses are recorded in the consolidated
statement of operations. We attempt to manage our operations in such a manner as to reduce our
exposure to foreign exchange losses. However, there are many factors that affect foreign exchange
rates and resulting exchange gains and losses, many of which are beyond our influence.
On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange
Agreement which eliminated the 2.60 Venezuelan Bolivars (Bolivars) per U.S. Dollar exchange rate
for purchases, the 2.5935 Bolivars per U.S. Dollar exchange rates for the sale of foreign currency,
and the Central Banks entitlement to require the sale of foreign currency at specific rates with
an effective date of January 1, 2011. The elimination of the 2.60 Bolivars per U.S. Dollar
exchange rate for purchases is not expected to have an impact on our business in Venezuela. Since
all sales of foreign currency will be at the 4.2893 Bolivars per U.S. Dollar exchange rate, we will
not be required to pay a financing fee resulting from blended exchange rates for the purchase of
foreign currency.
In May 2010, the government of Venezuela established the Sistema de Transacciones con Títulos
en Moneda Extranjera (SITME) for exchanging Bolivars. SITMEs 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 Venezuelas bonds. The establishment
of SITME has not had, nor is it expected to have, an impact on our business in Venezuela.
Harvest Vinccler does not have currency exchange risk other than the official prevailing
exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S.
Dollar). However, during the three months ended March 31, 2011, Harvest Vinccler exchanged
approximately $0.3 million through SITME and received an average exchange rate of 5.18 Bolivars per
U.S. Dollar. During the three months ended March 31, 2010, no such exchanges took place. Harvest
Vinccler currently does not have any U.S. Dollars pending government approval for settlement for
Bolivars at the official exchange rate or the SITME exchange rate.
The monetary assets that are exposed to exchange rate fluctuations are cash, accounts
receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed
to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All
monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the
official Bolivar exchange rate. At March 31, 2011, the balances in Harvest Vincclers
Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate
changes are BsF 3.0 million and BsF 3.5 million, respectively.
See Note 9 Investment in Equity Affiliates Petrodelta, S.A. for a discussion on the
effects of the exchange agreements on Petrodeltas business.
Revenue Recognition
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 and Cash Equivalents
Cash equivalents include money market funds and short term certificates of deposit with
original maturity dates of less than three months.
Restricted Cash
Restricted cash is classified as current or non-current based on the terms of the agreement.
Restricted cash at March 31, 2011 represents cash held in a U.S. bank used as collateral for a
standby letter of credit issued in support of the contract for the drilling unit to be used to
drill the Ruche Marin-A exploratory well on the Dussafu Marin Permit (Dussafu PSC) (see Note 12
Gabon).
7
Table of Contents
Financial Instruments
Our financial instruments that are exposed to concentrations of credit risk consist primarily
of cash and cash equivalents, accounts receivable, and notes payable. Cash and cash equivalents
are placed with commercial banks with high credit ratings. This diversified investment policy
limits our exposure both to credit risk and to concentrations of credit risk.
Total long-term debt at March 31, 2011 and December 31, 2010 consisted of $32 million of
fixed-rate unsecured senior convertible notes maturing in 2013 unless earlier redeemed, purchased
or converted and $60 million of fixed-rate unsecured term loan facility maturing in 2012.
Notes Receivable
Notes receivable relate to prospect leasing cost financing arrangements, bear interest and can
have due dates that are less than one year or more than one year. Amounts outstanding under the
notes bear interest at a rate based on the current prime rate and are recorded at face value.
Interest is recognized over the life of the note. We may or may not require collateral for the
notes.
Each note is analyzed to determine if it is impaired pursuant to Accounting Standards Updates
(ASU) 2010-20. A note is impaired if it is probable that we will not collect all principal and
interest contractually due. We do not accrue interest when a note is considered impaired. All
cash receipts on impaired notes are applied to reduce the accrued interest on the note until the
interest is made current and, thereafter, applied to reduce the principal amount of such notes.
At March 31, 2011 and December 31, 2010, note receivable plus accrued interest was
approximately $3.3 million and $3.4 million, respectively, and considered to be fully recoverable.
With the recent announcement of the sale of our Antelope project, it is expected that the note
receivable plus accrued interest will be settled upon closing of the announced sale transaction.
Other Assets
At March 31, 2011, other assets consist of investigative costs of $0.3 million associated with
new business development projects and deferred financing costs of $2.0 million. The investigative
costs are reclassified to oil and natural gas properties or expensed depending on managements
assessment of the likely outcome of the project. During the three months ended March 31, 2011, no
investigative costs related to new business development were reclassified to exploration expense.
At December 31, 2010, other assets consisted of investigative costs of $0.3 million associated with
new business development projects and deferred financing costs of $2.2 million.
Deferred financing costs relate to specific financing and are amortized over the life of the
financing to which the costs relate. See Note 4 Long-Term Debt.
Investment in Equity Affiliates
Investments in unconsolidated companies in which we have less than a 50 percent interest and
have significant influence are accounted for under the equity method of accounting. Investment in
Equity Affiliates is increased by additional investments and earnings and decreased by dividends
and losses. We review our Investment in Equity Affiliates for impairment whenever events and
circumstances indicate a decline in the recoverability of its carrying value.
There are many factors to consider when evaluating an equity investment for possible
impairment. Currency devaluations, inflationary economies and cash flow analysis are some of the
factors we consider in our evaluation for possible impairment. At March 31, 2011 and December 31,
2010, there were no events that caused us to evaluate our investment in Petrodelta for impairment.
Property and Equipment
We use the successful efforts method of accounting for oil and gas properties.
8
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Suspended Exploratory Drilling Costs
Mesaverde
At March 31, 2011 and December 31, 2010, assets held for sale included capitalized suspended
exploratory drilling costs of $16.5 million. The $16.5 million of suspended exploratory drilling
costs relates to drilling in the Mesaverde formation in the Bar F #1-20-3-2 (Bar F). The
Mesaverde Gas Exploration and Appraisal Project (Mesaverde) targeted the Mesaverde formation in
the Uintah Basin of Utah. Testing focused on the evaluation of the natural gas potential of the
Mesaverde tight gas reservoir over a prospective interval from 14,000 to 17,400 feet. While the
results to date have not definitively determined the commerciality of stand-alone development of
the Mesaverde in the current gas price environment, we believe that the test results confirm that
the Mesaverde formation exhibits sufficient quantities of hydrocarbons and reservoir over-pressure
to justify potential development. See Note 10 United States Operations, Western United States
Antelope.
Budong PSC
At March 31, 2011, oil and gas properties included capitalized suspended exploratory drilling
costs of $13.2 million related to drilling in the Budong-Budong Production Sharing Contract
(Budong PSC) of the Lariang-1 (LG-1) well. The LG-1 targeted the Miocene and Eocene reservoirs
to a planned depth of approximately 7,200 feet. The LG-1 was drilled to a total depth of 5,311
feet and encountered multiple oil and gas shows within the secondary Miocene objective.
At a depth of 5,300 feet, losses of heavy drilling
mud into the formation were encountered which, when coupled with the very high formation pressures,
led the partners to the decision to discontinue operations and plug and abandon the well for safety
reasons on April 8, 2011. The primary Eocene targets had not been
reached, as the well was planned for a total measured depth of
approximately 7,200 feet. While the results to date have not
definitively determined the commerciality of development of the LG-1, we believe that the well
results confirm that the Miocene formation exhibits sufficient quantities of hydrocarbons to
justify potential development pending further appraisal. See Note 11 Indonesia.
Capitalized Interest
We capitalize interest costs for qualifying oil and gas properties. The capitalization period
begins when expenditures are incurred on qualified properties, activities begin which are necessary
to prepare the property for production and interest costs have been incurred. The capitalization
period continues as long as these events occur. The average additions for the period are used in
the interest capitalization calculation. During the three months ended March 31, 2011, we
capitalized interest costs of $0.8 million for qualifying oil and gas property additions. During
the three months ended March 31, 2010, we did not capitalize any interest cost.
Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the measurement date.
At March 31, 2011 and December 31, 2010, cash and cash equivalents include $14.9 million and
$51.0 million, respectively, in a money market fund comprised of high quality, short term
investments with minimal credit risk which are reported at fair value. The fair value measurement
of these securities is based on quoted prices in active markets (level 1 input) for identical
assets. The estimated fair value of our senior convertible notes based on observable market
information (level 2 input) as of March 31, 2011 and December 31, 2010 was $62.3 million and $61.7
million, respectively. The estimated fair value of our term loan facility based on internally
developed discounted cash flow model and inputs based on managements best estimates (level 3
input) for identical liabilities as of March 31, 2011 and December 31, 2010 was $49.8 million and
$49.2 million, respectively.
Our current assets and liabilities accounts include financial instruments, the most
significant of which are accounts receivables and trade payables. We believe the carrying values
of our current assets and liabilities approximate fair value, with the exception of the note
receivable. Because this note receivable is not publicly-traded and not easily transferable, the
estimated fair value of our notes receivable is based on the market approach and time value of
money which approximates the note receivable book value of $3.3 million and $3.4 million at
March 31,
9
Table of Contents
2011 and December 31, 2010, respectively. The majority of inputs used in the fair value
calculation of the note receivable are Level 3 inputs and are consistent with the information used
in determining impairment of the note receivable.
The following is a reconciliation of the net beginning and ending balances recorded for
financial assets and liabilities classified as Level 3 in the fair value hierarchy.
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Financial assets: |
||||||||
Beginning balance |
$ | 3,420 | $ | 3,265 | ||||
Issuances |
| 200 | ||||||
Accrued interest |
157 | 398 | ||||||
Payments |
(322 | ) | (443 | ) | ||||
Ending balance |
$ | 3,255 | $ | 3,420 | ||||
Financial liabilities: |
||||||||
Beginning balance |
$ | 49,237 | $ | | ||||
Debt issuance |
| 60,000 | ||||||
Discount on debt |
| (11,122 | ) | |||||
Amortization of discount on debt |
538 | 359 | ||||||
Ending balance |
$ | 49,775 | $ | 49,237 | ||||
Asset Retirement Liability
The accounting for asset retirement obligations standard requires entities to record the fair
value of a liability for a legal obligation to retire an asset in the period in which the liability
is incurred if a reasonable estimate of fair value can be made. No wells were abandoned during the
three months ended March 31, 2011 or the year ended December 31, 2010. Changes in asset retirement
obligations during the three months ended March 31, 2011 and the year ended December 31, 2010 were
as follows:
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Asset retirement obligations beginning of period |
$ | 663 | $ | 50 | ||||
Liabilities recorded during the period |
52 | 382 | ||||||
Liabilities settled during the period |
| | ||||||
Revisions in estimated cash flows |
(120 | ) | 197 | |||||
Accretion expense |
4 | 34 | ||||||
Reclassify to liabilities held for sale |
(599 | ) | | |||||
Asset retirement obligations end of period |
$ | | $ | 663 | ||||
Noncontrolling Interests
Changes in noncontrolling interest during the three months ended March 31, 2011 and 2010 were
as follows:
March 31, | March 31, | |||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Balance at beginning of period |
$ | 70,051 | $ | 57,406 | ||||
Net income attributable to noncontrolling interest |
3,349 | 7,335 | ||||||
Balance at end of period |
$ | 73,400 | $ | 64,741 | ||||
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Earnings Per Share
Basic earnings per common share (EPS) are computed by dividing income available to common
stockholders by the weighted-average number of common shares outstanding for the period. Diluted
EPS reflects the potential dilution that would occur if securities or other contracts to issue
common stock were exercised or converted into common stock.
