UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2009
or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File No.: 1-10762
HARVEST NATURAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
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Delaware
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77-0196707 |
(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification Number) |
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1177 Enclave Parkway, Suite 300 |
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Houston, Texas
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77077 |
(Address of principal executive offices)
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(Zip Code) |
Registrants telephone number, including area code: (281) 899-5700
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered |
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Common Stock, $.01 Par Value
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NYSE |
Securities registered pursuant to Section 12(g) of the Act: Preferred Share Purchase Rights
Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act. Yes o No þ
Indicate by check mark whether the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act. Yes o No þ
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 website, if any, every Interactive Data File required to be submitted and posted pursuant
to Rule 405 of Regulation S-T (§ 232.405 of this chapter) 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. þ
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.
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Large Accelerated Filer o
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Accelerated Filer þ
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Non-Accelerated Filer o
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Smaller Reporting Company o |
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(Do not check if a smaller reporting company) |
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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
The aggregate market value of the registrants voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was last sold, or the
average bid and asked price of such common equity, as of June 30, 2009 was: $144,812,960.
Indicate the number of shares outstanding of each of the registrants classes of common stock, as
of the latest practical date. Class: Common Stock, par value $0.01 per share, on March 9, 2010,
shares outstanding: 33,260,554.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrants Proxy Statement for the 2010 Annual Meeting of Stockholders to be
filed with the Securities and Exchange Commission, not later than 120 days after the close of the
registrants fiscal year, pursuant to Regulation 14A, are incorporated by reference into Items 10,
11, 12, 13 and 14 of Part III of this annual report.
HARVEST NATURAL RESOURCES, INC.
FORM 10-K
TABLE OF CONTENTS
PART I
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)
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 Private Securities Litigation
Reform Act of 1995, 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 holding a noncontrolling interest 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 and 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 including
the Companys ability to obtain the Islamic (sukuk) financing described in Item 1A Risk Factors,
changes in weather conditions, and ability to hire, retain and train management and personnel. See
Item 1A Risk Factors and Item 7 Managements Discussion and Analysis of Financial Condition and
Results of Operations.
Item 1. Business
Executive Summary
Harvest Natural Resources, Inc. is an international 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 staffs 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, Indonesia, Muscat, Sultanate of Oman (Oman) and
Roosevelt, Utah to support field operations in those areas. We have acquired and developed
significant interests in the Bolivarian Republic of Venezuela (Venezuela) through our 40 percent
equity affiliate, Petrodelta, S.A. (Petrodelta), which 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. Geophysical,
geosciences, and reservoir engineering support services are available to our in-house experts
through our minority equity investment in Fusion Geophysical, LLC (Fusion). Fusion is a
technical firm specializing in the areas of geophysics, geosciences and reservoir engineering
headquartered in the Houston area. 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 project in Venezuela. Currently,
we hold interests in Venezuela, the Gulf Coast Region of the United States through an Area of
Mutual Intent (AMI) agreement with two private third parties, the Antelope prospect in the
Western United States through a Joint Exploration and Development Agreement (JEDA), and
exploration acreage mainly onshore West Sulawesi in the Republic of Indonesia (Indonesia),
offshore of the Republic of Gabon (Gabon), onshore in Oman and offshore of the Peoples Republic
of China (China).
HNR Finance B.V. (HNR Finance) has a 40 percent ownership interest in Petrodelta. As we
indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in
Petrodelta, and our partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A.
(OGTC), a controlled affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A.
(Vinccler), indirectly owns the remaining eight percent interest.
1
Corporación Venezolana del Petroleo S.A. (CVP) owns the remaining 60 percent of Petrodelta.
Petrodelta is governed by its own board of directors, charter and bylaws.
On April 11, 2009, we signed an Exploration and Production Sharing Agreement (EPSA) with
Oman for the Al Ghubar / Qarn Alam license (Block 64 EPSA).
On April 23, 2009, Petrodeltas board of directors declared a dividend of $51.9 million, $20.8
million net to HNR Finance ($16.6 million net to our 32 percent interest), which represents
Petrodeltas net income as reported under International Financial Reporting Standards (IFRS) for
the six months ended June 30, 2008. HNR Finance received the cash related to this dividend in the
form of an advance dividend in October 2008.
In June 2009, drilling operations commenced on a deep natural gas test well (the Bar F
#1-20-3-2 [Bar F]). The Bar F was drilled as a tight hole and was permitted to 18,000 feet.
Drilling was completed in the fourth quarter of 2009 at a depth of 17,566 feet and production
casing has been run. Production testing of the well commenced in November 2009 and continues in
the first quarter of 2010. The testing program is expected to be completed by the end of the first
quarter of 2010.
In December 2009, drilling operations commenced in an eight well appraisal and development
drilling program to produce oil and natural gas from the Green River formation on the southern
portion of our Antelope land position. As of March 1, 2010, all eight wells have been drilled.
Seven wells are currently on production. One additional well is waiting on completion operations
and is anticipated to commence production in early March 2010.
During the year ended December 31, 2009, Petrodelta drilled and completed 14 successful
development wells, suspended one well due to problems with the well and drilled two appraisal
wells. Petrodelta currently has one drilling rig working in the Uracoa field.
On January 28, 2010, we entered into an agreement with one of the private third parties in our
AMI for an option to participate in a new project. We paid $1.5 million for the option to acquire
up to a 50 percent interest in the new project. If we exercise our option to participate, we will
participate in this project with essentially the same terms as the other existing projects in the
AMI. The option to participate expires on June 1, 2010.
On February 17, 2010, we closed a debt offering of $32 million in aggregate principal amount
of our 8.25 percent senior convertible notes due 2013, which resulted in net proceeds to us, after
deducting underwriting discounts, commissions and estimated offering expenses, of approximately $30
million.
See Item 1 Business, Operations, Item 1A Risk Factors, and Item 7 Managements
Discussion and Analysis of Financial Condition and Results of Operations for a more detailed
description of these and other events during 2009.
As of December 31, 2009, we had total assets of $348.8 million, unrestricted cash of $32.3
million and no long-term debt. For the year ended December 31, 2009, we had revenues of $0.2
million and net cash used in operating activities of $34.9 million. Subsequent to December 31,
2009, we offered and issued $32.0 million in aggregate principal amount of our 8.25 percent senior
convertible notes due 2013. As of December 31, 2008, we had total assets of $362.3 million,
unrestricted cash of $97.2 million and no long-term debt. For the year ended December 31, 2008, we
had no revenues and net cash provided by operating activities of $50.4 million.
Our strategy has broadened from our primary focus on Venezuela to identify, access and
integrate hydrocarbon assets to include organic growth through exploration in basins globally with
proven hydrocarbon systems as an alternative to purchasing proved producing assets. We seek to
leverage our Venezuelan experience as well as our recently expanded business development and
technical platform to create a diversified resource base. With the addition of exploration
technical resources, opening of our London and Singapore offices, as well as our minority equity
investment in Fusion, we have made significant investments to provide the necessary foundation and
global reach required for an organic growth focus. While exploration will become a larger part of
our overall portfolio, we generally restrict ourselves to basins with known hydrocarbon systems and
favorable risk-reward profiles.
2
We intend to use our available cash to pursue additional growth opportunities in the United
States, Indonesia, Gabon, Oman, China and other countries that meet our strategy. However, the
execution of this strategy may be limited by factors including access to additional capital and the
receipt of dividends from Petrodelta as well as the need to preserve adequate development capital
in the interim. As described in Item 7 Managements Discussion and Analysis of Financial
Condition and Results of Operations, Capital Resources and Liquidity, on February 17, 2010, we
incurred indebtedness of $32.0 million in aggregate principal amount of our 8.25 percent senior
convertible notes. As a result of this offering, we received net proceeds, after deduction of
underwriting discounts, commissions and estimated offering expenses, of approximately $30.0
million. We intend to use these net proceeds to fund capital expenditures and for working capital
needs and general corporate purposes.
The ability to successfully execute our strategy is subject to significant risks including,
among other things, payment of Petrodelta dividends, exploration, operating, political, legal and
financial risks. See Item 1A Risk Factors, Item 7 Managements Discussion and Analysis of
Financial Condition and Results of Operations and other information set forth elsewhere in this
Annual Report on Form 10-K for a description of these and other risk factors.
Available Information
We file annual, quarterly and current reports, proxy statements and other documents with the
Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934 (Exchange
Act). The public may read and copy any materials that we file with the SEC at the SECs Office of
Investor Education and Advocacy at 100 F Street NE, Washington, DC 20549-0213. The public may
obtain information on the operation of the Office of Investor Education and Advocacy by calling the
SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy
and information statements, and other information regarding issuers, including us, that file
electronically with the SEC. The public can obtain any documents that we file with the SEC at
http://www.sec.gov.
We also make available, free of charge on or through our Internet website
(http://www.harvestnr.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current
Reports on Form 8-K, and if applicable, amendments to those reports filed or furnished pursuant to
Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file
such material with, or furnish it to, the SEC. Forms 3, 4 and 5 filed with respect to our equity
securities under Section 16(a) of the Exchange Act are also available on our website. In addition,
we have adopted a Code of Business Conduct and Ethics that applies to all of our employees,
including our chief executive officer, principal financial officer and principal accounting
officer. The text of the Code of Business Conduct and Ethics has been posted on the Corporate
Governance section of our website. We intend to post on our website any amendments to, or waivers
from, our Code of Business Conduct and Ethics applicable to our senior officers. Additionally, the
Code of Business Conduct and Ethics is available in print to any person who requests the
information. Individuals wishing to obtain this printed material should submit a request to
Harvest Natural Resources, Inc., 1177 Enclave Parkway, Suite 300, Houston, Texas 77077, Attention:
Investor Relations.
Operations
Since April 1, 2006, our Venezuelan operations have been conducted through our equity
affiliate Petrodelta which is governed by the Contract of Conversion (Conversion Contract) signed
on September 11, 2007. All of the equity investment in HNR Finance and Harvest Vinccler, S.C.A.