Three Months Ended March 31, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Basic | Diluted | Basic | Diluted | |||||||||||||
(in thousands, except per share data) | ||||||||||||||||
Income (loss) from continuing operations(a) |
$ | 3,655 | $ | 3,655 | $ | 22,275 | $ | 22,275 | ||||||||
Discontinued operations |
(2,885 | ) | (2,885 | ) | 2,315 | 2,315 | ||||||||||
Net income (loss) attributable to Harvest |
$ | 770 | $ | 770 | $ | 24,590 | $ | 24,590 | ||||||||
Weighted average common shares outstanding |
33,945 | 33,945 | 33,274 | 33,274 | ||||||||||||
Effect of dilutive securities |
| 4,555 | | 5,148 | ||||||||||||
Weighted average common shares,
Including dilutive effect |
33,945 | 38,500 | 33,274 | 38,422 | ||||||||||||
Per share: |
||||||||||||||||
Income (loss) from continuing operations(a) |
$ | 0.11 | $ | 0.09 | $ | 0.67 | $ | 0.58 | ||||||||
Discontinued operations |
$ | (0.09 | ) | $ | (0.07 | ) | $ | 0.07 | $ | 0.06 | ||||||
Net income (loss) attributable to
Harvest |
$ | 0.02 | $ | 0.02 | $ | 0.74 | $ | 0.64 |
(a) | Excludes net income attributable to noncontrolling interest. |
The
per share calculations above exclude 0.2 million and 3.2 million options because their
exercise price exceeded the average stock price for the three months ended March 31, 2011 and 2010,
respectively. The per share calculations above also exclude 5.6 million warrants because their
exercise price exceeded the average price for the three months ended March 31, 2011. We did not
have any warrants outstanding during the three months ended March 31, 2010.
Stock options of 41,666 were exercised in the three months ended March 31, 2011 resulting in
cash proceeds of $0.4 million. No stock options were exercised in the three months ended March 31,
2010.
Reclassifications
Certain items in 2010 have been reclassified to conform to the 2011 financial statement
presentation.
Note 3 Dispositions
Assets Held for Sale
On March 22, 2011, we announced that we had entered into a definitive agreement to sell all of
our oil and gas assets in Utahs Uinta Basin (Utah Operations) for $215 million in cash. The
sale has an effective date of March 1, 2011. The net proceeds from the sale are estimated to be
$205 million after deduction for transaction related costs. Closing is expected to occur in May
2011 and the final sales price is subject to customary adjustments at closing at that time. We
will provide transition services for a period of 60 days. The purchaser can cancel the transition
services arrangement at any time by delivering to us five days written notice of the intent to
cancel. We will not have any continuing involvement with the Utah operations except in the
capacity of the transition services arrangement; therefore, the related estimated gain on the sale
of approximately $100 million is expected to be reported in the second quarter of 2011.
Accordingly, these operations have been classified as discontinued operations. The Utah assets and
liabilities held for sale are reported in the consolidated balance sheet as follows:
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March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Proved oil and gas properties |
$ | 39,872 | $ | 31,037 | ||||
Unproved oil and gas properties |
62,672 | 57,737 | ||||||
Total assets held for sale |
$ | 102,544 | $ | 88,774 | ||||
Asset retirement liabilities |
$ | 599 | $ | 663 | ||||
Total liabilities held for sale |
$ | 599 | $ | 663 | ||||
Revenue and pretax income on these
dispositions are shown in the table below:
Three Months Ended March 31, | ||||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Revenues applicable to discontinued operations |
$ | 4,120 | $ | 3,124 | ||||
Pretax income (loss) from discontinued operations |
$ | (2,885 | ) | $ | 2,315 |
Pretax loss from discontinued operations for the three months ended March 31, 2011 includes
$1.4 million for impairment of long-lived assets and $3.5 million for employee severance and special accomplishment bonuses related to the sale of our
Utah Operations. Special accomplishment bonuses of $1.2 million directly relate to the sale of the
Utah properties and will be paid at the closing of the sale. Employee severance costs of $0.8
million will be paid at closing, $0.7 million is expected to be paid by June 30, 2011, and $1.2
million is expected to be paid in January 2012.
Note 4 Long-Term Debt
Long-Term Debt
Long-term debt consists of the following:
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Senior convertible notes, unsecured, with interest at 8.25% |
||||||||
See description below |
$ | 32,000 | $ | 32,000 | ||||
Term loan facility with interest at 10% |
||||||||
See description below |
60,000 | 60,000 | ||||||
92,000 | 92,000 | |||||||
Discount on term loan facility |
||||||||
See description below |
(10,225 | ) | (10,763 | ) | ||||
Less current portion |
| | ||||||
$ | 81,775 | $ | 81,237 | |||||
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 notes are 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 notes are also
redeemable in certain circumstances at our option and may be repurchased by us at the purchasers
option in connection with occurrence of certain events. Financing costs associated with the senior
convertible notes offering are being amortized over the remaining life of the notes and are
recorded in other assets. The balance was $1.7 million and $1.9 million at March 31, 2011 and
December 31, 2010, respectively.
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On October 29, 2010, we closed a $60.0 million term loan facility with MSD Energy Investments
Private II, LLC (MSD Energy), an affiliate of MSD Capital, L.P., as the sole lender under the
term loan facility. Under the terms of the term loan facility, interest is paid on a monthly basis
at the initial rate of 10 percent and will mature on October 28, 2012. The initial rate of
interest increases to 15 percent on July 28, 2011, the Bridge Date. The Bridge Date may be
extended at our option for three months by paying a fee to MSD Energy in the amount of five percent
of the initial principal amount of the term loan facility. If the loan is repaid in whole or in
part at any time before the Bridge Date, a prepayment premium of 3.5 percent of the amount prepaid
plus accrued interest on the prepayment amount is required in addition to the prepayment.
Financing costs associated with the term loan facility offering are being amortized over the
remaining life of the loan and are recorded in other assets. The balance was $0.3 million at March
31, 2011 and December 31, 2010, respectively.
In connection with the term loan facility, we issued to MSD Energy (1) 1.2 million warrants
exercisable at any time on or after the closing date for a period of five years from the closing
date on a cashless exercise basis at $15 per share until the Bridge Date, at which time the
exercise price per share will equal the lower of $15 or 120 percent of the average closing bid
price of Harvests common stock for the 20 trading days immediately preceding the Bridge Date
(Tranche A); (2) 0.4 million warrants exercisable at any time on or after the closing date for a
period of five years from the closing date on a cashless exercise basis at $20 per share until the
Bridge Date, at which time the exercise price per share will equal the lower of $15 or 120 percent
of the average closing bid price of Harvests common stock for the 20 trading days immediately
preceding the Bridge Date (Tranche B); and (3) 4.4 million warrants exercisable at any time on or
after the Bridge Date for a period of five years from the Bridge Date on a cashless exercise basis
at the lower of $15 per share or 120 percent of the average closing price of Harvests common stock
for the 20 trading days immediately preceding the Bridge Date (Tranche C). The Tranche C
warrants may be redeemed by Harvest for $0.01 per share at any time prior to the Bridge Date in
conjunction with the repayment of the loan prior to the Bridge Date.
The Black-Scholes option pricing model was used in pricing Tranche A and Tranche B. Tranche A
was priced at $5.46 per warrant, and Tranche B was priced at $4.60 per warrant. The Monte Carlo
option pricing model was used in pricing Tranche C due to the pricing and vesting variables in the
agreement. Tranche C was priced at $0.62 per warrant. The value of the warrants is recorded as
discount on debt with a corresponding credit to additional paid in capital. The discount on debt
is being amortized over the life of the warrants.
Note 5 Liquidity
The oil and gas industry is a highly capital intensive and cyclical business with unique
operating and financial risks. In Item 1A Risk Factors in our Annual Report on Form 10-K for the
year ended December 31, 2010, we discuss a number of variables and risks related to our exploration
projects and our minority equity investment in Petrodelta that could significantly utilize our cash
balances, affect our capital resources and liquidity. We also point out that the total capital
required to develop the fields in Venezuela may exceed Petrodeltas available cash and financing
capabilities, and that there may be operational or contractual consequences due to this inability.
Our cash is being used to fund oil and gas exploration projects and to a lesser extent general
and administrative costs. We require capital principally to fund the exploration and development
of new oil and gas properties. We are concentrating a substantial portion of our 2011 budget on
the development of the Budong-Budong Production Sharing Contract (Budong PSC) and the Dussafu
PSC. As is common in the oil and gas industry, we have various contractual commitments pertaining
to exploration, development and production activities. Currently, we have a work commitment of
$22.0 million which is a minimum amount to be spent on the Al Ghubar / Qarn Alam license (Block 64
EPSA) in Oman for the drilling of two wells over a three-year period which expires in May 2012.
We currently plan to fund this commitment in 2012, and we may be required to raise capital to do
so. We also have minimum work commitments during the various phases of the exploration periods in
the Budong PSC and Dussafu PSC.
As a petroleum exploration and production company, our revenue, profitability, cash flows, and
future rate of growth are substantially dependent on the condition of the oil and gas industry
generally, our success with our exploration program, and the belief that Petrodelta will fund its
own operations and continue to pay dividends. Because our revenues are generated from customers
with the same economic interests, our operations are also susceptible to market volatility
resulting from economic, cyclical, weather or other factors related to the energy industry.
Changes in the level of operating and capital spending in the industry, decreases in oil or gas
prices, or industry perceptions about future oil and gas prices could adversely affect our
financial position, results of
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operations and cash flows. Based on our current level of cash flow
from operations, we will be required to raise capital to meet our general and administrative costs
and fund our oil and gas programs.
Our primary source of cash is still dividends from Petrodelta and funding from debt financing.
In November 2010, Petrodeltas board of directors declared a dividend of $30.6 million, $12.2
million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents
the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodeltas net income
as reported under International Financial Reporting Standards (IFRS) for the year ended
December 31, 2009. We expect to receive future dividends from Petrodelta; however, we expect that
in the near term Petrodelta will reinvest most of its earnings into the company in support of its
drilling and appraisal activities. Therefore, there is uncertainty that Petrodelta will pay
additional dividends in 2011 or 2012.
Additionally, any dividend received from Petrodelta carries a liability to our non-controlling
interest holder, Vinccler, for its 20 percent share. Dividends declared and paid by Petrodelta are
paid to HNR Finance, our consolidated subsidiary. HNR Finance must declare a dividend in order for
us and our non-controlling interest holder, Vinccler, to receive our respective shares of
Petrodeltas dividends. A dividend from HNR Finance is due upon demand. Currently, Vinccler has
not demanded its respective share of the three most recent Petrodelta dividends and has waived such
a demand until at least April 2012. As of March 31, 2011, Vincclers share of the undistributed
dividends is $9.0 million inclusive of the unpaid November 2010 dividend. See Note 15 Related
Party Transactions.
We incurred significant debt during 2010 which has imposed restrictions on us and increased
our vulnerability to adverse economic and industry conditions. Our monthly and semi-annual
interest expense has increased significantly, and our senior convertible notes and term loan
facility impose new restrictions on us. Our senior convertible notes and term loan facility impose
covenant restrictions on us that limit our ability to obtain additional financing. Our ability to
meet these covenants is primarily dependent on meeting customary affirmative covenant clauses,
including providing consolidated statements to be audited and accompanied by a report and opinion
of an independent certified public accountant, which report and opinion shall not be subject to any
going concern or like qualification. Our inability to satisfy the covenants contained in our
long term debt arrangements would constitute an event of default, if not waived. An uncured
default could result in our outstanding debt becoming immediately due and payable. If this were to
occur, we may not be able to obtain waivers or secure alternative financing to satisfy our
obligations, either of which would have a material adverse impact on our business. As of March 31,
2011 and December 31, 2010, we were in compliance with all of our long term debt covenants.