(Harvest Vinccler) is owned by Harvest-Vinccler Dutch Holding B.V., a Netherlands private company
with limited liability. We own an 80 percent equity investment in Harvest-Vinccler Dutch Holding
B.V. The remaining 20 percent noncontrolling interest is owned by OGTC. In addition, we have an
interest varying from 50 to 55 percent by prospect in an area of the Gulf Coast Region of the
United States covered by an AMI agreement with private third parties, a 60 percent interest in the
Antelope prospect in the Western United States covered by a JEDA, a 47 percent interest in the
Budong-Budong production sharing contract (Budong PSC) which we may operate during the production
phase, a 66.667 percent interest in the production sharing contract related to the Dussafu Marin
Permit production sharing contract (Dussafu PSC) for which we are the operator, a 100 percent
interest in an Exploration and Production Sharing Agreement (EPSA) with Oman for the Al
Ghubar/Qarn Alam license, and a 100 percent interest in the WAB-21 petroleum contract in the South
China Sea for which we are the operator. See Item 1 Business, United States; Budong-Budong,
Onshore Indonesia; Dussafu Marin, Offshore Gabon, Block 64 Project, Oman, and WAB-21, South China Sea for
a more detailed description.
3
Reserves
In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which
is effective for reporting 2009 reserve information. The primary impacts of the SECs final rule
on our reserve estimates include:
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In Venezuela, the use of the unweighted 12-month average of the first-day-of-the-month
contracted reference price of $56.83 per barrel for oil compared to the year-end contracted
reference price of $69.87 per barrel, and |
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In the United States, the use of the unweighted 12-month average of the
first-day-of-the-month reference prices of $48.21 per barrel for oil and $3.31 per Mcf for
gas compared to year-end reference prices of $61.73 per barrel of oil and $4.25 per Mcf for
gas. |
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The disclosure of probable and possible reserves. |
Under the SECs final rule, prior period reserves were not restated.
The process for preparation of our oil and gas reserves estimates is completed in accordance
with our prescribed internal control procedures, which include verification of data provided for,
management reviews and review of the independent third party reserves report. The technical
employee responsible for overseeing the process for preparation of the reserves estimates has a
Bachelor of Arts in Engineering Science, a Master of Science in Petroleum Engineering, has more
than 25 years of experience in reservoir engineering and is a member of the Society of Petroleum
Engineers.
All reserve information in this report is based on estimates prepared by Ryder Scott Company
L.P. (Ryder Scott), independent petroleum engineers. The technical personnel responsible for
preparing the reserve estimates at Ryder Scott meet the requirements regarding qualifications,
independence, objectivity and confidentiality set forth in the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum
Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists
and petrophysicists; they do not own an interest in our properties and are not employed on a
contingent fee basis.
The following table shows, by country and in the aggregate, a summary of our proved, probable
and possible oil and gas reserves as of December 31, 2009. Probable and possible reserves are not
reported for Domestic Utah due to the ongoing evaluation of assets within these categories.
4
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Oil and |
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Natural |
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Condensate |
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Gas |
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Total |
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(MBls) |
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(MMcf) |
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(MBls) (1) |
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Proved Developed Reserves: |
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Domestic Utah |
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131 |
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653 |
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240 |
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International Venezuela(2) |
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14,242 |
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24,015 |
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18,244 |
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Total Proved Developed |
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14,373 |
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24,668 |
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18,484 |
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Proved Undeveloped Reserves: |
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Domestic Utah |
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95 |
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473 |
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174 |
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International Venezuela (2) |
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33,177 |
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38,695 |
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39,626 |
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Total Proved Undeveloped |
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33,272 |
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39,168 |
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39,800 |
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Total Proved Reserves |
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47,645 |
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63,836 |
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58,284 |
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Probable Developed Reserves: |
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International Venezuela(2) |
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118 |
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93 |
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134 |
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Probable Undeveloped Reserves: |
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International Venezuela(2) |
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43,689 |
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14,593 |
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46,121 |
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Total Probable Reserves |
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43,807 |
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14,686 |
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46,255 |
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Possible Developed Reserves: |
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International Venezuela(2) |
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11 |
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11 |
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Possible Undeveloped Reserves: |
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International Venezuela(2) |
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168,506 |
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46,434 |
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176,245 |
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Total Possible Reserves |
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168,517 |
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46,434 |
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176,256 |
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(1) |
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MBls is determined using the ratio of one barrel of crude oil or condensate to six
Mcf of natural gas. |
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(2) |
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Information represents HNR Finances 40 percent interest. |
Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves at
December 31, 2009, 2008 and 2007 and changes in proved reserves during the last three years are
contained in Part IV, Item 15 Supplemental Information on Oil and Natural Gas Producing
Activities (unaudited). See Item 7 Managements Discussion and Analysis of Financial Condition
and Results of Operations, Critical Accounting Policies for additional information on our reserves.
Petrodelta
General
On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to
Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract
was published in the Official Gazette. Petrodelta will engage in the exploration, production,
gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of
20 years from that date. Petrodelta has undertaken its operations in accordance with its business
plan as set forth in the Conversion Contract. Under the 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. On February 4, 2010, Petrodeltas board of directors
endorsed a capital budget of $205 million for Petrodeltas 2010 business plan.
Petrodelta shareholders intend that the company be self-funding and rely on
internally-generated cash flow to fund operations. Currently, Petrodelta has one drilling rig
operating in the Uracoa field. For 2010, the planned drilling program includes utilizing two rigs
to drill both development and appraisal wells for both maintaining production capacity and
appraising the substantial resource bases in the El Salto field and presently non-producing Isleño
field.
5
During 2009, Petrodelta drilled and completed 14 successful development wells and two
appraisal wells, produced approximately 7.8 million barrels of oil and sold 4.4 billion cubic feet
(BCF) of natural gas. Petrodelta was advised by the Venezuelan government that the 2009
production target was approximately 16,000 barrels of oil per day following the December 17, 2008
Organization of the Petroleum Exporting Countries (OPEC) meeting establishing new production
quotas. However, Petrodelta was allowed to produce at capacity to help fulfill other companies
production shortfalls, thus averaging 21,464 barrels of oil per day during 2009.
Petrodelta began the appraisal and testing of its large portfolio of undeveloped resources in
the second quarter of 2009. During the second quarter 2009, Petrodelta drilled two successful
appraisal wells in the El Salto field, and pilot production commenced from one of the appraisal
wells through temporary facilities. The well commenced production on July 18, 2009 and has
produced 349,000 barrels of oil through the end of 2009. The second appraisal well is still
waiting on permits from the Ministry of Energy and Petroleum (MENPET) for testing.
On April 15, 2008, the Venezuelan government published in the Official Gazette the Law of
Special Contribution to Extraordinary Prices at the Hydrocarbons International Market (the
original Windfall Profits Tax). The original Windfall Profits Tax was based on prices for Brent
crude. On July 10, 2008, the Venezuelan government published the amended Windfall Profits Tax to
be calculated on the Venezuelan Export Basket (VEB) of prices as published by MENPET. The
amended Windfall Profits Tax was made retroactive to April 15, 2008, the date of the original
Windfall Profits Tax. As instructed by CVP, Petrodelta has applied the amended Windfall Profits
Tax to gross oil production delivered to Petroleos de Venezuela S.A. (PDVSA) since April 15, 2008
when the tax was enacted. The amended 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 amended Windfall Profits Tax is reported as expense on the income
statement and is deductible for Venezuelan tax purposes. Petrodelta recorded $0.9 million and
$56.4 million for the years ended December 31, 2009 and 2008, respectively, for the amended
Windfall Profits Tax.
During the second quarter of 2009, PDVSA completed an actuarial study for their pension and
retirement plan. This pension and retirement plan covers all PDVSA employees and mixed
companies employees. Petrodelta is not required to reimburse the pension costs to PDVSA until
PDVSA pays the pension benefits to employees. In May 2009, upon completion of the review of
this actuarial study, PDVSA sent a statement to Petrodelta for its respective costs associated with
the pension and retirement plan. Petrodelta recorded additional pension expense of $15.6 million
($5.0 million net to our 32 percent interest) in the three month period ended June 30, 2009 based
on the statement received. The pension adjustment resulted from the completion of the first full
actuary study by PDVSA related to its employees that provide services to the mixed companies
and a refinement of managements assumptions related to credit for past service costs covering
the period from January 2008, when the Harvest Vinccler employees were migrated to PDVSA
payroll, through May 2009. At this time PDVSA did not have specific benefit information
related to each individual mixed company and thus allocated the pension obligation to each
mixed company assuming that the employees serving each of the mixed companies had the same
characteristics. The pension adjustment was a change in Petrodelta managements estimate based
on the new information provided by PDVSA.
During the fourth quarter of 2009, PDVSA completed an updated actuarial study as of December
31, 2009. This study was based on a further refinement of assumptions for each of the mixed
companies, including Petrodelta and a new allocation methodology as PDVSA gathered during
2009 all relevant information for each of the mixed companies. The revised pension obligation
allocated to Petrodelta resulted in a decrease of $8.4 million ($2.7 million net to our 32 percent
interest) to the pension and retirement plan costs as compared to those previously recorded to
Petrodelta in May 2009. This change in managements estimate related to the pension and
retirement plan costs was recorded in December 2009. Pension costs at December 31, 2009
reasonably reflect Petrodeltas employee demographic and plan conditions. The additional
pension cost is not tax deductible until future periods when the pension is settled in cash. The
provision for the pension plan is subject to future revisions, both upwards and downwards, based
on changes in assumptions, the terms of the relevant plans, the allocation methodology or other prospective amendments or changes as determined by PDVSA.
In June 2009, CVP issued instructions to Petrodelta to set up a reserve within the equity
section of the balance sheet for deferred tax assets. Petrodeltas bylaws state that Petrodeltas
shareholders are required to approve the setting up of special reserves. In August 2009,
Petrodeltas board of directors approved the setting up of the reserve. Although this reserve has
no effect on Petrodeltas financial position, results of operation or cash flows, it has the effect
of limiting future dividends to net income adjusted for deferred tax assets. Past dividends
received from Petrodelta represented Petrodeltas net income as reported under IFRS. Article 307
of the Venezuelan Commerce Code states that shareholders are not obligated to restore dividends
that have been distributed in good faith according to the entitys balances and sets the statute of
limitations for an entity to claim restoration of dividends at five years.