At March 31, 2011, we had cash on hand of $24.7 million. On March 22, 2011, we announced that
we had entered into a definitive agreement to sell all of our oil and gas assets in Utahs Uinta
Basin for $215 million in cash. Closing is expected to occur in May 2011, and the net proceeds
from the sale are estimated to be $205 million after deduction for transaction related costs. We
believe that this cash plus cash generated from Petrodelta dividends and funding from our prior
debt financings combined with our ability to vary the timing of our capital expenditures is
sufficient to fund our operations and capital commitments through at least March 31, 2012.
However, if the sale of the Utah Operations is unsuccessful, we will be required to increase our
liquidity to levels sufficient to fund our
exploration program.
In order to increase our liquidity to levels sufficient to meet our commitments, we are
currently pursuing a number of actions including our ability to delay discretionary capital
spending to future periods, possible farm-out or sale of assets, or other monetization of assets as
necessary to maintain the liquidity required to run our operations. We continue to pursue, as
appropriate, additional actions designed to generate liquidity including seeking of financing
sources, accessing equity and debt markets, and cost reductions. However, there is no assurance
that our plans will be successful. Although we believe that we will have adequate liquidity to
meet our near term operating requirements and to remain compliant with the covenants under our long
term debt arrangements, the factors described above create uncertainty. 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. Accordingly, 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.
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Note 6 Commitments and Contingencies
Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc., Branta
Exploration & Production, LLC, Ute Energy LLC, Cameron Cuch, Paula Black, Johnna Blackhair, and
Elton Blackhair in the United States District Court for the District of Utah. This suit was
served in April 2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the
defendants, among other things, intentionally interfered with Plaintiffs employment agreement with
the Ute Indian Tribe Energy & Minerals Department and intentionally interfered with Plaintiffs
prospective economic relationships. Plaintiffs seek actual damages, punitive damages, costs and
attorneys fees. We dispute Plaintiffs claims and plan to vigorously defend against them. We are
unable to estimate the amount or range of any possible loss.
Uracoa Municipality Tax Assessments. Our Venezuelan subsidiary, Harvest Vinccler, has
received nine assessments from a tax inspector for the Uracoa municipality in which part of the
Uracoa, Tucupita and Bombal fields are located as follows:
| Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the capital fee reimbursement and related interest paid by Petroleos de Venezuela S.A. (PDVSA) under the Operating Service Agreement (OSA). Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims. |
| Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims. |
| Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim. |
| Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims. |
Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for
its positions. Harvest Vinccler is unable to estimate the amount or range of any possible loss.
As a result of the SENIATs, the Venezuelan income tax authority, interpretation of the tax code as
it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in
Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.
Libertador Municipality Tax Assessments. Harvest Vinccler has received five
assessments from a tax inspector for the Libertador municipality in which part of the Uracoa,
Tucupita and Bombal fields are located as follows:
| One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the municipality. Harvest Vinccler has filed a protest with the Mayors Office and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. On April 10, 2008, the Tax Court suspended the case pending a response from the Mayors Office to the protest. If the municipalitys response is to confirm the assessment, Harvest Vinccler will defer to the competent Tax Court to enjoin and dismiss the claim. |
| Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims. |
| Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss both claims. |
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Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes
it has a substantial basis for its position. Harvest Vinccler is unable to estimate the amount or
range of any possible loss. As a result of the SENIATs interpretation of the tax code as it
applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in
Caracas against the Libertador Municipality for the refund of all municipal taxes paid since 2002.
We are a defendant in or otherwise involved in other litigation incidental to our business.
In the opinion of management, there is no such litigation which will have a material adverse impact
on our financial condition, results of operations and cash flows.
Note 7 Taxes Other Than on Income
The components of taxes other than on income were:
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Franchise Taxes |
$ | 46 | $ | 61 | ||||
Payroll and Other Taxes |
303 | 239 | ||||||
$ | 349 | $ | 300 | |||||
Note 8 Operating Segments
We regularly allocate resources to and assess the performance of our operations by segments
that are organized by unique geographic and operating characteristics. The segments are organized
in order to manage regional business, currency and tax related risks and opportunities. Operations
included under the heading United States and Other include U.S. operations, corporate management,
cash management, business development and financing activities performed in the United States and
other countries which do not meet the requirements for separate disclosure. All intersegment
revenues, other income and equity earnings, expenses and receivables are eliminated in order to
reconcile to consolidated totals. Corporate general and administrative and interest expenses are
included in the United States and Other segment and are not allocated to other operating segments:
Three Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Operating Segment Income (Loss) |
||||||||
Venezuela |
$ | 16,362 | $ | 36,490 | ||||
Indonesia |
(1,413 | ) | (1,279 | ) | ||||
United States and other |
(11,294 | ) | (12,936 | ) | ||||
Discontinued operations (Utah Operations) |
(2,885 | ) | 2,315 | |||||
Net income (loss) |
$ | 770 | $ | 24,590 | ||||
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Operating Segment Assets |
||||||||
Venezuela |
$ | 296,314 | $ | 292,023 | ||||
Indonesia |
45,157 | 16,254 | ||||||
United States and other |
115,849 | 140,744 | ||||||
Net assets held for sale (Utah Operations) |
102,544 | 88,774 | ||||||
559,864 | 537,795 | |||||||
Intersegment eliminations |
(57,682 | ) | (49,551 | ) | ||||
$ | 502,182 | $ | 488,244 | |||||
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Note 9 Investment in Equity Affiliates
Petrodelta, S.A.
Petrodelta has undertaken its operations in accordance with Petrodeltas business plan as set
forth in its conversion contract. Under its conversion contract, work programs and annual budgets
adopted by Petrodelta must be consistent with Petrodeltas business plan. Petrodeltas business
plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the
shares of Petrodelta. Petrodeltas 2011 capital budget is expected to be approximately $220
million for Petrodeltas 2011 business plan. The 2011 budget is still pending shareholder
approval.
As discussed in previous filings, PDVSA has failed to pay on a timely basis certain amounts
owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA purchases all of
Petrodeltas 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 is continuing to experience, difficulty in retaining
contractors who provide services for Petrodeltas 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 Petrodeltas operations
and on Petrodeltas ability to carry out its business plan.
In 2008, the Venezuelan government published in the Official Gazette the Law of Special
Contribution to Extraordinary Prices at the Hydrocarbons International Market (Windfall Profits
Tax). The Windfall Profits Tax is calculated on the Venezuelan Export Basket (VEB) of prices as
published by the Ministry of the Peoples Power for Energy and Petroleum (MENPET). The Windfall
Profits Tax is being applied to gross oil production delivered to PDVSA. The Windfall Profits Tax
established a special 50 percent tax to the Venezuelan government when the average price of the VEB
exceeds $70 per barrel. In a similar manner, the percentage is increased from 50 percent to 60
percent when the average price of the VEB exceeds $100 per barrel. The Windfall Profits Tax is
reported as taxes other than on income on the income statement of Petrodelta and is deductible for
Venezuelan tax purposes. Petrodelta recorded $27.1 million and $1.3 million of expense for the
Windfall Profits Tax during the three months ended March 31, 2011 and 2010, respectively.
The Science and Technology Law (referred to as LOCTI in Venezuela) 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 on projects to promote inventions or investigate technology in areas deemed critical to
Venezuela. The contribution is based on the previous years 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. Since
Petrodelta expected PDVSA to continue requesting and receiving waivers, Petrodelta did not accrue a
liability to LOCTI for the year ended December 31, 2009. For filing years 2007 and 2008, PDVSA
provided Petrodelta with a copy of the waiver acceptance letter from LOCTI. PDVSA has stated that
a waiver was granted for filing year 2009; however, LOCTI has not yet issued the acceptance letter
to PDVSA for the 2009 filing year. The potential exposure to LOCTI for the year ended December 31,
2009 after devaluation is $4.8 million, $2.4 million net of tax ($0.8 million net to our 32 percent
interest). In January 2011, PDVSA informed its consolidating entities, including Petrodelta, that
effective with the 2010 reporting year it would no longer be requesting waivers to file the LOCTI
declaration on a consolidated basis. Based on this information, Petrodelta accrued the 2010
liability to LOCTI in the fourth quarter of 2010. However, in April 2011, Petrodelta received a
copy of the waiver acceptance letter issued by LOCTI to PDVSA for the 2010 filing year. Petrodelta
reversed the 2010 LOCTI accrual of $4.6 million, $2.3 million net of tax ($0.7 million net to our
32 percent interest) in the three months ended March 31, 2011. Petrodelta is accruing the 2011
liability to LOCTI on a current basis.
In December 2010, LOCTI was modified to reduce the amount of contributions beginning January
2011 to one percent of gross revenues for companies owned by individuals or corporations and 0.5
percent for companies owned by Venezuela. Petrodeltas rate of contribution starting in 2011 will
be 0.5 percent. LOCTI was also modified to require all contributions to be paid in cash directly
to the National Fund for Science, Technology and
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Innovation (FONDACIT), the entity responsible for the administration of LOCTI contributions.
Self-funded programs and direct contributions to projects performed by other institutions are no
longer allowed.
In November 2010, Petrodeltas board of directors declared a dividend of $30.6 million, $12.2
million net to HNR Finance ($9.8 million net to our 32 percent interest). Petrodelta shareholder
approval of the dividend was received on March 14, 2011. The dividend represents the remaining 50
percent of the cash withdrawal rights as shareholders on Petrodeltas net income as reported under
IFRS for the year ended December 31, 2009.
On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange
Agreement with an effective date of January 1, 2011. See Note 2 Summary of Significant
Accounting Policies, Reporting and Functional Currency. Petrodelta does not have currency exchange
risk other than the official prevailing exchange rate that applies to its operating costs
denominated in Bolivars (4.30 Bolivars per U.S. Dollar). Petrodelta does not have, and has not
had, any Bolivars pending government approval for settlement for U.S. Dollars at the official
exchange rate or the SITME rate. The monetary assets that are exposed to exchange rate
fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The
monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals
and other current liabilities. All monetary assets and liabilities incurred at the official
Bolivar exchange rate are settled at the official Bolivar exchange rate. At March 31, 2011, the
balances in Petrodeltas Bolivar denominated monetary assets and liabilities accounts that are
exposed to exchange rate changes are BsF 106.2 million and BsF 1,902.1 million, respectively.
Petrodeltas reporting and functional currency is the U.S. Dollar. HNR Finance owns a 40
percent interest in Petrodelta. Petrodeltas financial information is prepared in accordance with
IFRS which we have adjusted to conform to GAAP. All amounts through Net Income Equity Affiliate
represent 100 percent of Petrodelta. Summary financial information has been presented below at
March 31, 2011 and December 31, 2010 and for the three months ended March 31, 2011 and 2010:
18
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Three Months | Three Months | |||||||
Ended | Ended | |||||||
March 31, | March 31, | |||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Revenues: |
||||||||
Oil sales |
$ | 226,613 | $ | 141,502 | ||||
Gas sales |
726 | 1,018 | ||||||
Royalty |
(77,315 | ) | (47,986 | ) | ||||
150,024 | 94,534 | |||||||
Expenses: |
||||||||
Operating expenses |
14,282 | 10,043 | ||||||
Workovers |
6,475 | | ||||||
Depletion, depreciation and amortization |
12,487 | 8,607 | ||||||
General and administrative |
(930 | ) | 3,417 | |||||
Windfall profits tax |
27,126 | 1,251 | ||||||
59,440 | 23,318 | |||||||
Income from operations |
90,584 | 71,216 | ||||||
Gain on exchange rate |
| 118,716 | ||||||
Investment Earnings and Other |
167 | 2,894 | ||||||
Interest expense |
(1,272 | ) | (895 | ) | ||||
Income before Income Tax |
89,479 | 191,931 | ||||||
Current income tax expense |
53,343 | 85,420 | ||||||
Deferred income tax expense (benefit) |
(25,762 | ) | 42,464 | |||||
Net Income |
61,898 | 64,047 | ||||||
Adjustment to reconcile to reported Net Income from
Unconsolidated Equity Affiliate: |
||||||||
Deferred income tax expense (benefit) |
18,563 | (32,989 | ) | |||||
Net Income Equity Affiliate |
43,335 | 97,036 | ||||||
Equity interest in unconsolidated equity affiliate |
40 | % | 40 | % | ||||
Income before amortization of excess basis in equity affiliate |
17,334 | 38,814 | ||||||
Amortization of excess basis in equity affiliate |
(421 | ) | (334 | ) | ||||
Conform depletion expense to GAAP |
(81 | ) | (113 | ) | ||||
Net income from unconsolidated equity affiliate |
$ | 16,832 | $ | 38,367 | ||||
March 31, | December 31, | |||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Current assets |
$ | 704,681 | $ | 535,225 | ||||
Property and equipment |
345,191 | 321,816 | ||||||
Other assets |
84,501 | 67,755 | ||||||
Current liabilities |
583,225 | 406,339 | ||||||
Other liabilities |
40,568 | 39,224 | ||||||
Net equity |
510,580 | 479,233 |
Fusion Geophysical, LLC
On January 28, 2011, Fusion Geophysical, LLCs (Fusion) 69 percent owned subsidiary,
FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and Plan of Merger.
We received $1.3 million for our equity investment, subject to post-closing adjustments, and $0.7
million for the repayment in full of the outstanding balance of the prepaid service agreement,
short term loan and accrued interest. The Agreement and Plan of Merger includes an Earn Out
provision wherein we would receive an additional payment of up to a maximum of $2.7 million if
FusionGeo, Inc.s 2011 gross profit exceeds $5.6 million. The Earn Out payment will not be
determined until early in 2012. We can give no assurance that we will receive any Earn Out
payment.
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Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir
engineering. Our minority equity investment in Fusion was accounted for using the equity method of
accounting. Operating revenue and total assets represent 100 percent of Fusion. No dividends were
declared or paid during the three months ended March 31, 2011 and 2010, respectively. Summarized
financial information for Fusion follows. Due to the sale of Fusion on January 28, 2011, the
operating results shown for the three months ended March 31, 2011 reflect only January 2011
results, corresponding to date of sale.
Three Months | Three Months | |||||||
Ended | Ended | |||||||
March 31, | March 31, | |||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Operating Revenues |
$ | 678 | $ | 2,836 | ||||
Net Loss |
$ | (197 | ) | $ | (839 | ) | ||
Equity interest in unconsolidated equity affiliate |
49 | % | 49 | % | ||||
Net loss from unconsolidated equity affiliate |
$ | (97 | ) | $ | (411 | ) | ||
December 31, | ||||
2010 | ||||
(in thousands) | ||||
Current assets |
$ | 1,925 | ||
Total assets |
23,780 | |||
Current liabilities |
7,447 | |||
Total liabilities |
7,479 |
At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion.
Accordingly, we did not record net losses incurred by Fusion in the three months ended March 31,
2011 and 2010 as doing so would have caused our equity investment to
go into a negative position. However, we have recognized a $1.3
million gain on the sale of Fusion in the three months ended March
31, 2011.
Approximately 25.0 percent of Fusions revenue for the three months ended March 31, 2010 was
earned from Harvest or equity affiliates.
Note 10 United States Operations
In 2008, we initiated a domestic exploration program in two different basins. We are the
operator of both exploration programs and complemented our existing personnel with the addition of
highly experienced management and technical personnel.
Gulf Coast
We hold exploration acreage in the Gulf Coast Region of the United States through an Area of
Mutual Interest (AMI) agreement with two private third parties.
West Bay Project
In February 2011, the previously existing Alligator Point Unit (as approved by the Texas
General Land Office [GLO]) expired. We have obtained from the GLO an extension until September
1, 2011 of a smaller version of the Alligator Point Unit defined more specifically by the drilling
prospects currently existing on the project. As a result of the GLO approval of the smaller
Alligator Point Unit and the anticipated expiry of five leases previously held by the larger unit,
we expect our lease position on the West Bay project to be reduced from approximately 13,000 acres
in February 2011 to approximately 10,050 acres in August 2011.
The West Bay project represents $3.3 million of unproved oil and gas properties on our March
31, 2011 and December 31, 2010 balance sheets, respectively.
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Western United States Antelope
On March 22, 2011, we announced that we had entered into a definitive agreement to sell all of
our oil and gas assets in Utahs Uinta Basin (see Note 3 Dispositions). The oil and gas assets
are located in our Antelope project area in the Uinta Basin of Utah and consist of approximately
69,000 gross acres (47,600 net acres). The transaction includes the Mesaverde project, the Lower
Green River/Upper Wasatch project and the Monument Butte Extension project. We owned an
approximate working interest of 70 percent in the Mesaverde and Lower Green River/Upper Wasatch
projects, an approximate 60 percent working interest in one well in the Monument Butte Extension,
an approximate 43 percent working interest in the initial eight well program in the Monument Butte
Extension, and 37 percent working interest in the follow-up six well program in the Monument Butte
Extension. The initial eight well program and follow-up six well program in the Monument Butte
Extension are non-operated.
In July 2010, we executed a farm-out agreement with the private third party in the Joint
Exploration and Development Agreement (JEDA) for the acquisition of an incremental 10 percent
interest in the Antelope Project with an effective date of July 1, 2010. This acquisition
increased our ownership in the Antelope project to 70 percent. Total consideration for the
incremental 10 percent interest was $20.0 million, of which (1) $3.0 million was paid on August 2,
2010 (the closing date of the acquisition); (2) $3.0 million to be used as a credit against future
joint interest billings, the balance of which was paid on October 15, 2010; and (3) a capped $14.0
million carry of a portion of our partners exploration and development cost obligations in the
Lower Green River/Upper Wasatch and Monument Butte Extension drilling programs in the Antelope
project. At March 31, 2011, the outstanding balance on the $14.0 million exploration and
development cost obligation carry is $4.9 million. Due to the recent announcement of the sale of
our Antelope project, the balance of the carry obligation will be settled in cash from the sales
proceeds upon closing of the announced sale transaction.
The Antelope project represents $39.9 million and $62.7 million of proved and unproved oil and
gas properties held for sale on our March 31, 2011 balance sheet and $31.0 million and $57.7
million of proved and unproved oil and gas properties held for sale on our December 31, 2010
balance sheet.
The Antelope project was targeted to explore for and develop oil and natural gas from three
prospective reservoir horizons in the Uintah Basin of northeastern Utah in Duchesne and Uintah
Counties.
Mesaverde
The Mesaverde is the first prospective horizon in the Antelope project. Exploratory drilling
costs for the Mesaverde have been suspended pending further evaluation (see Note 2 Summary of
Significant Accounting Policies, Suspended Exploratory Drilling Costs, Mesaverde).
Lower Green River/Upper Wasatch
The Lower Green River/Upper Wasatch is the second prospective horizon that was being pursued
in the Antelope project. After the initial oil discovery in this project in the Bar F announced in
first quarter 2010, a five well Lower Green River/Upper Wasatch delineation and development
drilling program was initiated in the third quarter of 2010. The delineation and development
program was later expanded to include a sixth well. As of March 31, 2011, six wells were
producing from this project. The seventh well, the Evans #1-4-3-3, commenced production on April
22, 2011.
Monument Butte
The Monument Butte Extension is the third prospective horizon in the Antelope project. It was
initiated in the fourth quarter of 2009 with an eight well appraisal and development drilling
program to produce oil and natural gas from the Green River formation. As a follow up to the
successful completion of the eight well program, a six well appraisal and development drilling
program was approved in 2010. The six well expansion was on acreage immediately adjacent to the
eight well program. These 14 wells in the Monument Butte Extension (as defined above) are
non-operated, and we held a 43 percent working interest in the initial eight wells and an
approximate 37 percent working interest in the follow-up six wells. All 14 of these wells were
producing as of March 31, 2011.
During 2010, an additional Harvest operated well, the K Moon #2-13-4-3, was added to the
project. We had an approximate 60 percent working interest in the well. The K Moon #2-13-4-3 was
producing on natural flow as of March 31, 2011.
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Operational activities during 2011 for the Monument Butte Extension consisted of completion of
the K Moon #2-13-4-3 and drilling and completion of the sixth and final well in the six-well
follow-up program.
Note 11 Indonesia
In December 2007, we entered into a Farmout Agreement to acquire a 47 percent interest in the
Budong PSC located mostly onshore West Sulawesi, Indonesia. In April 2008, the Government of
Indonesia approved the assignment to us of the 47 percent interest in the Budong PSC. Our partner
is the operator through the exploration phase as required by the terms of the Budong PSC, and we
have an option to become operator, if approved by the Government of Indonesia and BPMIGAS,
Indonesias oil and gas regulatory authority, in any subsequent development and production phase.
We acquired our original 47 percent interest in the Budong PSC by committing to fund the first
phase of the exploration program up to a cap of $17.2 million, including the acquisition of 2-D
seismic and drilling of the first two exploration wells under a Farmout Agreement with our partner
in the Budong PSC. Prior to drilling the first exploration well, our partner had a one-time option
to increase the level of the carried interest to a maximum of $20.0 million. On September 15,
2010, our partner exercised their option to increase the carry obligation by $2.7 million to a
total of $19.9 million. The additional carry increased our ownership by 7.4 percent to 54.4
percent. On March 3, 2011, the Government of Indonesia and BPMIGAS approved this change in
ownership interest.
On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by
the operator to a third party, which has allowed us to acquire an additional 10 percent equity in
the Budong PSC at a cost of $3.7 million payable ten business days after completion of the first
exploration well. Closing of this acquisition, which is subject to the approval of the Government
of Indonesia and BPMIGAS, will increase our interest in the Budong PSC to 64.4 percent. The $3.7
million was paid on April 18, 2011.
Operational activities during the three months ended March 31, 2011 focused on drilling of the
first exploratory well, the Lariang-1 (LG-1), which spud on January 6, 2011, and well planning
and construction of the second exploratory well site. The LG-1 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. At a depth of 5,300 feet, losses of heavy drilling mud
into the formation were encountered which, when coupled with the very high formation pressures, led
to the decision to discontinue operations and plug and abandon the well for safety reasons on April
8, 2011. The primary Eocene targets had not been reached, as the well
was planned for a total measured depth of approximately 7,200 feet. At March 31, 2011, exploratory drilling costs of $13.2 million had been expended for the
drilling of the LG-1. These costs have been suspended pending further evaluation and appraisal
(see Note 2 Summary of Significant Accounting Policies Suspended Exploratory Drilling Costs,
Budong PSC). The Budong PSC represents $22.8 million and $10.9 million of unproved oil and gas
properties on our March 31, 2011 and December 31, 2010 balance sheets, respectively.
Note 12 Gabon
We are the operator of the Dussafu PSC offshore Gabon in West Africa with a 66.667 percent
ownership interest. The Dussafu PSC partners and the Republic of Gabon, represented by the
Ministry of Mines, Energy, Petroleum and Hydraulic Resources (Republic of Gabon), entered into
the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. It was
agreed that the second three-year exploration phase be extended until May 27, 2011, at which time
the partners can elect to enter a third exploration phase. In order to complete drilling
activities of the first exploratory well, in March 2011, the Direction Generale Des Hydrocarbures
(DGH) approved another one year extension to May 27, 2012 of the second exploration phase.
Operational activities during the three months ended March 31, 2011 included well preparation,
importation of drilling material and equipment into Gabon, contracting of well services for
drilling, the negotiation and contracting of a drilling unit in preparation to spud the exploration
well in the second quarter of 2011. A Standby Letter of Credit was issued on April 7, 2011 for a
semi-submersible rig to drill the Ruche Marin prospect. The exploratory well was spud on April 28,
2011 to test stacked reservoir potential in the pre-salt section. The Dussafu PSC represents $11.6
million and $9.2 million of unproved oil and gas properties on our March 31, 2011 and December 31,
2010 balance sheets, respectively.