In 2005, Venezuela modified the Science and Technology Law (referred to as LOCTI in
Venezuela) to require companies doing business in Venezuela to invest, contribute, or spend a
percentage of their gross revenue
6
on projects to promote inventions or investigate technology in
areas deemed critical to Venezuela. LOCTI requires
major corporations engaged in activities covered by the Hydrocarbon and Gaseous Hydrocarbon
Law (OHL) to contribute two percent of their gross revenue generated in Venezuela from activities
specified in the OHL. The contribution is based on the previous 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 expects PDVSA to continue requesting and receiving waivers, Petrodelta has not
accrued a liability to LOCTI for the year ended December 31, 2009. The potential exposure to LOCTI
for the year ended December 31, 2009 is $9.5 million, $4.8 million net of tax ($1.5 million net to
our 32 percent interest).
In our Annual Report on Form 10-K for the year ended December 31, 2008, we reported that
Petrodelta had not received all information regarding production and operating costs during the
conversion period for the Temblador field in order to invoice all volumes produced in that field
during that period. As Temblador production was processed through the PDVSA system, PDVSA had
allocated only partial, estimated production to Petrodelta. As a result, Petrodelta had not, and
still has not, received full credit for the Temblador field production nor has Petrodelta been
invoiced for the related operating costs. Although we believe the amount of production, related
revenue and operating costs to be immaterial to Petrodelta, discussions are ongoing to settle
figures. During the third quarter of 2009, Petrodelta completed the facilities and pipelines to
segregate approximately 80 percent of the Temblador fields production into Petrodeltas system.
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 may continue 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.
On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange
Agreement which establishes new exchange rates for the Venezuela Bolivar (Bolivar)/United States
Dollar (U.S. Dollar) currencies that will enter into force on January 11, 2010. Each exchange
rate will be applied to foreign currency sales and purchases conducted through the Foreign Currency
Administration Commission (CADIVI), in the cases expressly provided in the Exchange Agreement.
In this regard, the exchange rates established in the Agreement are: 2.60 Bolivars per U.S. Dollar
and 4.30 Bolivars per U. S. Dollar. The 2.60 Bolivar exchange rate applies to the food, health,
medical and technology sectors. The 4.30 Bolivar exchange rate applies to all other sectors not
expressly established by the 2.60 Bolivar exchange rate. The
U.S. Dollar is the functional reporting currency for both Petrodelta and Harvest Vinccler.
Location and Geology
Petrodelta Fields
Uracoa Field
There are currently 78 oil and natural gas producing wells and six water injection wells in
the field. The current production facility has capacity to handle 60 thousand barrels (MBbls) of
oil per day, 130 MBbls of water per day, and storage of up to 75 MBbls of crude oil. All natural
gas presently being delivered by Petrodelta is produced from the Uracoa field.
7
Tucupita Field
There are currently 16 oil producing wells and four water injection wells in the field. The
Tucupita production facility has capacity to process 30 MBbls of oil per day, 125 MBbls of water
per day and storage for up to 60 MBbls of crude oil. The oil is transported through a 31-mile, 20
MBbls of oil per day pipeline from the
Tucupita field to the Uracoa plant facilities. 3-D seismic is available over the entire field and
is currently being reprocessed and reinterpreted.
Bombal Field
East Bombal was drilled in 1992, and currently remains underdeveloped. The West Bombal field
is currently inactive pending facility and pipeline upgrades. Development of East Bombal and West
Bombal has been incorporated into Petrodeltas business plan.
Isleño Field
The Isleño field was discovered in 1953. 2-D seismic data is available over a portion of the
field. Seven oil appraisal wells were drilled by PDVSA prior to the field being contributed to
Petrodelta which have confirmed the presence of commercial oil deposits. The field is located near
the Uracoa field existing infrastructure. Petrodeltas business plan projects full development of
the Isleño field over the next four years.
Temblador Field
The Temblador field was discovered in 1936 and developed in the 1940s and 1950s. There are
currently 19 oil producing wells in the field. The fluid produced from Temblador field flows
through two flow stations operated by Petrodelta. Approximately 80 percent of the Temblador
fields production flows through Petrodelta pipelines directly into PDVSAs system. The remaining
20 percent of the Temblador fields production flows through the EPT-1 plant operated by PDVSA. 3-D
seismic is available over the entire field.
El Salto Field
The El Salto field was discovered in 1936. Currently there is one oil producing well in the
field. A total of 31 appraisal wells were drilled by PDVSA prior to the field being contributed to
Petrodelta, identifying nine productive structures and six productive formations. Pilot production
from the one producing well commenced in the second quarter of 2009 through temporary facilities.
The second appraisal well will be tested after the permitting process with MENPET is completed. 3-D
seismic data is available over one-third of the field. We believe the El Salto field has
substantial exploration upside from several fault blocks, which have been identified using 2-D
seismic data but have not yet been confirmed through drilling.
Infrastructure and Facilities
Petrodelta has a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSAs
storage facility, the custody transfer point. The marketing contract specifies that the oil stream
may contain no more than one percent base sediment and one percent water. Quality measurements are
conducted both at Petrodeltas facilities and at PDVSAs storage facility. Approximately 20
percent of the Temblador production is currently delivered to the sales point in the EPT-1 PDVSA
facility through gathering systems integrated with the Jobo and Pilon fields operated by PDVSA and
is allocated to Petrodelta based on well tests. Petrodelta is working to segregate completely
Tembladors production.
Petrodelta has a 64-mile pipeline from Uracoa with a normal capacity of 70 million cubic feet
(MMcf) of natural gas per day and a design capacity of 90 MMcf of natural gas per day.
Petrodelta has agreements in place for purchase of power for the electrical needs, leasing of
compression, and operation and maintenance of the gas treatment and compression facilities at the
Uracoa and Tucupita fields through 2012.
8
Business Plan of Petrodelta
Petrodeltas focus in 2009 was the resumption of drilling in the Uracoa field, development
drilling in the Temblador field and appraisal drilling in the El Salto field which resulted in an
increase in production. Petrodelta is reprocessing existing 3-D seismic over Petrodeltas fields.
Temblador field production is processed at existing field facilities. El Salto production is being
process through temporary facilities. The El Salto field is believed to contain substantial
undeveloped and unexplored reserves. We expect to acquire additional 3-D seismic and undergo
significant appraisal and development in a timely manner to provide for larger scale development
implementation. Isleño field production can be integrated into the existing Uracoa field
infrastructure providing for early production from the field. Overall, production is expected to
peak in approximately ten years under Petrodeltas 2010 business plan.
Risk Factors
We face significant risks in holding a minority equity investment in Petrodelta. These risks
and other risk factors are discussed in Item 1A Risk Factors and Item 7 Managements
Discussion and Analysis of Financial Condition and Results of Operations.
United States Operations
During 2008, we initiated a domestic exploration program in two different basins. We are the
operator of both exploration programs and have complemented our existing personnel with the
addition of highly experienced management and technical personnel and with the acquisition of our
minority equity investment in Fusion.
Gulf Coast
General
In March 2008, we executed an AMI agreement with a private third party for an area in the
upper Gulf Coast Region of the United States. We are the operator and have initial working
interests of 55 percent in Starks, the first prospect in the AMI, and 50 percent in West Bay, the
second prospect in the AMI. The private third party contributed these two prospects, including the
leases and proprietary 3-D seismic data sets, and numerous leads generated over the last three
decades of regional geological focus. We agreed to fund the first $20 million of new lease
acquisitions, geological and geophysical studies, seismic reprocessing and drilling costs. At June
30, 2009, we had met the $20 million funding obligation under the terms of the AMI. All costs
incurred after June 30, 2009 are being shared by the parties in proportion to their working
interests as defined in the AMI. In August 2009, the AMI became a three party arrangement when the
private third party restructured and assigned a portion of its interest to one of its affiliates.
The private third parties are obligated to evaluate and present additional opportunities at
their sole cost. As each prospect is accepted it will be covered by the AMI. Although several
additional potential prospects had been screened and evaluated within the AMI since its inception,
we had not pursued leasing or drilling on any new projects within the AMI as of December 31, 2009.
On January 28, 2010, we entered into an agreement with one of the private third parties in our AMI
for an option to participate in a new project. We paid $1.5 million for the option to acquire up
to a 50 percent interest in the new project. If we exercise our option to participate, we will
participate in this project with essentially the same terms as the other existing projects in the
AMI. The option to participate expires on June 1, 2010.
Location and Geology
The AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana,
including state waters.
9
Drilling and Development Activity
We drilled an exploratory dry hole on the Starks prospect in 2008. In December 2009, we wrote
off the remaining carrying value of $0.7 million of the Starks prospect as we have no plans for
further activities relating to this prospect.
During the year ended December 31, 2009, operational activities in the West Bay prospect
included the interpretation of 3-D seismic, site surveying, and preparation of engineering
documents. Interpretation of 3-D seismic data on the West Bay project was completed in 2009 and
resulted in the identification of a set of drilling leads and prospects for the project. On July
14, 2009, we, along with our partner in the AMI, acquired 880 acres of shallow water offshore bay
leases representing two separate tracts from the State of Texas General Land Office at a state
lease sale for a total gross cost of $0.5 million. Acquisition of these two tracts completes the
planned land acquisition activities on the project.
The AMI participants are currently continuing to evaluate the leads and prospects to
determine priorities and drilling plans for the West Bay project and have identified the likely
initial drilling prospect. Land, regulatory, and surface access preparations are currently in
progress focused on taking the initial drilling prospect to drill-ready status. Current plans
are to drill the initial well in 2011.
Western United States Antelope
In October 2007, we entered into a JEDA with a private third party to pursue a lease
acquisition program and drilling program on the Antelope prospect in the Western United States. We
are the operator and had an initial working interest of 50 percent in the Antelope prospect. The
private third party is obligated to assemble the lease position on the Antelope prospect. The JEDA
provides that we would earn our initial 50 percent working interest in the Antelope prospect by
compensating the private third party for leases acquired in accordance with terms defined in the
JEDA, and by drilling and completing one deep natural gas test well (the Bar F) at our sole
expense. In November 2008, we entered into a Letter Agreement/Amendment of the JEDA (the Letter
Agreement) with the private third party. The Letter Agreement clarifies several open issues in
the JEDA, such as classification of $2.7 million of prepaid land costs for the Antelope prospect as
a note receivable, addition of a requirement for the private third party to partially assign leases
to us prior to meeting the lease earning obligation, and clarification of the private third partys
cost obligations for any shallow wells to be drilled on the Antelope prospect prior to the Bar F.
Per the Letter Agreement, payment of the $2.7 million note receivable was due from the private
third party on or by spud date of the Bar F. Since payment was not received prior to the Bar F
spud date, our interest in the Antelope prospect was increased to 60 percent, with the incremental
10 percent working interest being earned by drilling and completing the Bar F. The note receivable
remains outstanding and will be collected through sales revenues taken from a portion of the
private third partys net revenue from the Bar F provided the Bar F is commercial.
Activities are in progress on two separate projects on the Antelope prospect in Duchesne
County, Utah.
Mesaverde
General
The Mesaverde project is targeted to explore for and develop oil and natural gas from multiple
reservoir horizons in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties. Leads
and/or prospects were identified in three prospective reservoir horizons in preparation for
drilling.
Drilling and Development Activity
Operational activities during 2009 on the Mesaverde project focused on continuing leasing
activities on private, Allottee, and tribal land, and surveying, preliminary engineering,
permitting preparations, and conducting drilling operations on a deep natural gas test well (the
Bar F) that commenced drilling on June 15, 2009. The Bar F was permitted to 18,000 feet. The Bar
F was drilled to a total depth of 17,566 feet, and an extended production test
10
of multiple potential reservoir horizons is now in progress. To date, testing has been 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. Completion activities consisted of hydraulic fracturing of eight separate
reservoir intervals in the Mesaverde and multiple extended flow tests of the individual fractured
intervals, along with a flow test of the commingled eight intervals. While the results to date
have not definitively determined the commerciality of a stand-alone development of the Mesaverde,
we believe these results indicate progress toward that determination and that the Mesaverde
reservoir remains potentially prospective over a portion of our land position.
Earning of Undeveloped Acreage
Acreage for Mesaverde reflects the acreage that will be earned by us upon completion of the
drilling and testing of the first deep natural gas test well on the project. We anticipate
completing the lease earning obligation in 2010. If, however, the earning well is not completed in
accordance with the requirements of the JEDA, we will have an obligation to assign our interest in
the acreage back to the private third party in accordance with the terms of the Letter Agreement.
Monument Butte
General
The Monument Butte project is an eight well appraisal and development drilling program to
produce oil and natural gas from the Green River formation on the southern portion of our Antelope
land position. The Monument Butte project is non-operated and we hold a 43 percent working
interest. The parties have formed a 320 acre AMI which contained the eight drilling locations.
Drilling and Development Activity
Operational activities during 2009 on the Monument Butte project focused on resolution of
forced pooling issues with non-consenting interests, negotiations and finalization of an agreement
with the operator for the joint drilling operations. As of March 1, 2010, all eight wells have
been drilled. Seven wells are currently on production. One additional well is waiting on
completion operations and is anticipated to commence production in early March 2010.
Budong-Budong, Onshore Indonesia
General
In February 2008, Indonesias oil and gas regulatory authority, BP Migas, approved the
assignment to us of a 47 percent interest in the Budong PSC located mainly onshore West Sulawesi,
Indonesia. Final government approval from the Ministry of Energy and Mineral Resources, Migas, was
received in April 2008. Our partner will be the operator through the exploration phase as required
by the terms of the Budong PSC. We will have control of major decisions and financing for the
project with an option to become operator, if approved by BP Migas, in the subsequent development
and production phase.
Location and Geology
The Budong PSC covers 1.35 million acres and includes the Lariang and Karama sub-basins, which
are the eastern onshore extension of the West Sulawesi foldbelt (WSFB). Exploration to date in
the basin is immature due to previously difficult jungle terrain, which is now accessible with the
development of palm oil plantations and their related infrastructure. Field work performed over
the last 10 years, as outcrops have been more accessible, has given a new understanding to the
presence of Eocene source and reservoir potential that had not previously been recognized. Recent
seismic surveys have greatly improved the understanding of the geology and enhanced the
prospectivity of the offshore WSFB and, by analogy, the sparsely explored onshore area.
11
Drilling and Development Activity
Operational activities during 2009 focused on the interpretation of 650 kilometers of 2-D
seismic and well planning. Two drill sites have been selected. Currently, the locations for the
two test wells are being constructed and the rig and ancillary equipment is being mobilized to the
area. It is expected that the first of two exploration
wells will spud early in the second quarter of 2010. In accordance with the farm-in
agreement, we expect to fund 100 percent of the well expenditures to earn our 47 percent working
interest up to a cap of $10.7 million; thereafter, we will pay in proportion to our working
interest.
Title to Undeveloped Acreage
We acquired the 47 percent interest in the Budong PSC by committing to fund the first phase of
the exploration program including the acquisition of 2-D seismic and drilling of the first two
exploration wells. This commitment is capped at $17.2 million. Prior to drilling the first
exploration well, subject to the estimated cost of that well, our partner will have a one-time
option to increase the level of the carried interest to a maximum of $20.0 million, and as
compensation for the increase, we will increase our participation to a maximum of 54.65 percent.
This equates to a total carried cost for the farm-in of $9.1 million.
Dussafu Marin, Offshore Gabon
General
In 2008, we completed the purchase of a 66.667 percent interest in the Dussafu PSC for $6.0
million. We are the operator of the Dussafu PSC.
Location and Geology
The Dussafu PSC contract area is located offshore Gabon, adjacent to the border with the
Republic of Congo. It contains 680,000 acres with water depths to 1,000 feet. The Dussafu PSC has
two small oil discoveries in the Gamba and Dentale reservoirs and a small natural gas discovery.
Production and infrastructure exists in the blocks contiguous to the Dussafu PSC.
Drilling and Development Activity
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. The second
exploration phase comprises a three-year work commitment which includes the acquisition and
processing of 500 kilometers of 2-D seismic, geology and geophysical interpretation, engineering
studies and the drilling of a conditional well. Operational activities during 2009 focused on
completion of the processing and reprocessing of 1,330 kilometers of 2-D seismic and the pre-stack
depth reprocessing of 1,076 square kilometers of 3-D seismic data. The improved imaging from this
work has allowed the interpretation to mature the prospect inventory to provide the partnership a
number of prospective targets in the sub-salt section, in both the Gamba and Syn-rift plays that
are productive in the nearby Etame, Lucina and MBya fields. Subject to drilling rig availability,
we expect to drill an exploration well in the third quarter of 2010.
Oman
General
On April 11, 2009, we signed an Exploration and Production Sharing Agreement (EPSA) with
Oman for the Al Ghubar/Qarn Alam license. 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.
12
Location and Geology
Block 64 EPSA is a newly-created block designated for exploration and production of
non-associated gas and condensate which the Oman Ministry of Oil and Gas has carved out of the
Block 6 Concession operated by Petroleum Development of Oman (PDO). The 3,867 square kilometer
(955,600 acres) block is located in the gas and condensate rich Ghaba Salt Basin in close proximity
to the Barik, Saih Rawl and Saih Nihayda gas and condensate fields.
Drilling and Development Activity
PDO will continue to produce oil from several fields within Block 64 EPSA area. We have an
obligation to drill two wells over a three year period with a funding commitment of $22.0 million.
Current activities include the compilation of existing data, over two prospect areas of
approximately 1,000 square kilometers and geological studies to determine drillable prospects.
Well planning is expected to commence in 2010 for exploration drilling in 2011.
WAB-21, South China Sea
General
In December 1996, we acquired a petroleum contract with China National Offshore Oil
Corporation (CNOOC) for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres
in the South China Sea, with an option for an additional 1.25 million acres under certain
circumstances, and lies within an area which is the subject of a border dispute between the
Peoples Republic of China (China) and Socialist Republic of Vietnam (Vietnam). Vietnam has
executed an agreement on a portion of the same offshore acreage with another company. The border
dispute has lasted for many years, and there has been limited exploration and no development
activity in the WAB-21 area due to the dispute. It is uncertain when or how this dispute will be
resolved, and under what terms the various countries and parties to the agreements may participate
in the resolution.
Location and Geology
The WAB-21 contract area is located in the West Wan an Bei Basin (Nam Con Son) of the South
China Sea. Its western edge lies approximately 20 miles to the east of significant producing
natural gas fields, Lan Tay and Lan Do, which are reported to contain two trillion cubic feet
(Tcf) of natural gas and commenced production in November 2002. Also located to the west of
WAB-21 are the Dua and Chim Sao (formerly Blackbird) discoveries and the discovery in 2009 of Ca
Rong. The Chim Sao oil field has recently received development approval. The WAB-21 contract area
covers a large unexplored area of the Wan an Bei Basin where the same successful Lower Miocene
through to Upper Miocene plays to the west are present. Exploration success in the basin to date
has resulted in discoveries estimated to total in excess of 500 million barrels of oil and 7.5 Tcf
of natural gas. Several similar structural trends and geological formations, each with significant
potential for hydrocarbon reserves in traps with multiple pay zones similar to the known fields and
discoveries to the west are present within WAB-21.
Drilling and Development Activity
Due to the border dispute between China and Vietnam, we have been unable to pursue an
exploration program during Phase One of the contract. As a result, we have obtained license
extensions, with the current extension in effect until May 31, 2011. While no assurance can be
given, we believe we will continue to receive contract extensions so long as the border disputes
persist. Recently, Vietnam, along with the company that is the party to the agreement with
Vietnam, announced plans for exploration drilling during 2010. While no assurance can be given, we
believe this announcement may provide some resolution with the border disputes, although we do not
know in what manner any resolution might appear.
Production, Prices and Lifting Cost Summary
In the following table we have set forth, by country, our net production, average
sales prices and average operating expenses for the years ended December 31, 2009, 2008 and 2007.