In January 2011, we established an operational and logistics base in Port Gentil, Gabon to
support the drilling program.
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Note 13 Oman
In April 2009, we signed an Exploration and Production Sharing Agreement (EPSA) with Oman
for the Block 64 EPSA. We have a 100 percent working interest in Block 64 EPSA during the
exploration phase. Oman Oil Company has the option to back-in to up to a 20 percent interest in
Block 64 EPSA after the discovery of gas. We have a work commitment of $22.0 million which is a minimum amount to be spent on the Block 64
EPSA for the drilling of two wells over a three-year period which expires in May 2012.
Operational activities during the three months ended March 31, 2011 included the completion of
the reprocessing and integrating multiple existing 3-D seismic databases. Detail geological and
geophysical interpretation is underway to refine the prospects and define drilling locations. Well
planning and procurement of long lead items began in April 2011 in anticipation of spudding the
first of the two exploratory wells in late 2011. The Block 64 EPSA represents $4.3 million and
$4.2 million of unproved oil and gas properties on our March 31, 2011 and December 31, 2010 balance
sheets, respectively.
Note 14 China
In March 2011, China National Offshore Oil Corporation (CNOOC) granted us an extension of
Phase One of the Exploration Period for the WAB-21 contract area to May 2013. WAB-21 represents
$3.1 million of unproved oil and gas properties on our March 31, 2011 and December 31, 2010 balance
sheets, respectively.
Note 15 Related Party Transactions
Dividends declared and paid by Petrodelta are paid to HNR Finance. HNR Finance must declare a
dividend in order for the partners, Harvest and Vinccler, to receive their respective shares of
Petrodeltas dividend. Petrodelta has declared two dividends, totaling $33.0 million, which have
been received by HNR Finance and one dividend, totaling $12.2 million, which has not yet been
received by HNR Finance. HNR Finance has not distributed these dividends to the partners. At
March 31, 2011, Vincclers share of the undistributed dividends is $9.0 million.
Note 16 Subsequent Event
We conducted our subsequent events review up through the date of the issuance of this
Quarterly Report on Form 10-Q.
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
Harvest Natural Resources, Inc. (Harvest or the Company) cautions that any forward-looking
statements (as such term is defined in the Private Securities Litigation Reform Act of 1995, as
amended [the PSLRA]) contained in this report or made by management of the Company involve risks
and uncertainties and are subject to change based on various important factors. When used in this
report, the words budget, guidance, forecast, expect, believes, goals, projects,
plans, anticipates, estimates, should, could, assume and similar expressions are
intended to identify forward-looking statements. In accordance with the provisions of the PSLRA,
we caution you that important factors could cause actual results to differ materially from those in
the forward-looking statements. Such factors include our concentration of operations in Venezuela,
the political and economic risks associated with international operations (particularly those in
Venezuela), the anticipated future development costs for undeveloped reserves, drilling risks, the
risk that actual results may vary considerably from reserve estimates, the dependence upon the
abilities and continued participation of certain of our key employees, the risks normally incident
to the exploration, operation and development of oil and natural gas properties, risks incumbent to
being a noncontrolling interest shareholder in a corporation, the permitting and the drilling of
oil and natural gas wells, the availability of materials and supplies necessary to projects and
operations, the price for oil and natural gas and related financial derivatives, changes in
interest rates, the Companys ability to acquire oil and natural gas properties that meet its
objectives, availability and cost of drilling rigs, seismic crews, overall economic conditions,
political stability, civil unrest, acts of terrorism, currency and exchange risks, currency
controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in
governmental policy, availability of sufficient financing, changes in weather conditions, and
ability to hire, retain and train management and personnel. A discussion of these factors is
included in our Annual Report on Form 10-K for the year ended December 31, 2010, which includes
certain definitions and a summary of significant accounting policies and should be read in
conjunction with this Quarterly Report on Form 10-Q.
Executive Summary
Harvest Natural Resources, Inc. is a petroleum exploration and production company incorporated
under Delaware law in 1989. Our focus is on acquiring exploration, development and producing
properties in geological basins with proven active hydrocarbon systems. Our experienced technical,
business development and operating personnel have identified low entry cost exploration
opportunities in areas with large hydrocarbon resource potential. We operate from our Houston,
Texas headquarters. We also have regional/technical offices in the United Kingdom and Singapore,
and small field offices in Jakarta, Republic of Indonesia (Indonesia); Muscat, Sultanate of Oman
(Oman); Port Gentil, Republic of Gabon (Gabon); and Roosevelt, Utah to support field operations
in those areas. We expect to cease operations in the Roosevelt, Utah field office in May 2011 upon
closing of the announced sale transaction.
We have acquired and developed significant interests in the Bolivarian Republic of Venezuela
(Venezuela). Our Venezuelan interests are owned through HNR Finance, B.V. (HNR Finance). Our
ownership of HNR Finance is through several corporations in all of which we have direct controlling
interests. Through these corporations, we indirectly own 80 percent of HNR Finance and our
partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of
Venezolana de Inversiones y Construcciones Clerico, C.A. (Vinccler), indirectly owns the
remaining 20 percent interest of HNR Finance. HNR Finance owns 40 percent of Petrodelta, S.A.
(Petrodelta). As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent
interest in Petrodelta, and Vinccler indirectly owns eight percent. Corporación Venezolana del
Petroleo S.A. (CVP) owns the remaining 60 percent of Petrodelta. Petrodelta is governed by its
own charter and bylaws and operates a portfolio of properties in eastern Venezuela including large
proven oil fields as well as properties with very substantial opportunities for both development
and exploration. We have seconded key technical and managerial personnel into Petrodelta and
participate on Petrodeltas board of directors. HNR Finance has a direct controlling interest in
Harvest Vinccler S.C.A. (Harvest Vinccler). Harvest Vincclers main business purposes are to
assist us in the management of Petrodelta and in negotiations with Petroleos de Venezuela S.A.
(PDVSA). We do not have a business relationship with Vinccler outside of Venezuela.
Through the pursuit of technically-based strategies guided by conservative investment
philosophies, we are building a portfolio of exploration prospects to complement the low-risk
production, development and exploration prospects we hold in Venezuela. In addition to our
interests in Venezuela, we hold exploration acreage in the Gulf Coast Region of the United States
through an Area of Mutual Interest (AMI) agreement with two private third
24
Table of Contents
parties; mainly onshore
West Sulawesi in Indonesia; offshore of Gabon; onshore in Oman; and offshore of the Peoples Republic of China (China). Until March 1, 2011, pending closing of the sale for
our Utah Operations (see Notes to Consolidated Financial Statements Note 3 Dispositions), we
had developed acreage in the Antelope project in the Western United States through a Joint
Exploration and Development Agreement (JEDA) in the Monument Butte Extension Appraisal and
Development Project (Monument Butte Extension) and Lower Green River/Upper Wasatch Oil
Delineation and Development Project (Lower Green River/Upper Wasatch) where we had established
production.
From time to time we learn of possible third party interests in acquiring ownership in certain
assets within our property portfolio. We evaluate these potential opportunities taking into
consideration our overall property mix, our operational and liquidity requirements, our strategic
focus and our commitment to long-term shareholder value. For example, we have received such
expressions of interest in acquiring some of our international and domestic producing and
exploration assets, and we are currently evaluating these potential opportunities. There can be no
assurances that our discussions will continue or that any transaction may ultimately result from
our discussions.
On March 22, 2011, we announced that we had entered into a definitive agreement to sell all of
our oil and gas assets in Utahs Uinta Basin for $215 million in cash. The sale has an effective
date of March 1, 2011. The net proceeds from the sale are estimated to be $205 million after
deduction for transaction related costs. Closing is expected to occur in May 2011 and the final
sales price is subject to customary adjustments at closing at that time. The oil and gas assets
are located in our Antelope project area in the Uinta Basin of Utah and consist of approximately
69,000 gross acres (47,600 net acres). The transaction includes both operated and non-operated
wells. Bank of America Merrill Lynch served as our financial advisor in connection with the
transaction. This transaction is part of our ongoing process of exploring strategic alternatives
announced in September of 2010.
Venezuela
On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange
Agreement which eliminated the 2.60 Venezuela Bolivars (Bolivars) per U.S. Dollar exchange rate
for purchases, the 2.5935 Bolivars per U.S. Dollar exchange rates for the sale of foreign currency,
and the Central Banks entitlement to require the sale of foreign currency at specific rates with
an effective date of January 1, 2011. The elimination of the 2.60 Bolivars per U.S. Dollar
exchange rate for purchases is not expected to have an impact on our business in Venezuela. Since
all sales of foreign currency will be at the 4.2893 Bolivars per U.S. Dollar exchange rate, we will
not be required to pay a financing fee resulting from blended exchange rates for the purchase of
foreign currency.
In May 2010, the government of Venezuela established the Sistema de Transacciones con Títulos
en Moneda Extranjera (SITME) for exchanging Bolivars. SITMEs 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 Venezuelas bonds. The establishment
of SITME has not had, nor is it expected to have, an impact on our business in Venezuela.
Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official
prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30
Bolivars per U.S. Dollar). However, during the three months ended March 31, 2011, Harvest Vinccler
exchanged approximately $0.3 million through SITME and received an average exchange rate of 5.18
Bolivars per U.S. Dollar. During the three months ended March 31, 2010, no such exchanges took
place. Petrodelta does not have, and has not had, any U.S. Dollars pending government approval for
settlement for Bolivars at the official exchange rate or the SITME exchange rate. Harvest Vinccler
currently does not have any U.S. Dollars pending government approval for settlement for Bolivars at
the official exchange rate or the SITME exchange rate.
The monetary assets that are exposed to exchange rate fluctuations are cash, accounts
receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed
to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All
monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the
official Bolivar exchange rate. At March 31, 2011, the balances in Harvest Vincclers
Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate
changes are BsF 3.0 million and BsF 3.5 million, respectively. At March 31, 2011, the balances in
Petrodeltas Bolivar denominated monetary assets and liabilities accounts that are exposed to
exchange rate changes are BsF 106.2 million and BsF 1,902.1 million, respectively.
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Petrodelta
Petrodeltas shareholders intend that the company be self-funding and rely on
internally-generated cash flow to fund operations. Petrodeltas 2011 capital budget is expected to
be approximately $220 million for Petrodeltas 2011 business plan. The 2011 budget is still
pending shareholder approval. Since Petrodelta only executed approximately 50 percent its 2010
budget primarily due to lack of funding by PDVSA, we do not believe that PDVSA will be able to
provide the support required to execute Petrodeltas proposed 2011 budget. However, Petrodeltas
2011 proposed business plan includes a planned drilling program to utilize two rigs to drill both
development and appraisal wells for maintaining production capacity, the continued appraisal of the
substantial resource base in the El Salto field and further drilling in the Isleño field. It also
includes engineering work for production facilities required for the full development of the El
Salto field.
As discussed in previous filings, PDVSA has failed to pay on a timely basis certain amounts
owed to contractors that PDVSA has contracted to do work for Petrodelta. PDVSA purchases all of
Petrodeltas 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 is continuing to experience, difficulty in retaining
contractors who provide services for Petrodeltas 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 Petrodeltas operations
and on Petrodeltas ability to carry out its business plan.
In 2008, the Venezuelan government published in the Official Gazette the Law of Special
Contribution to Extraordinary Prices at the Hydrocarbons International Market ( original Windfall
Profits Tax). The original Windfall Profits Tax is calculated on the Venezuelan Export Basket
(VEB) of prices as published by the Ministry of the Peoples Power for Energy and Petroleum
(MENPET). The original Windfall Profits Tax is being applied to gross oil production delivered
to PDVSA. The original Windfall Profits Tax established a special 50 percent tax to the Venezuelan
government when the average price of the VEB exceeds $70 per barrel. In a similar manner, the
percentage is increased from 50 percent to 60 percent when the average price of the VEB exceeds
$100 per barrel.
On April 18, 2011, the Venezuelan government published in the Official Gazette the Law
Creating a Special Contribution on Extraordinary Prices and Exorbitant Prices in the International
Hydrocarbons Market (the amended Windfall Profits Tax). The amended Windfall Profits Tax repeals
the original Windfall Profits Tax. The amended Windfall Profits Tax establishes a special
contribution for extraordinary prices to the Venezuelan government of 20 percent to be applied to
the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at
$40 per barrel for 2011) and $70 per barrel. The amended Windfall Profits Tax also establishes a
special contribution for exorbitant prices to the Venezuelan government of (1) 80 percent when the
average price of the VEB exceeds $70 per barrel but is less than $90 per barrel; (2) of 90 percent
when the average price of the VEB exceeds $90 per barrel but is less that $100 per barrel; and (3)
of 95 percent when the average price of the VEB exceeds $100 per barrel. It is not clear from the
drafting of the amended Windfall Profits Tax if the special contribution for extraordinary prices
and the special contribution for exorbitant prices are exclusive of each other; whether these
layers are additive or if the 95 percent rate would apply from $70 to the price above $100; and
whether the new rates apply to 100 percent of production. The amended Windfall Profits Tax caps
the royalty paid on production at $70 per barrel. By placing a cap on the royalty barrels, the
amended Windfall Profits Tax reduces the royalties paid to the government and increases payments to
the National Development Fund (FONDEN). Also, the amended Windfall Profits Tax considers that an
exemption of this tax could be granted by MENPET for the incremental production of projects and
grass root developments until the specific investments are recovered. This exemption has to be
considered and approved in a case by case basis by MENPET. There is still a lack of clarity on
several issues. We are currently evaluating the impact of the amended Windfall Profits Tax on
Petrodeltas operations.
During the three months ended March 31, 2011, Petrodelta drilled and completed four
development wells and one successful appraisal well compared to four development wells in the three
months ended March 31, 2010. Petrodelta delivered approximately 2.6 million barrels (MBls) of
oil and 0.5 billion cubic feet (Bcf) of natural gas, averaging 28,700 barrels of oil equivalent
(BOE) per day during the three months ended March 31, 2011 compared to deliveries of 2.0 MBls of
oil and 0.7 Bcf of gas, averaging 21,867 BOE per day during the three months ended March 31, 2010.
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During the three months ended March 31, 2011, Petrodelta began appraisal of the Isleño field.
The first appraisal well, the ILM-8, began production on March 16 through temporary facilities.
Currently, Petrodelta is operating drilling rigs in the El Salto and the Uracoa fields. A workover
rig is operating in the Tucupita field. Petrodelta is also continuing infrastructure enhancement
projects in El Salto and Temblador.
Certain operating statistics for the three months ended March 31, 2011 and 2010 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 | Three Months | |||||||
Ended | Ended | |||||||
March 31, | March 31, | |||||||
2011 | 2010 | |||||||
Thousand barrels of oil sold |
2,583 | 1,968 | ||||||
Million cubic feet of gas sold |
470 | 660 | ||||||
Total thousand barrels of oil equivalent |
2,661 | 2,078 | ||||||
Average price per barrel |
$ | 87.73 | $ | 71.90 | ||||
Average price per thousand cubic feet |
$ | 1.54 | $ | 1.54 | ||||
Cash operating costs ($millions) |
$ | 14.3 | $ | 11.2 | ||||
Capital expenditures ($millions) |
$ | 34.4 | $ | 6.1 |
Crude oil delivered from the Petrodelta fields to PDVSA Petroleo S.A. (PPSA) 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. Merey 16 published prices are quoted and sold in
U.S. Dollars. Natural gas delivered from the Petrodelta Fields to PPSA is priced at $1.54 per
thousand cubic feet. PPSA is obligated to make payment to Petrodelta in U.S. Dollars in the case
of payment for crude oil and natural gas liquids delivered. Natural gas deliveries are paid in
Bolivars, but the pricing for natural gas is referenced to the U.S. Dollar.
United States
Gulf Coast AMI West Bay
In February 2011, the previously existing Alligator Point Unit (as approved by the Texas
General Land Office [GLO]) expired. We have obtained from the GLO an extension until September
1, 2011 of a smaller version of the Alligator Point Unit defined more specifically by the drilling
prospects currently existing on the project. As a result of the GLO approval of the smaller
Alligator Point Unit and the anticipated expiry of five leases previously held by the larger unit,
we expect our lease position on the West Bay project to be reduced from approximately 13,000 acres
in February 2011 to approximately 10,050 acres in August 2011.
Western United States Antelope
On March 22, 2011, we announced that we had entered into a definitive agreement to sell all of
our oil and gas assets in Utahs Uinta Basin for $215 million in cash. The sale has an effective
date of March 1, 2011. The net proceeds from the sale are estimated to be $205 million after
deduction for transaction related costs. Closing is expected to occur in May 2011 and the final
sales price is subject to customary adjustments at closing at that time.
The oil and gas assets are located in our Antelope project area in the Uinta Basin of Utah and
consist of approximately 69,000 gross acres (47,600 net acres). The transaction includes the
Mesaverde project, the Lower Green River/Upper Wasatch project and the Monument Butte Extension
project. We owned an approximate working interest of 70 percent in the Mesaverde and Lower Green
River/Upper Wasatch projects, an approximate 60 percent working interest in one well in the
Monument Butte Extension, and an approximate 43 percent working interest in the initial eight well
program and 37 percent working interest in the follow-up six well program in the Monument Butte
Extension. The initial eight well program and follow-up six well program in the Monument Butte
Extension are non-operated.
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Lower Green River/Upper Wasatch Oil Delineation and Development Project
Operational activities during the three months ended March 31, 2011 included completion of the
five-well delineation and development drilling program, that was later expanded to include a sixth
well, which was initiated in the third quarter of 2010. As of March 31, 2011, we had six Lower
Green River/Upper Wasatch wells on production and one well, the Evans #1-4-3-3 in the process of
being completed and having production facilities installed. The Evans #1-4-3-3 commenced
production on April 22, 2011.
Monument Butte
Operational activities during 2011 for the Monument Butte Extension consisted of drilling and
completion of the sixth and final well in the non-operated six-well follow-up program started in
the fourth quarter of 2010. At March 31, 2011, all non-operated wells had been drilled and
completed, and all were on production.
During 2010, an additional Harvest operated well, the K Moon #2-13-4-3, was added to the
project. We had an approximate 60 percent working interest in the well. During the first quarter
of 2011, the K Moon #2-13-4-3 was drilled to total depth, completed, and production facilities
installed. The K Moon #2-13-4-3 is producing on natural flow as of March 31, 2011.
Certain operating statistics for the three months ended March 31, 2011 and 2010 for the U.S.
operations are set forth below. This information is provided at our net ownership.
Three Months | Three Months | |||||||
Ended | Ended | |||||||
March 31, | March 31, | |||||||
2011 | 2010 | |||||||
Barrels of oil sold |
40,323 | 42,269 | ||||||
Thousand cubic feet of gas sold |
246,019 | 86,336 | ||||||
Total barrels of oil equivalent |
81,326 | 56,658 | ||||||
Average price per barrel |
$ | 81.25 | $ | 65.86 | ||||
Average price per thousand cubic feet |
$ | 3.43 | $ | 3.94 | ||||
Lease operating costs and production taxes ($millions) |
$ | 2.4 | $ | 0.2 | ||||
Cash capital expenditures ($millions) |
$ | 15.6 | $ | 10.7 | ||||
Depletion expense per barrel of oil equivalent |
$ | 9.91 | $ | 8.27 |
Crude oil delivered from the Monument Butte Extension is priced with reference to NYMEX
CL1 Light Sweet Crude Contract published prices. Natural gas delivered from the Monument Butte
Extension is priced with reference to NYMEX Henry Hub published prices. Crude oil delivered from
the Lower Green River/Upper Wasatch is priced with reference to Chevron Altamont Yellow Wax monthly
average posting.
Budong-Budong Project, Indonesia
On September 15, 2010, our partner in the Budong-Budong Production Sharing Contract (Budong
PSC) exercised their option to increase the carry obligation. The additional carry obligation
increased our ownership by 7.4 percent from 47 percent to 54.4 percent. On March 3, 2011, the
Government of Indonesia and BPMIGAS, Indonesias oil and gas regulatory authority, approved this
change in ownership interest.
On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by
the operator to a third party, which has allowed us to acquire an additional 10 percent equity in
the Budong PSC at a cost of $3.7 million payable ten business days after completion of the first
exploration well. Closing of this acquisition, which is subject to the approval of the Government
of Indonesia and BPMIGAS, will increase our interest in the Budong PSC to 64.4 percent. The $3.7
million was paid on April 18, 2011.
The Lariang-1 (LG-1) well, the first of two planned exploration wells, was spud on January 6, 2011 in
the Budong-Budong Block, West Sulawesi. The LG-1 targeted the Miocene and Eocene reservoirs to a planned
depth of approximately 7,200 feet. The LG-1 was drilled to a total depth of 5,311 feet and encountered multiple oil
and gas shows within the secondary Miocene objective. Wireline logs and samples of reservoir fluids confirmed the
presence of hydrocarbons, trap and seal thus greatly de-risking the exploration potential of the license as well as
proving the LG structure to be hydrocarbon bearing. The high formation pressures, well control difficulties, and a
poor cementing job on the 9-5/8ths casing required the use of more casing strings at shallower depths than were
originally planned. At a depth of 5,300 feet, losses of heavy drilling mud into the formation were encountered
which, when coupled with the very high formation pressures, led the partners to the decision to discontinue
operations and plug and abandon the well 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. The costs for drilling the LG-1, $13.2 million, have been suspended pending further
evaluation and appraisal (see Notes to Consolidated Financial Statements - Note 2 - Summary of Significant
Accounting Policies - Suspended Exploratory Drilling Costs, Budong PSC).
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The drilling rig is currently mobilizing to drill the second exploratory well on the block,
the Karama-1 (KD-1), which is located approximately 50 miles south of the LG-1 well. The KD-1
well will be drilled to a total depth of about 10,500 feet.
During the three months ended March 31, 2011, we had cash capital expenditures of $5.5 million
for drilling and construction costs.
Dussafu Project Gabon
The Dussafu Marin Permit (Dussafu PSC) partners and the Republic of Gabon, represented by
the Ministry of Mines, Energy, Petroleum and Hydraulic Resources (Republic of Gabon), entered
into the second exploration phase of the Dussafu PSC with an effective date of May 28, 2007. It
was agreed that the second three-year exploration phase be extended until May 27, 2011, at which
time the partners can elect to enter a third exploration phase. In order to complete drilling
activities of the first exploratory well, in March 2011, the Direction Generale Des Hydrocarbures
(DGH) approved another one year extension to May 27, 2012 of the second exploration phase.
Operational activities during the three months ended March 31, 2011 included well preparation,
importation of drilling material and equipment into Gabon, contracting of well services for
drilling, the negotiation and contracting of a drilling unit in preparation to spud the exploration
well in the second quarter of 2011. A Standby Letter of Credit was issued on April 8, 2011 for the
Transocean Sedneth 701 semi-submersible drilling unit. We took possession of the drilling unit
mid-April 2011 on a one well contract. All critical materials required for drilling the well have
been purchased and received. The Ruche Marin-A exploration well spud April 28, 2011. The Ruche
Marin-A well is in a water depth of 380 feet and will drill to test multiple stacked pre-salt
targets to a planned total measured depth of approximately 10,100 feet with an option to deepen to
12,500 feet. We have also established an operational and logistics base in Port Gentil, Gabon to
support the drilling program. During the three months ended March 31, 2011, we had cash capital
expenditures of $2.1 million for well planning.