The presentation for Venezuela
13
includes 100 percent of Petrodeltas production. The United States is presented at our ownership
interest. In thousands, except per unit information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2009 |
|
2008 |
|
2007 |
Venezuela(a) |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Production (Bbls) |
|
|
7,835 |
|
|
|
5,505 |
|
|
|
5,374 |
|
Natural Gas Production (Mcf)(b) |
|
|
4,397 |
|
|
|
10,700 |
|
|
|
13,456 |
|
Average Crude Oil Sales Price ($per Bbl) |
|
$ |
57.62 |
|
|
$ |
83.22 |
|
|
$ |
58.61 |
|
Average Natural Gas Sales Price ($ per Mcf) |
|
$ |
1.54 |
|
|
$ |
1.54 |
|
|
$ |
1.54 |
|
Average Operating Expenses ($ per Boe)(c) |
|
$ |
8.46 |
|
|
$ |
10.90 |
|
|
$ |
4.20 |
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
Monument Butte(d) |
|
|
|
|
|
|
|
|
|
|
|
|
Net Crude Oil Production (Bbls) |
|
|
3 |
|
|
|
|
|
|
|
|
|
Natural Gas Production (Mcf) |
|
|
6 |
|
|
|
|
|
|
|
|
|
Average Crude Oil Sales price ($per Bbl) |
|
$ |
61.61 |
|
|
$ |
|
|
|
$ |
|
|
Average Natural Gas Sales Price ($ per Mcf) |
|
$ |
2.77 |
|
|
$ |
|
|
|
$ |
|
|
Average Operating Expenses ($ per Boe) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
(a) |
|
Information represents 100 percent of production. |
|
(b) |
|
Royalty-in-kind paid on gas used as fuel was 3,323 Mcf and 3,830 Mcf for 2009 and 2008,
respectively. |
|
(c) |
|
Net of royalty and excluding workovers. |
|
(d) |
|
Information represents our ownership interest. |
Drilling and Undeveloped Acreage
For acquisitions of leases, development and exploratory drilling, we spent approximately
(excluding our share of capital expenditures incurred by equity affiliates) $28.0 million, $26.3
million and $0.6 million in 2009, 2008 and 2007, respectively. These numbers do not include any
costs for the development of proved undeveloped reserves in 2009, 2008 or 2007.
We have participated in the drilling of wells as follows:
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2009 |
|
2008 |
|
2007 |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Wells Drilled: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Venezuela (Petrodelta) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development |
|
|
15 |
|
|
|
4.8 |
|
|
|
9 |
|
|
|
2.9 |
|
|
|
|
|
|
|
|
|
Appraisal |
|
|
2 |
|
|
|
0.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development |
|
|
5 |
|
|
|
2.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
1 |
|
|
|
1.0 |
|
|
|
1 |
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Depth of Wells (Feet) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Venezuela (Petrodelta) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
|
6,500 |
|
|
|
|
|
|
|
6,500 |
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
|
6,751 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
|
|
|
|
17,566 |
|
|
|
|
|
|
|
12,290 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing Wells (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Venezuela (Petrodelta) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
114 |
|
|
|
36.5 |
|
|
|
118 |
|
|
|
37.8 |
|
|
|
97 |
|
|
|
31.0 |
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
2 |
|
|
|
0.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The information related to producing wells reflects wells we drilled, wells we
participated in drilling and producing wells we acquired. |
All of our drilling activities are conducted on a contract basis with independent drilling
contractors. We do not directly operate any drilling equipment.
Acreage
The following table summarizes the developed and undeveloped acreage that we owned, leased or
held under concession as of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
Undeveloped |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Venezuela Petrodelta |
|
|
23,050 |
|
|
|
9,220 |
|
|
|
224,063 |
|
|
|
89,625 |
|
China |
|
|
|
|
|
|
|
|
|
|
7,470,080 |
|
|
|
7,470,080 |
|
United States: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Bay |
|
|
|
|
|
|
|
|
|
|
12,808 |
|
|
|
6,316 |
|
Antelope |
|
|
212 |
|
|
|
90 |
|
|
|
111,457 |
|
|
|
36,536 |
|
Indonesia |
|
|
|
|
|
|
|
|
|
|
1,357,723 |
|
|
|
638,130 |
|
Gabon |
|
|
|
|
|
|
|
|
|
|
685,470 |
|
|
|
456,982 |
|
Oman |
|
|
|
|
|
|
|
|
|
|
955,600 |
|
|
|
955,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
23,262 |
|
|
|
9,310 |
|
|
|
10,817,201 |
|
|
|
9,653,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulation
General
Our operations and our ability to finance and fund our growth strategy are affected by
political developments and laws and regulations in the areas in which we operate. In particular,
oil and natural gas production operations and economics are affected by:
15
|
|
|
civil unrest; |
|
|
|
|
price and currency controls; |
|
|
|
|
limitations on oil and natural gas production; |
|
|
|
|
tax, environmental, safety and other laws relating to the petroleum industry; |
|
|
|
|
changes in laws relating to the petroleum industry; |
|
|
|
|
changes in administrative regulations and the interpretation and application of such
rules and regulations; and |
|
|
|
|
changes in contract interpretation and policies of contract adherence. |
In any country in which we may do business, the oil and natural gas industry legislation and
agency regulation are periodically changed, sometimes retroactively, for a variety of political,
economic, environmental and other reasons. Numerous governmental departments and agencies issue
rules and regulations binding on the oil and natural gas industry, some of which carry substantial
penalties for the failure to comply. The regulatory burden on the oil and natural gas industry
increases our cost of doing business and our potential for economic loss.
Competition
We encounter substantial competition from major, national and independent oil and natural gas
companies in acquiring properties and leases for the exploration and development of crude oil and
natural gas. The principal competitive factors in the acquisition of such oil and natural gas
properties include staff and data necessary to identify, investigate and purchase such properties,
the financial resources necessary to acquire and develop such properties, and access to local
partners and governmental entities. Many of our competitors have influence, financial resources,
staffs, data resources and facilities substantially greater than ours.
Environmental Regulation
Various federal, state, local and international laws and regulations relating to the discharge
of materials into the environment, the disposal of oil and natural gas wastes, or otherwise
relating to the protection of the environment may affect our operations and costs. We are
committed to the protection of the environment and believe we are in substantial compliance with
the applicable laws and regulations. However, regulatory requirements may, and often do, change
and become more stringent, and there can be no assurance that future regulations will not have a
material adverse effect on our financial position, results of operations and cash flows.
Employees
At December 31, 2009, our Houston office had 23 full-time employees. Our Utah, Caracas,
London, Singapore, Jakarta and Muscat offices had 1, 14, 7, 3, 4 and 3 employees, respectively. We
augment our employees from time to time with independent consultants, as required. We closed our
Moscow office on March 31, 2009.
Item 1A. Risk Factors
In addition to other information set forth elsewhere in this Annual Report on Form 10-K, the following
factors should be carefully considered when evaluating us.
Our cash position and limited ability to access additional capital may limit our growth
opportunities. At December 31, 2009, we had $32 million of available cash and, until Petrodelta
pays a dividend or the revenue from our U.S. operations increases substantially, cash available
from operations will not be sufficient to meet operational requirements. Having a Petrodelta
dividend as our primary source of cash flow limits our access to additional capital, and our
concentration of political risk in Venezuela may limit our ability to leverage our assets. In
addition, our future cash position depends upon the payment of dividends by Petrodelta or success
with our exploration program. While we believe that Petrodelta will reinvest any excess cash which
might be available for payment of dividends into Petrodelta in 2010 and 2011, there is no assurance
this will be the case, nor that if the cash is not reinvested that it will be paid as dividends.
These factors could have a material adverse effect on our financial condition and liquidity and may
limit our ability to grow through the acquisition or exploration of additional oil and gas
properties and projects.
16
We have incurred long-term indebtedness obligations, which significantly increased our
leverage. On February 17, 2010, we closed a debt offering of $32.0 million in aggregate principal
amount of our 8.25 percent senior convertible notes due 2013. Prior to the offering, we had no
long-term debt obligations. The degree to which we are leveraged could, among other things:
|
|
|
make it difficult for us to make payments on the notes; |
|
|
|
|
make it difficult for us to obtain financing for working capital, acquisitions or
other purposes on favorable terms, if at all; |
|
|
|
|
make us more vulnerable to industry downturns and competitive pressures; and |
|
|
|
|
limit our flexibility in planning for, or reacting to changes in, our business. |
Our ability to meet our debt service obligations will depend upon our future performance,
which will be subject to financial, business and other factors affecting our operations, many of
which are beyond our control. Additionally, the covenants contained in the indenture governing the
notes restrict, among other things, our ability to incur certain indebtedness. Any failure to
comply with these covenants could result in an event of default under the indenture, which could
permit acceleration of the indebtedness under the notes. If our indebtedness were to be
accelerated, we cannot assure you that we would be able to repay it.
We may incur significant indebtedness in the near future. We continually assess our need for
additional sources of financing based on our operational, working capital and other needs from time
to time. In addition, we are currently contemplating one particular additional source of financing
through an Islamic (sukuk) financing, in which one of our subsidiaries would form and contribute
certain assets to a partnership and subsequently sell a minority interest in the partnership to one
or more third parties for approximately $250 million. Although the terms of this transaction have
not been finalized, we anticipate that the terms would include our agreement to pay all or a
substantial portion of the future dividends paid by Petrodelta over the next five or six years to
reacquire all of the third-party partnership interests, including premiums thereon. While we may
be able to consummate this financing transaction during the first half of 2010, there can be no
assurances that this transaction will be consummated, and we may consider alternative forms of
additional financing if we deem necessary or advisable with respect to our operations from time to
time.
Global market and economic conditions, including those related to the credit markets, could
have a material adverse effect on our business, financial condition and results of operations. A
general slowdown in economic activity could adversely affect our business by impacting our ability
to access additional capital, the receipt of dividends from Petrodelta as well as the need to
preserve adequate development capital in the interim.
We may not be able to meet the requirements of the global expansion of our business strategy.
We have added a significant global exploration component to diversify our overall portfolio. In
many locations, we may be required to post performance bonds in support of a work program. We also
intend to acquire underdeveloped, undeveloped and exploration properties from time to time for
which the primary risks may be technical, operational or both.
Our strategy to identify, access and integrate hydrocarbon assets in known hydrocarbon basins
globally carries greater deal execution, operating, financial, legal and political risks. The
environments in which we operate are often difficult and the ability to operate successfully will
depend on a number of factors, including our ability to control the pace of development, our
ability to apply best practices in drilling and development, and the fostering of productive and
transparent relationships with local partners, the local community and governmental authorities.
Financial risks include our ability to control costs and attract financing for our projects. In
addition, often the legal systems of these countries are not mature and their reliability is
uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to
develop and operate oil and natural gas projects, as well as our ability to obtain adequate
compensation for any resulting losses. Our strategy depends on our ability to have significant
influence over operations and financial control.
Operations in areas outside the United States are subject to various risks inherent in foreign
operations. Our operations are subject to various risks inherent in foreign operations. These
risks may include, among other things, loss of revenue, property and equipment as a result of
hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other political risks, increases in
taxes and governmental
17
royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts or tribunals, renegotiation of contracts with governmental entities,
changes in laws and policies, including taxes, governing operations of foreign-based companies,
currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign
government sovereignty over our international operations. Our international operations may also be
adversely affected by laws and policies of the United States affecting foreign policy, foreign
trade, taxation and the possible inability to subject foreign persons to the jurisdiction of the
courts in the United States.
Operations on the Uintah and Ouray Reservation of the Ute Indian Tribe in the western United
States are subject to various risks similar to those for foreign operations. Similar to our
operations in foreign jurisdictions, our operations on the Uintah and Ouray Reservation of the Ute
Indian Tribe are subject to certain risks. These risks may include, among other things, loss of
revenue, property and equipment as a result of hazards such as civil unrest, strikes and other
political risks, increases in taxes or fees, being subject to tribal laws, changes in tribal laws
and policies and other uncertainties arising out of tribal sovereignty.
Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This Annual
Report on Form 10-K contains estimates of our oil and natural gas reserves. These estimates are
based upon various assumptions, including assumptions required by the SEC relating to oil prices,
drilling and operating expenses, capital expenditures, taxes and availability of funds.
The process of estimating oil and natural gas reserves is complex, requiring significant
decisions and assumptions in the evaluation of available geological, geophysical, engineering and
economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual
future production, oil and natural gas prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable oil and natural gas reserves likely will vary from those
estimated. Any significant variance could materially affect the estimated quantities and present
value of reserves set forth. Actual production, revenue, taxes, development expenditures and
operating expenses with respect to our reserves will likely vary from the estimates used, and these
variances may be material.
You should not assume that the present value of future net revenues referred to in Part IV,
Item 15 Supplemental Information on Oil and Natural Gas Producing Activities (unaudited), TABLE
V Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas
Reserve Quantities is the current market value of our estimated oil and natural gas reserves. In
accordance with SEC requirements, the estimated discounted future net cash flows from proved
reserves are generally based on the unweighted average price of the first day of the month during
the 12-month period before the ending date of the period covered by the reserve report and costs as
of the date of the estimate. Actual future prices and costs may be materially higher or lower than
the prices and costs as of the date of the estimate. Any changes in demand, changes in our ability
to produce or changes in governmental regulations, policies or taxation will also affect actual
future net cash flows. The timing of both the production and the expenses from the development and
production of oil and natural gas properties will affect the timing of actual future net cash flows
from estimated proved reserves and their present value. In addition, the 10 percent discount
factor, which is required by the SEC to be used in calculating discounted future net cash flows for
reporting purposes, is not necessarily the most accurate discount factor. The effective interest
rate at various times and the risks associated with the oil and natural gas industry in general
will affect the accuracy of the 10 percent discount factor.
We may not be able to replace production with new reserves. In general, production rates and
remaining reserves from oil and natural gas properties decline as reserves are depleted. The
decline rates depend on reservoir characteristics. Our future oil and natural gas production is
highly dependent upon our level of success in finding or acquiring additional reserves. The
business of exploring for, developing or acquiring reserves is capital intensive and uncertain. We
may be unable to make the necessary capital investment to maintain or expand our oil and natural
gas reserves if cash flow from operations is reduced and external sources of capital become limited
or unavailable. We cannot give any assurance that our future exploration, development and
acquisition activities will result in additional proved reserves or that we will be able to drill
productive wells at acceptable costs.
Our future operations and our investments in equity affiliates are subject to numerous risks
of oil and natural gas drilling and production activities. Oil and natural gas exploration and
development drilling and production activities are subject to numerous risks, including the risk that no commercially
productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells
is often uncertain. Oil and natural gas
18
drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control.
These factors include:
|
|
|
unexpected drilling conditions; |
|
|
|
|
pressure or irregularities in formations; |
|
|
|
|
equipment failures or accidents; |
|
|
|
|
weather conditions; |
|
|
|
|
shortages in experienced labor; |
|
|
|
|
delays in receiving necessary governmental permits; |
|
|
|
|
delays in receiving partner approvals; |
|
|
|
|
shortages or delays in the delivery of equipment; |
|
|
|
|
delays in receipt of permits or access to lands; and |
|
|
|
|
government actions or changes in regulations. |
The prevailing price of oil also affects the cost of and availability for drilling rigs,
production equipment and related services. We cannot give any assurance that the new wells we
drill will be productive or that we will recover all or any portion of our investment. Drilling
for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells
that are productive but do not produce sufficient net revenues after operating and other costs.
Our oil and natural gas operations are subject to various governmental regulations that
materially affect our operations. Our oil and natural gas operations are subject to various
governmental regulations. These regulations may be changed in response to economic or political
conditions. Matters regulated may include permits for discharges of wastewaters and other
substances generated in connection with drilling operations, bonds or other financial
responsibility requirements to cover drilling contingencies and well plugging and abandonment
costs, reports concerning operations, the spacing of wells, and unitization and pooling of
properties and taxation. At various times, regulatory agencies have imposed price controls and
limitations on oil and natural gas production. In order to conserve or limit supplies of oil and
natural gas, these agencies have restricted the rates of the flow of oil and natural gas wells
below actual production capacity. We cannot predict the ultimate cost of compliance with these
requirements or their effect on our operations.
We are subject to complex laws that can affect the cost, manner or feasibility of doing
business. Exploration and development and the production and sale of oil and natural gas are
subject to extensive federal, state, local and international regulation. We may be required to make
large expenditures to comply with environmental and other governmental regulations. Matters
subject to regulation include:
|
|
|
the amounts and types of substances and materials that may be released into the
environment; |
|
|
|
|
response to unexpected releases to the environment; |
|
|
|
|
reports and permits concerning exploration, drilling, production and other operations; |
|
|
|
|
the spacing of wells; |
|
|
|
|
unitization and pooling of properties; |
|
|
|
|
calculating royalties on oil and gas produced under federal and state leases; and |
|
|
|
|
taxation. |
Under these laws, we could be liable for personal injuries, property damage, oil spills,
discharge of hazardous materials, remediation and clean-up costs, natural resource damages and
other environmental damages. We also could be required to install expensive pollution control
measures or limit or cease activities on lands located within wilderness, wetlands or other
environmentally or politically sensitive areas. Failure to comply with these laws also may result
in the suspension or termination of our operations and subject us to administrative, civil and
criminal penalties as well as the imposition of corrective action orders. Moreover, these laws
could change in ways that substantially increase our costs. Any such liabilities, penalties,
suspensions, terminations or regulatory changes could have a material adverse effect on our
financial condition, results of operations or cash flows.
Potential regulations regarding climate change could alter the way we conduct our business.
Governments around the world are beginning to address climate change matters. This may result in
new
19
environmental regulations that may unfavorably impact us, our suppliers and our customers. The
cost of meeting these requirements may have an adverse impact on our financial condition, results
of operations and cash flows.
Competition within the industry may adversely affect our operations. We operate in a highly
competitive environment. We compete with major, national and independent oil and natural gas
companies for the acquisition of desirable oil and natural gas properties and the equipment and
labor required to develop and operate such properties. Many of these competitors have financial
and other resources substantially greater than ours.
The loss of key personnel could adversely affect our ability to successfully execute our
strategy. We are a small organization and depend on the skills and experience of a few individuals
in key management and operating positions to execute our business strategy. Loss of one or more
key individuals in the organization could hamper or delay achieving our strategy.
We no longer directly manage operations of Petrodelta. PDVSA, through CVP, exercises
substantial control over Petrodeltas operations, making Petrodelta subject to some internal
policies and procedures of PDVSA as well as being subject to constraints in skilled personnel
available to Petrodelta. These issues may have an adverse effect on the efficiency and
effectiveness of Petrodeltas operations.
We hold a minority equity investment in Petrodelta. Even though we have substantial negative
control provisions as a minority equity investor in Petrodelta, our control of Petrodelta is
limited to our rights under the Conversion Contract and its annexes and Petrodeltas charter and
bylaws. As a result, our ability to implement or influence Petrodeltas business plan, assure
quality control, and set the timing and pace of development may be adversely affected. In
addition, the majority partner, CVP, has initiated and undertaken numerous unilateral decisions
that can impact our minority equity investment.
Petrodeltas business plan will be sensitive to market prices for oil. Petrodelta operates
under a business plan, the success of which will rely heavily on the market price of oil. To the
extent that market values of oil decline, the business plan of Petrodelta may be adversely
affected.
A decline in the market price of crude oil could uniquely affect the financial condition of
Petrodelta. Under the terms of the Conversion Contract and other governmental documents,
Petrodelta is subject to a special advantage tax (ventajas especiales) which requires that if in
any year the aggregate amount of royalties, taxes and certain other contributions is less than 50
percent of the value of the hydrocarbons produced, Petrodelta must pay the government of Venezuela
the difference. In the event of a significant decline in crude prices, the ventajas especiales
could force Petrodelta to operate at a loss. Moreover, our ability to control those losses by
modifying Petrodeltas business plan or restricting the budget is limited under the Conversion
Contract.
An increase in oil prices could result in increased tax liability in Venezuela affecting
Petrodeltas operations and profitability, which in turn could affect our dividends and
profitability. Prices for oil fluctuate widely. On July 10, 2008, the Venezuelan government
published the amended Windfall Profits Tax to be calculated on the VEB of prices as published by
MENPET. The amended 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. Any increase in the taxes payable by Petrodelta, including the Windfall Profits
Tax, as a result of increased oil prices will reduce cash available for dividends to us and our
partner, CVP.
Oil price declines and volatility could adversely affect Petrodeltas operations and
profitability, which in turn could affect our dividends and profitability. Prices for oil also
affect the amount of cash flow available for capital expenditures and dividends from Petrodelta.
Lower prices may also reduce the amount of oil that we can produce economically and lower oil
production could affect the amount of natural gas we can produce. We cannot predict future oil
prices. Factors that can cause fluctuations in oil prices include:
|
|
|
relatively minor changes in the global supply and demand for oil; |
|
|
|
|
export quotas; |
|
|
|
|
market uncertainty; |
|
|
|
|
the level of consumer product demand; |
20
|
|
|
weather conditions; |
|
|
|
|
domestic and foreign governmental regulations and policies; |
|
|
|
|
the price and availability of alternative fuels; |
|
|
|
|
political and economic conditions in oil-producing and oil consuming countries; and |
|
|
|
|
overall economic conditions. |
The total capital required for development of Petrodeltas assets may exceed the ability of
Petrodelta to finance such developments. Petrodeltas ability to fully develop the fields in
Venezuela will require a significant investment. Petrodeltas future capital requirements for the
development of its assets may exceed the cash available from existing cash flow. Petrodeltas
ability to secure financing is currently limited and uncertain, and has been, and may be, affected
by numerous factors beyond its control, including the risks associated with operating in Venezuela.