Block 64 EPSA Project Oman
We have a work commitment of $22.0 million which is a minimum amount to be spent on the Al
Ghubar / Qarn Alam license (Block 64 EPSA) for the drilling of two wells over a three-year period
which expires in May 2012. Operational activities during the three months ended March 31, 2011
included the completion of the reprocessing and integrating multiple existing 3-D seismic
databases. Detail geological and geophysical interpretation is underway to refine the prospects
and define drilling locations. Well planning and procurement of long lead items began in April
2011 in anticipation of spudding the first of the two exploratory wells in late 2011. During the
three months ended March 31, 2011, we incurred $0.3 million for seismic interpretation.
WAB-21 Project China
In March 2011, China National Offshore Oil Corporation (CNOOC) granted us an extension of
Phase One of the Exploration Period for the WAB-21 contract area to May 2013.
Other Exploration Projects
Any of the exploratory wells to be drilled in 2011 on the Budong PSC and the Dussafu PSC could
have a significant impact on our ability to obtain financing, record reserves and generate cash
flow in 2011 and beyond.
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Fusion Geophysical, LLC (Fusion)
On January 28, 2011, Fusions 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a
private purchaser pursuant to an Agreement and Plan of Merger. We received $1.3 million for our
equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full
of the outstanding balance of the prepaid service agreement, short term loan and accrued interest.
The Agreement and Plan of Merger includes an Earn Out provision wherein we would receive an
additional payment of up to a maximum of $2.7 million if FusionGeo, Inc.s 2011 gross profit
exceeds $5.6 million. The Earn Out payment will not be determined until early in 2012. We can
give no assurance that we will receive any Earn Out payment. See Notes to Consolidated Financial
Statements, Note 9 Investment in Equity Affiliates Fusion Geophysical LLC.
Capital Resources and Liquidity
The oil and gas industry is a highly capital intensive and cyclical business with unique
operating and financial risks. In Item 1A Risk Factors in our Annual Report on Form 10-K for
the year ended December 31, 2010, we discuss a number of variables and risks related to our
exploration projects and our minority equity investment in Petrodelta that could significantly
utilize our cash balances, affect our capital resources and liquidity. We also point out that the
total capital required to develop the fields in Venezuela may exceed Petrodeltas available cash
and financing capabilities, and that there may be operational or contractual consequences due to
this inability.
Our cash is being used to fund oil and gas exploration projects and to a lesser extent general
and administrative costs. We require capital principally to fund the exploration and development
of new oil and gas properties. We are concentrating a substantial portion of our 2011 budget on
the development of the Budong PSC and the Dussafu PSC. As is common in the oil and gas industry,
we have various contractual commitments pertaining to exploration, development and production
activities. Currently, we have a work commitment of $22.0 million which is a minimum amount to be
spent on the Block 64 EPSA in Oman for the drilling of two wells over a three-year period which
expires in May 2012. We currently plan to fund this commitment in 2012, and we may be required to
raise capital to do so. We also have minimum work commitments during the various phases of the
exploration periods in the Budong PSC and Dussafu PSC.
As a petroleum exploration and production company, our revenue, profitability, cash flows, and
future rate of growth are substantially dependent on the condition of the oil and gas industry
generally, our success with our exploration program, and the belief that Petrodelta will fund its
own operations and continue to pay dividends. Because our revenues are generated from customers
with the same economic interests, our operations are also susceptible to market volatility
resulting from economic, cyclical, weather or other factors related to the energy industry.
Changes in the level of operating and capital spending in the industry, decreases in oil or gas
prices, or industry perceptions about future oil and gas prices could adversely affect our
financial position, results of operations and cash flows. Based on our current level of cash flow
from operations, we will be required to raise capital to meet our general and administrative costs
and fund our oil and gas programs.
Our primary source of cash is still dividends from Petrodelta and funding from debt financing.
In November 2010, Petrodeltas board of directors declared a dividend of $30.6 million, $12.2
million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents
the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodeltas net income
as reported under International Financial Reporting Standards (IFRS) for the year ended December
31, 2009. We expect to receive future dividends from Petrodelta; however, we expect that in the
near term Petrodelta will reinvest most of its earnings into the company in support of its drilling
and appraisal activities. Therefore, there is uncertainty that Petrodelta will pay additional
dividends in 2011 or 2012.
Additionally, any dividend received from Petrodelta carries a liability to our non-controlling
interest holder, Vinccler, for its 20 percent share. Dividends declared and paid by Petrodelta are
paid to HNR Finance, our consolidated subsidiary. HNR Finance must declare a dividend in order for
us and our non-controlling interest holder, Vinccler, to receive our respective shares of
Petrodeltas dividends. A dividend from HNR Finance is due
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upon demand. Currently, Vinccler has not demanded its respective share of the three most
recent Petrodelta dividends and has waived such a demand until at least April 2012. As of March
31, 2011, Vincclers share of the undistributed dividends is $9.0 million inclusive of the unpaid
November 2010 dividend. See Notes to Consolidated Financial Statements, Note 15 Related Party
Transactions.
We incurred significant debt during 2010 which has imposed restrictions on us and increased
our vulnerability to adverse economic and industry conditions. Our monthly and semi-annual
interest expense has increased significantly, and our senior convertible notes and term loan
facility impose new restrictions on us. Our senior convertible notes and term loan facility impose
covenant restrictions on us that limit our ability to obtain additional financing. Our ability to
meet these covenants is primarily dependent on meeting customary affirmative covenant clauses,
including providing consolidated statements to be audited and accompanied by a report and opinion
of an independent certified public accountant, which report and opinion shall not be subject to any
going concern or like qualification. Our inability to satisfy the covenants contained in our
long term debt arrangements would constitute an event of default, if not waived. An uncured
default could result in our outstanding debt becoming immediately due and payable. If this were to
occur, we may not be able to obtain waivers or secure alternative financing to satisfy our
obligations, either of which would have a material adverse impact on our business. As of March 31,
2011 and December 31, 2010, we were in compliance with all of our long term debt covenants.
At March 31, 2011, we had cash on hand of $24.7 million. On March 22, 2011, we announced that
we had entered into a definitive agreement to sell all of our oil and gas assets in Utahs Uinta
Basin for $215 million in cash. Closing is expected to occur in May 2011, and the net proceeds
from the sale are estimated to be $205 million after deduction for transaction related costs. We
believe that this cash plus cash generated from Petrodelta dividends and funding from our prior
debt financings combined with our ability to vary the timing of our capital expenditures is
sufficient to fund our operations and capital commitments through at least March 31, 2012.
However, if the sale of the Utah Operations is unsuccessful, we will be required to increase our
liquidity to levels sufficient to fund our
exploration program.
In order to increase our liquidity to levels sufficient to meet our commitments, we are
currently pursuing a number of actions including our ability to delay discretionary capital
spending to future periods, possible farm-out or sale of assets, or other monetization of assets as
necessary to maintain the liquidity required to run our operations. We continue to pursue, as
appropriate, additional actions designed to generate liquidity including seeking of financing
sources, accessing equity and debt markets, and cost reductions. However, there is no assurance
that our plans will be successful. Although we believe that we will have adequate liquidity to
meet our near term operating requirements and to remain compliant with the covenants under our long
term debt arrangements, the factors described above create uncertainty. 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. Accordingly, 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.
Working Capital. 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:
Three Months Ended March 31, | ||||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Net cash used in operating activities |
$ | (7,021 | ) | $ | (1,424 | ) | ||
Net cash used in investing activities |
(27,245 | ) | (16,151 | ) | ||||
Net cash provided by financing activities |
227 | 29,373 | ||||||
Net increase (decrease) in cash |
$ | (34,039 | ) | $ | 11,798 | |||
At March 31, 2011, we had current assets of $159.3 million and current liabilities of $35.6
million, resulting in working capital of $123.7 million and a current ratio of 4.5:1. This
compares with a working capital of $133.3 million and a current ratio of 5.7:1 at December 31,
2010. The decrease in working capital of $9.6 million was primarily due to dividends declared by
an equity affiliate and the reclassification of Antelope assets to Asset Held for Sale offset by
increases in capital expenditures and administrative expenses.
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Cash Flow used in Operating Activities. During the three months ended March 31, 2011 and
2010, net cash used in operating activities was approximately $7.0 million and $1.4 million,
respectively. The $5.6 million decrease was primarily due to increases in accounts payable and
accrued expenses offset by payments of income tax payable and increases in accounts receivable and
dividend receivable from equity affiliate.
Cash Flow from Investing Activities. During the three months ended March 31, 2011, we had
cash capital expenditures for property and equipment of approximately $8.4 million. Of the 2011
expenditures, $5.5 million was attributable to activity on the Budong PSC, $2.1 million was
attributable to activity on the Dussafu PSC and $0.8 million was attributable to activity on other
projects. During the three months ended March 31, 2010, we had cash capital expenditures of
approximately $13.5 million. Of the 2010 expenditures, $10.7 million was attributable to activity
on the Antelope projects, $2.3 million was attributable to activity on the Budong PSC, $0.4 million
was attributable to activity on the Dussafu PSC and $0.1 million was attributable to other
projects.
During the three months ended March 31, 2011, we received $1.3 million from the sale of our
equity investment in Fusion, and we deposited $4.5 million as collateral for a standby letter of
credit issued in support of the drilling unit to be used on the Gabon PSC. During the three months
ended March 31, 2010, we deposited with a U.S. bank $1.0 million as collateral for a standby letter
of credit issued in support of a bank guarantee required as a performance guarantee for a joint
study. During the three months ended March 31, 2011 and 2010, we incurred $0.03 million and $1.7
million, respectively, of investigatory costs related to various international and domestic
exploration studies.
Petrodeltas capital commitments will be determined by its business plan. Petrodeltas capital
commitments are expected to be funded by internally generated cash flow. Our budgeted capital
expenditures for 2011 will be funded through our existing cash balances, accessing equity and debt
markets, and cost reductions. In addition, we could delay the discretionary portion of our capital
spending to future periods or sell, farm-out or otherwise monetize assets as necessary to maintain
the liquidity required to run our operations, as warranted.
Cash Flow from Financing Activities. During the three months ended March 31, 2011 and 2010,
we incurred $0.2 million and $0.1 million, respectively, in legal fees associated with financings.
During the three months ended March 31, 2010, we closed an offering of $32.0 million in aggregate
principal amount of our 8.25 percent senior convertible notes, incurred $2.5 million in deferred
financings costs related to the $32.0 million convertible debt offering that are being amortized
over the life of the financial instrument.
Results of Operations
You should read the following discussion of the results of operations for the three months
ended March 31, 2011 and 2010 and the financial condition as of March 31, 2011 and December 31,
2010 in conjunction with our consolidated financial statements and related notes included in our
Annual Report on Form 10-K for the year ended December 31, 2010.
Three Months Ended March 31, 2011 Compared with Three Months Ended March 31, 2010
We reported net income attributable to Harvest of $0.8 million, or $0.02 diluted earnings per
share, for the three months ended March 31, 2011, compared with net income attributable to Harvest
of $24.6 million, or $0.64 diluted earnings per share, for the three months ended March 31, 2010.