Because of this financial risk, Petrodelta may not be able to secure either the equity or debt
financing necessary to meet its future cash needs for investment, which may limit its ability to
fully develop the properties, cause delays with their development or require early divestment of
all or a portion of those projects. This could negatively impact our minority equity investment.
If we are called upon to fund our share of Petrodeltas operations, our failure to do so could be
considered a default under the Conversion Contract and cause the forfeiture of some or all our
shares in Petrodelta. In addition, CVP may be unable or unwilling to fund its share of capital
requirements and our ability to require them to do so is limited.
The legal or fiscal regime for Petrodelta may change and the Venezuelan government may not
honor its commitments. While we believe that the Conversion Contract and Petrodelta provide a
basis for a more durable arrangement in Venezuela, the value of the investment necessarily depends
upon Venezuelas maintenance of legal, tax, royalty and contractual stability. Our recent
experiences in Venezuela demonstrate that such stability cannot be assured. While we have and will
continue to take measures to mitigate our risks, no assurance can be provided that we will be
successful in doing so or that events beyond our control will not adversely affect the value of our
minority equity investment in Petrodelta.
PDVSAs failure to timely pay contractors could have an adverse affect on Petrodelta. 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 may continue 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.
Tax claims by municipalities in Venezuela may adversely affect Harvest Vincclers financial
condition. The municipalities of Uracoa and Libertador have asserted numerous tax claims against
Harvest Vinccler which we believe are without merit. However, the reliability of Venezuelas
judicial system is a source of concern and it can be subject to local and political influences.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
In April 2004, we signed a ten-year lease for office space in Houston, Texas, for
approximately $17,000 per month. In December 2008, we signed a five-year lease for additional
office space in Houston, Texas, for approximately $15,000 per month. In November 2008, Harvest
Vinccler extended its lease for office space in Caracas, Venezuela for two years for approximately $10,000 per month. In August 2008, we
signed a two-year lease in Roosevelt, Utah for approximately $6,000 per month. In October 2008, we
signed a two-year lease for
21
office space in Singapore for approximately $19,000 per month. In April 2009, we signed a two-year lease for office space in Indonesia for approximately $5,000 per
month. In September 2009, we signed a two-year lease for office space in Oman for approximately
$5,000 per month. In November 2009, we signed a one-year lease for office space in London for approximately $24,000 per month.
See Item 1 Business for a description of our oil and gas properties.
Item 3. Legal Proceedings
Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural
Resources, Inc., Chemex, Inc., Benton-Vinccler, C.A., Gale Campbell and Sheila Campbell in the
District Court for Harris County, Texas. This suit was brought in May 2003 by Excel alleging,
among other things, breach of a consulting agreement between Excel and us, misappropriation of
proprietary information and trade secrets, and fraud. Excel seeks actual and exemplary damages,
injunctive relief and attorneys fees. In April 2007, the court set the case for trial. The trial
date, reset for the first quarter of 2009, had been stayed indefinitely. On October 20, 2009, the
stay was lifted. A trial date of November 1, 2010 has been set. We dispute Excels 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 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. |
22
|
|
|
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. |
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.
In June 2007, the SENIAT issued an assessment for taxes in the amount of $0.4 million for
Harvest Vincclers failure to withhold VAT from vendors during 2005. Also, the SENIAT imposed
penalties and interest in the amount of $1.3 million for Harvest Vincclers failure to withhold
VAT. In July 2008, the SENIAT adjusted the assessment for penalties and interest to the change in
tax units as mandated by the Venezuelan tax code and issued a new assessment for $2.3 million. The
change in assessment resulted in an additional $1.0 million expense recorded in the year ended
December 31, 2008. In August 2008, Harvest Vinccler filed an appeal in the tax courts and
presented a proposed settlement with the SENIAT. In October 2008, after consideration of our
proposed settlement, the SENIAT offered a counter-proposal which Harvest Vinccler accepted.
Throughout 2009, the General Attorney Office and Harvest Vinccler agreed several times to resuspend
the case while the Finance Minister and the SENIAT confirmed their acceptance to the proposed
settlement. On December 30, 2009, Harvest Vinccler settled the case for 3.1 million Bolivars
(approximately $1.4 million) for penalties and interest and closed the case with the SENIATs
concurrence. As a result of the settlement, in December 2009, Harvest Vinccler reversed $0.9
million of accrued penalties and interest previously accrued based on notices received from the
SENIAT.
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.
PART II
|
|
|
Item 5. |
|
Market for Registrants Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities |
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our common stock is traded on the NYSE under the symbol HNR. As of December 31, 2009, there
were 33,281,385 shares of common stock outstanding, with approximately 515 stockholders of record.
The following table sets forth the high and low sales prices for our Common Stock reported by the
NYSE.
23
|
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|
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|
|
|
|
|
Year |
|
Quarter |
|
High |
|
Low |
2008 |
|
First quarter |
|
$ |
13.02 |
|
|
$ |
10.32 |
|
|
|
Second quarter |
|
|
12.84 |
|
|
|
9.03 |
|
|
|
Third quarter |
|
|
11.31 |
|
|
|
9.06 |
|
|
|
Fourth quarter |
|
|
9.59 |
|
|
|
3.84 |
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
First quarter |
|
|
4.69 |
|
|
|
2.70 |
|
|
|
Second quarter |
|
|
5.66 |
|
|
|
3.25 |
|
|
|
Third quarter |
|
|
6.64 |
|
|
|
4.24 |
|
|
|
Fourth quarter |
|
|
6.39 |
|
|
|
4.90 |
|
On March 9, 2010, the last sales price for the common stock as reported by the NYSE was $5.48
per share.
Our policy is to retain earnings to support the growth of our business. Accordingly, our
Board of Directors has never declared a cash dividend on our common stock.
STOCK PERFORMANCE GRAPH
The graph below shows the cumulative total stockholder return over the five-year period ending
December 31, 2009, assuming an investment of $100 on December 31, 2004 in each of Harvests common
stock, the Dow Jones U.S. Exploration & Production Index and the S&P Composite 500 Stock Index.
This graph assumes that the value of the investment in Harvest stock and each index was $100
at December 31, 2004 and that all dividends were reinvested.
24
PLOT POINTS
(December 31 of each year)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
|
2005 |
|
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
Harvest Natural
Resources, Inc. |
|
$ |
100 |
|
|
$ |
51 |
|
|
$ |
62 |
|
|
$ |
72 |
|
|
$ |
25 |
|
|
$ |
31 |
|
Dow Jones US E&P Index |
|
$ |
100 |
|
|
$ |
166 |
|
|
$ |
174 |
|
|
$ |
244 |
|
|
$ |
142 |
|
|
$ |
201 |
|
S&P 500 Index |
|
$ |
100 |
|
|
$ |
105 |
|
|
$ |
121 |
|
|
$ |
128 |
|
|
$ |
81 |
|
|
$ |
102 |
|
Total Return Data provided by S&Ps Institutional Market Services, Dow Jones & Company, Inc.
is composed of companies that are classified as domestic oil companies under Standard Industrial
Classification codes (1300-1399, 2900-2949, 5170-5179 and 5980-5989). The Dow Jones US Exploration
& Production Index is accessible at
http://www.djindexes.com/mdsidx/index.cfm?event=showTotalMarket.
Item 6. Selected Financial Data
SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth our selected consolidated financial data for each of the years
in the five-year period ended December 31, 2009. In December 2007, we changed our accounting
method for oil and gas exploration and development activities to the successful efforts method from
the full cost method. The selected consolidated financial data have been derived from and should
be read in conjunction with our annual audited consolidated financial statements, including the
notes thereto.
|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007(1) |
|
|
2006(1) |
|
|
2005 |
|
|
|
(in thousands, except per share data) |
|
Statement of Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
181 |
|
|
$ |
|
|
|
$ |
11,217 |
|
|
$ |
59,506 |
|
|
$ |
236,941 |
|
Operating income (loss) |
|
|
(30,959 |
) |
|
|
(54,440 |
) |
|
|
(19,536 |
) |
|
|
574 |
|
|
|
104,571 |
|
Net income from Unconsolidated
Equity Affiliates |
|
|
35,757 |
|
|
|
34,576 |
|
|
|
55,297 |
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Harvest |
|
|
(3,107 |
) |
|
|
(21,464 |
) |
|
|
60,118 |
|
|
|
(62,502 |
) |
|
|
38,876 |
|
Net income (loss) attributable to Harvest per
common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.09 |
) |
|
$ |
(0.63 |
) |
|
$ |
1.65 |
|
|
$ |
(1.68 |
) |
|
$ |
1.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(0.09 |
) |
|
$ |
(0.63 |
) |
|
$ |
1.59 |
|
|
$ |
(1.68 |
) |
|
$ |
1.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
33,084 |
|
|
|
34,073 |
|
|
|
36,550 |
|
|
|
37,225 |
|
|
|
36,949 |
|
Diluted |
|
|
33,084 |
|
|
|
34,073 |
|
|
|
37,950 |
|
|
|
37,225 |
|
|
|
38,444 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007(1) |
|
|
2006(1) |
|
|
2005 |
|
|
|
(in thousands) |
|
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
348,779 |
|
|
$ |
362,266 |
|
|
$ |
417,071 |
|
|
$ |
468,365 |
|
|
$ |
451,377 |
|
Long-term debt, net of current maturities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
66,977 |
|
|
|
|
|
Total Harvests Stockholders equity (2) |
|
|
274,593 |
|
|
|
273,242 |
|
|
|
316,647 |
|
|
|
281,409 |
|
|
|
337,975 |
|
|
|
|
(1) |
|
Activities under our former OSA in Venezuela are reflected under the equity method
of accounting effective April 1, 2006. The results of Petrodeltas operations from April 1,
2006 until December 31, 2007 are reflected in 2007 when Petrodelta was formed. |
|
(2) |
|
No cash dividends were declared or paid during the periods presented. |
25
Item 7. Managements Discussion and Analysis of Financial Condition and Results of
Operations
Operations
We had a net loss attributable to Harvest of $3.1 million, or $(0.09) per diluted share, for
the twelve months ended December 31, 2009 compared with a net loss attributable to Harvest of $21.5
million, or $(0.63) per diluted share, for the twelve months ended December 31, 2008. Net loss
attributable to Harvest for the year ended December 31, 2009 includes $7.8 million of exploration
expense and the net equity income from Petrodeltas operations of $40.7 million. Net loss
attributable to Harvest for the year ended December 31, 2008 includes $16.4 million of exploration
expense, $10.8 million of dry hole expense and the net equity income from Petrodeltas operations
of $35.9 million.