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Total expenses and other non-operating (income) expense (in millions):
Three Months Ended | ||||||||||||
March 31, | Increase | |||||||||||
2011 | 2010 | (Decrease) | ||||||||||
Depreciation and amortization |
$ | 0.1 | $ | 0.1 | $ | | ||||||
Exploration expense |
1.2 | 1.2 | | |||||||||
General and administrative |
6.7 | 5.3 | 1.4 | |||||||||
Taxes other than on income |
0.3 | 0.3 | | |||||||||
Investment earnings and other |
(0.1 | ) | (0.1 | ) | | |||||||
Interest expense |
2.2 | 0.4 | 1.8 | |||||||||
Other non-operating expense |
0.4 | | 0.4 | |||||||||
Loss on exchange rates |
| 1.5 | (1.5 | ) | ||||||||
Income tax expense |
0.2 | | 0.2 |
During the three months ended March 31, 2011, we incurred $1.1 million of exploration
costs related to the processing and reprocessing of seismic data related to ongoing operations and
$0.1 million related to other general business development activities. During the three months
ended March 31, 2010, we incurred $0.9 million of exploration costs related to the processing and
reprocessing of seismic data related to ongoing operations, and $0.3 million related to other
general business development activities.
General and administrative costs were higher in the three months ended March 31, 2011 compared
to the three months ended March 31, 2010 primarily due to higher employee related costs ($1.3
million) and general corporate overhead costs ($0.5 million) offset by lower legal and other
professional fees ($0.4 million). The employee related cost increase includes $0.4 million
of special consideration bonuses related to the sale of our Utah operations.
Taxes other than on income for the three months ended March 31,
2011 were consistent with the three months ended March 31, 2010.
Investment earnings and other for the three months ended March 31, 2011 were consistent with
the three months ended March 31, 2010. Interest expense was higher for the three months ended
March 31, 2011 compared to the three months ended March 31, 2010 due to the interest associated
with our $32 million convertible debt offering in February 2010, our $60 million term loan facility
occurring in October 2010 and amortization of discount on the term loan facility related to the
warrants issued in connection with the $60 million term loan facility offset by interest
capitalized to oil and gas properties of $0.8 million. Other non-operating expense was higher in
the three months ended March 31, 2011 compared to the three months ended March 31, 2010 due to $0.4
million of costs incurred related to on-going strategic alternatives.
Loss on exchange rates was lower for the three months ended March 31, 2011 compared to the
three months ended March 31, 2010 due to the Bolivar/U.S. Dollar currency exchange rate devaluation
announced on January 8, 2010. In January 2010, Harvest Vinccler revalued the appropriate monetary
accounts that were Bolivar-denominated to U.S. Dollars, Harvest Vincclers functional and reporting
currency, at the published exchange rate of 4.30 Bolivars per U.S. Dollar. The primary factor in
Harvest Vincclers loss on currency exchange rates is that Harvest Vinccler had substantially
higher Bolivar denominated assets than Bolivar denominated liabilities. During the three months
ended March 31, 2010, Harvest Vinccler recorded a $1.5 million remeasurement loss on revaluation of
assets and liabilities.
For the three months ended March 31, 2011, income tax expense was higher compared with that of
the three months ended March 31, 2010, due to income tax assessed in the Netherlands recorded in
the first quarter of 2011.
For the three months ended March 31, 2010, net income from unconsolidated equity affiliates
includes a $118.7 million, before tax, ($38.0 million, before tax, net to our 32 percent interest)
remeasurement gain on revaluation of assets and liabilities recorded by Petrodelta due to the
Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. Petrodeltas
reporting and functional currency is the U.S. Dollar. The adjustment to reconcile to reported net
income from unconsolidated affiliate for deferred income taxes increased due to the effect of the
currency devaluation on the deferred tax asset associated with the non-monetary assets impacted by
inflationary adjustments.
We recorded a $1.3 million gain on the sale of our equity affiliate, Fusion, during the three
months ended March 31, 2011.
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Discontinued Operations
On March 22, 2011, we announced that we had entered into a definitive agreement to sell all of
our oil and gas assets in Utahs Uinta Basin for $215 million in cash. The sale has an effective
date of March 1, 2011. The net proceeds from the sale are estimated to be $205 million after
deduction for transaction related costs. Closing is expected to occur in May 2011 and the final
sales price is subject to customary adjustments at closing at that time.
Revenues were higher in the three months ended March 31, 2011 compared with the three months
ended March 31, 2010 due to more wells being on production and higher average prices received for
the sale of oil and natural gas. Production for the two areas for the three months ended March 31,
2011 and 2010 was:
March 31, 2011 | March 31, 2010 | |||||||||||||||
Lower Green | Monument | Lower Green | Monument | |||||||||||||
River/Upper | Butte | River/Upper | Butte | |||||||||||||
Wasatch | Extension | Wasatch | Extension | |||||||||||||
Barrels of oil sold |
23,542 | 16,780 | 2,541 | 39,728 | ||||||||||||
Thousand cubic feet of gas sold |
5,939 | 240,080 | | 86,336 | ||||||||||||
Total barrels of oil equivalent |
24,532 | 56,794 | 2,541 | 54,117 | ||||||||||||
Average price per barrel |
$ | 84.31 | $ | 76.95 | $ | 71.89 | $ | 65.46 | ||||||||
Average price per thousand cubic feet |
$ | 4.79 | $ | 3.40 | $ | | $ | 3.94 |
Lease operating costs and production taxes were higher in the three months ended March 31,
2011 compared to the three months ended March 31, 2010 due to the increase in the number oil and
natural gas wells on production in the U.S. Costs incurred were for supervision and pipeline and
transportation costs. Depletion expense was $0.8 million and $0.5 million ($9.91 and $8.27 per
BOE) for the three months ended March 31, 2011 and 2010, respectively.
Pretax loss from discontinued
operations includes $1.4 million for impairment of long-lived assets
and $3.5 million for employee severance and
special bonuses related to the sale of our Utah Operations.
Effects of Changing Prices, Foreign Exchange Rates and Inflation
Our results of operations and cash flow are affected by changing oil prices. Fluctuations in
oil prices may affect our total planned development activities and capital expenditure program.
Our net foreign exchange losses attributable to our international operations were minimal for
the three months ended March 31, 2011 and $1.5 million for the three months ended March 31, 2010.
The U.S. Dollar and Bolivar exchange rates had not been adjusted from March 2005 until January
2010. However, there are many factors affecting foreign exchange rates and resulting exchange
gains and losses, most of which are beyond our control. It is not possible for us to predict the
extent to which we may be affected by future changes in exchange rates and exchange controls.
Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official
exchange rate in February 2004, March 2005, January 2010 and again in January 2011. 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 went into effect on
January 11, 2010. On January 4, 2011, the Venezuelan government published in the Official Gazette
the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate with an
effective date of January 1, 2011.
Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official
prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30
Bolivars per U.S. Dollar). However, during the three months ended March 31, 2011, Harvest Vinccler
exchanged approximately $0.3 million through SITME and received an average exchange rate of 5.18
Bolivars per U.S. Dollar. The monetary assets that are exposed to exchange rate fluctuations are
cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities
that are exposed to exchange rate fluctuations are accounts payable, accruals and other current
liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate
are settled at the official Bolivar exchange rate. Petrodelta does not have, and has not had, any
U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate
or the SITME exchange rate. Harvest Vinccler
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currently does not have any U.S. Dollars pending government approval for settlement for
Bolivars at the official exchange rate or the SITME exchange rate.
Within the United States and other countries in which we conduct business, inflation has had a
minimal effect on us, but it is potentially an important factor with respect to results of
operations in Venezuela.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk from adverse changes of the situation in Venezuela, our
exploration program and adverse changes in oil prices, interest rates, foreign exchange and
political risk, as discussed in our Annual Report on Form 10-K for the year ended December 31,
2010. The information about market risk for the three months ended March 31, 2011 does not
differ materially from that discussed in the Annual Report on Form 10-K for the year ended
December 31, 2010.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. We have established disclosure
controls and procedures that are designed to ensure the information required to be disclosed by us
in the reports that we file or submit under the Securities Exchange Act of 1934, as amended (the
Exchange Act) is recorded, processed, summarized and reported within the time periods specified
in the SECs rules and forms and that such information is accumulated and communicated to our
management, including our principal executive officer and principal financial officer, as
appropriate, to allow timely decisions regarding required disclosure.
Based on their evaluation as of March 31, 2011, our principal executive officer and principal
financial officer have concluded that our disclosure controls and procedures (as defined in Rule
13a-15(e) and 15d-15(e) under the Exchange Act) were effective.
Changes in Internal Control over Financial Reporting. There have been no changes in our
internal control over financial reporting during our most recent quarter ended March 31, 2011, that
have materially affected, or are reasonably likely to affect, our internal control over financial
reporting.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings
See our Annual Report on Form 10-K for the year ended December 31, 2010 for a
description of legal proceedings. There have been no material developments in such
legal proceedings since the filing of such Annual Report.
Item 1A. Risk Factors
See our Annual Report on Form 10-K for the year ended December 31, 2010 under
Item 1A Risk Factors for a description of risk factors. There have been no material
developments in such risk factors since the filing of such Annual Report.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 6. Exhibits
(a) Exhibits
2.1 | Purchase and Sale Agreement, dated March 21, 2011, between Harvest (US) Holding, Inc. and Newfield Production Company. (Incorporated by reference to Exhibit 2.1 to our Form 8-K filed on March 25, 2011, File No. 1-10762.) | ||
3.1 | Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.) | ||
3.2 | Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on April 23, 2007, File No. 1-10762.) | ||
4.1 | Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.1 to our Form 10-K filed on March 17, 2008, File No. 1-10762.) | ||
4.2 | Certificate of Designation, Rights and Preferences of the Series B Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.2 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.) | ||
4.3 | Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A filed on October 23, 2007, File No. 1-10762.) | ||
4.4 | Amendment to Third Amended and Restated Rights Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on October 29, 2010, File No. 1-10762.) | ||
31.1 | Certification of the principal executive officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
31.2 | Certification of the principal financial officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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32.1 | Certification accompanying Quarterly Report on Form 10-Q pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by James A. Edmiston, President and Chief Executive Officer. | ||
32.2 | Certification accompanying Quarterly Report on Form 10-Q pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by Stephen C. Haynes, Vice President, Chief Financial Officer and Treasurer. |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
HARVEST NATURAL RESOURCES, INC. |
||||
Dated: May 10, 2011 | By: | /s/ James A. Edmiston | ||
James A. Edmiston | ||||
President and Chief Executive Officer | ||||
Dated: May 10, 2011 | By: | /s/ Stephen C. Haynes | ||
Stephen C. Haynes | ||||
Vice President - Finance, Chief Financial Officer and Treasurer |
||||
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Exhibit Index
Exhibit | ||
Number | Description | |
2.1
|
Purchase and Sale Agreement, dated March 21, 2011, between Harvest (US) Holding, Inc. and Newfield Production Company. (Incorporated by reference to Exhibit 2.1 to our Form 8-K filed on March 25, 2011, File No. 1-10762.) | |
3.1
|
Amended and Restated Certificate of Incorporation (Incorporated by reference to Exhibit 3.1 to our Form 10-Q filed on November 9, 2010, File No. 1-10762). | |
3.2
|
Restated Bylaws as of May 17, 2007. (Incorporated by reference to Exhibit 3.1 to our Form 8-K filed on April 23, 2007, File No. 1-10762.) | |
4.1
|
Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.1 to our Form 10-K filed on March 17, 2008. File No. 1-10762.) | |
4.2
|
Certificate of Designation, Rights and Preferences of the Series B Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.2 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.) | |
4.3
|
Third Amended and Restated Rights Agreement, dated as of August 23, 2007, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 99.3 to our Form 8-A filed on October 23, 2007, File No. 1-10762.) | |
4.4
|
Amendment to Third Amended and Restated Rights Agreement, dated as of October 28, 2010, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A. (Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on October 29, 2010, File No. 1-10762.) | |
31.1
|
Certification of the principal executive officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
31.2
|
Certification of the principal financial officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1
|
Certification accompanying Quarterly Report on Form 10-Q pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by James A. Edmiston, President and Chief Executive Officer. | |
32.2
|
Certification accompanying Quarterly Report on Form 10-Q pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by Stephen C. Haynes, Vice President, Chief Financial Officer and Treasurer. |
39