Petrodelta Venezuela
During 2009, Petrodelta drilled and completed 14 successful development wells, suspended one
well due to problems with the well and drilled two appraisal wells, produced approximately 7.8
million barrels of oil and sold 4.4 billion cubic feet (BCF) of natural gas. Petrodelta was
advised by the Venezuelan government that the 2009 production target was approximately 16,000
barrels of oil per day following the December 17, 2008 OPEC meeting establishing new production
quotas. However, Petrodelta was allowed to produce at capacity to help fulfill other companies
production shortfalls, thus averaging 21,464 barrels of oil per day during 2009.
Petrodelta began the appraisal and testing of its large portfolio of undeveloped resources in
the second quarter of 2009. During the second quarter 2009, Petrodelta drilled two successful
appraisal wells in the El Salto field, and pilot production commenced from one of the appraisal
wells through temporary facilities. The well commenced production on July 18, 2009 and has
produced 349,000 barrels of oil through the end of 2009. The second appraisal well will be tested
after the permitting process with MENPET is completed.
Petrodelta shareholders intend that the company be self-funding and rely on
internally-generated cash flow to fund operations. Currently, Petrodelta has one drilling rig
operating in the Uracoa field. On February 4, 2010, Petrodeltas board of directors endorsed a
capital budget of $205 million for Petrodeltas 2010 business plan. For 2010, the planned drilling
program includes utilizing two rigs to drill both development and appraisal wells for both
maintaining production capacity and appraising the substantial resource bases in the El Salto field
and presently non-producing Isleño field.
On April 23, 2009, Petrodeltas board of directors declared a dividend of $51.9 million, $20.8
million net to HNR Finance ($16.6 million net to our 32 percent interest). HNR Finance received
the cash related to this dividend in the form of an advance dividend in October 2008. We expect to
receive future dividends from Petrodelta; however, we expect the amount of any future dividends to
be lower in the near term as Petrodelta reinvests most of its earnings into the company in support
of its drilling and appraisal activities. Petrodeltas results and operating information is more
fully described in Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 7
Investment in Equity Affiliates Petrodelta, S.A.
Diversification
Beginning in 2005, we recognized the need to diversify our asset base as part of our strategy.
We broadened our strategy from our primary focus on Venezuela to identify, access and integrate
hydrocarbon assets to include organic growth through exploration in basins globally with proven
hydrocarbon systems. We seek to leverage our Venezuelan experience as well as our recently
expanded business development and technical platform to create a diversified resource base. With
the addition of technical resources, opening of our London and Singapore offices, as well as our
minority equity investment in Fusion, we have made significant investments to provide the necessary
foundation and global reach required for an organic growth focus. Our organic growth is focused on
undeveloped or underdeveloped fields, field redevelopments and exploration. While exploration will
become a larger part of our overall portfolio, we will generally restrict ourselves to basins with
known hydrocarbon systems and favorable risk-reward profiles. Exploration will be technically
driven with a low entry cost and high
26
resource potential that provides sustainable growth. We will
continue to seek opportunities where perceived geopolitical risk
may provide high reward opportunities in the long term. In 2009, we acquired an exploration
asset in Oman that fit our strategy and began production at Monument Butte described below.
United States
On January 28, 2010, we entered into an agreement with one of the private third parties in our
AMI for an option to participate in a new project. We paid $1.5 million for the option to acquire
up to a 50 percent interest in the new project. If we exercise our option to participate, we will
participate in this project with essentially the same terms as the other existing projects in the
AMI. The option to participate expires on June 1, 2010.
Gulf Coast West Bay
During the year ended December 31, 2009, operational activities in the West Bay prospect
included the interpretation of 3-D seismic, site surveying, and preparation of engineering
documents. Interpretation of 3-D seismic data on the West Bay project was completed in the second
quarter 2009 and resulted in the identification of a revised set of drilling leads and prospects
for the project.
The AMI participants are currently evaluating the leads and prospects to determine priorities
and drilling plans for the West Bay project. Depending on the selected drilling prospects and
locations, the drilling may or may not require permit(s) from the U.S. Army Corps of Engineers
Galveston District (Corps of Engineers). We expect to firm up plans for initial drilling on the
West Bay project during 2010, with the expectation of initial drilling on the West Bay project in
2011. During the year ended December 31, 2009, we incurred $0.4 million for lease acquisition,
surveying, permitting and site preparation and $1.5 million for seismic data interpretation. The
2010 budget for the West Bay project is $0.1 million.
Western United States Antelope
Activities are in progress on two separate projects on the Antelope prospect in Duchesne
County, Utah.
Mesaverde
The Mesaverde project is targeted to explore for and develop oil and natural gas from multiple
reservoir horizons in the Uintah Basin of northeastern Utah in Duchesne and Uintah Counties. Leads
and prospects have been identified in three prospective reservoir horizons and initial drilling
activities commenced in 2009 on one prospect.
Operational activities during 2009 on the Mesaverde project focused on continuing leasing
activities on private, Allottee, and tribal land, and surveying, preliminary engineering,
permitting preparations, and conducting drilling operations on a deep natural gas test well (the
Bar F) that commenced drilling on June 15, 2009. The Bar F was permitted to 18,000 feet. The Bar
F was drilled to a total depth of 17,566 feet and an extended production test is now in progress.
To date, testing has been 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. Completion activities
consisted of hydraulic fracturing of eight separate reservoir intervals in the Mesaverde and
multiple extended flow tests of the individual fractured intervals, along with a flow test of the
commingled eight intervals. While the results to date have not definitively determined the
commerciality of a stand-alone development of the Mesaverde, we believe these results indicate
progress toward that determination and that the Mesaverde reservoir remains potentially prospective
over a portion of our land position. During the year ended December 31, 2009, we incurred $23.4
million for drilling, lease acquisition, surveying, permitting and site preparation and $0.3
million for seismic data program planning. The 2010 budget for the Mesaverde project is $5.7
million; however, contingent on successful results of the Bar F and availability of funds, we plan
to increase this budget to $33.0 million.
Monument Butte
The Monument Butte project is an eight well appraisal and development drilling program to
produce oil and natural gas from the Green River formation on the southern portion of our Antelope
land position. The
27
Monument Butte project is non-operated and we hold a 43 percent working
interest. The parties have formed a 320 acre AMI which contained the eight drilling locations.
Operational activities during 2009 on the Monument Butte project focused on resolution of
forced pooling issues with a non-consenting interest, negotiations and finalization of an agreement
with the operator for the joint drilling operations. As of March 1, 2010, all eight wells have
been drilled. Seven wells are currently on production. One additional well is waiting on
completion operations and is anticipated to commence production in early March 2010. During the
year ended December 31, 2009, we incurred $1.8 million for drilling (including drilling accruals),
lease acquisition, surveying, permitting and site preparation. The 2010 budget for the Monument
Butte project is $1.1 million which has already been spent in the first quarter of 2010. We are
currently evaluating the potential expansion of this drilling program. Contingent on the
successful results of this evaluation, negotiation with the operator and availability of funds,
this budget could be increased to $4.6 million.
Budong-Budong Project, Indonesia
Operational activities during 2009 focused on the interpretation of 650 kilometers of 2-D
seismic and well planning. Two drill sites have been selected. Currently, the locations for the
two test wells are being constructed and the rig and ancillary equipment is being mobilized to the
area. It is expected that the first of two exploration wells will spud early in the second quarter
of 2010. In accordance with the farm-in agreement, we expect to fund 100 percent of the well
expenditures to earn our 47 percent working interest up to a cap of $10.7 million; thereafter, we
will pay in proportion to our working interest. During the year ended December 31, 2009, we
incurred $0.3 million for surveying, permitting, engineering and well planning and $1.8 million for
seismic data processing and interpretation. The 2010 budget for the Budong PSC is $14.9 million.
Contingent on the successful results of the two exploratory test wells and availability of funds,
this budget could be increased to $28.0 million.
Dussafu Project Gabon
Operational activities during 2009 focused on completion of the processing and reprocessing of
1,330 kilometers of 2-D seismic and the pre-stack depth reprocessing of 1,076 square kilometers of
3-D seismic data. The improved imaging from this work has allowed the interpretation to mature the
prospect inventory to provide the partnership a number of prospective targets in the sub-salt
section, in both the Gamba and Syn-rift plays that are productive in the nearby Etame, Lucina and
MBya fields. Subject to drilling rig availability, we expect to drill an exploration well in the
third quarter of 2010. During the year ended December 31, 2009, we incurred $1.2 million for
seismic data processing and reprocessing. The 2010 budget for the Dussafu PSC is $2.2 million.
Contingent on rig availability and successful results from the exploration well and availability of
funds, this budget could be increased to $20.1 million.
Block 64 EPSA Project Oman
On April 11, 2009, we signed an EPSA with Oman for the Block 64 EPSA. Current activities
include the compilation of existing data over two prospect areas of approximately 1,000 square
kilometers and geological studies to determine drillable prospects. Well planning is expected to
commence in 2010 for exploration drilling in 2011. We incurred $2.3 million for costs associated
with signing the license, including signature bonus and data compilation and $0.5 million for
seismic data processing and reprocessing. The 2010 budget for the Block 64 EPSA is $2.8 million.
Contingent on the availability of funds, an additional $1.9 million are planned for this project.
WAB-21 Project China
The WAB-21 petroleum contract lies within an area which is the subject of a border dispute
between China and Vietnam. The border dispute has lasted for many years, and there has been
limited exploration and no development activity in the WAB-21 area due to the dispute. However,
Vietnam, along with the company that is the party to the agreement with Vietnam, recently announced
plans for exploration drilling during 2010. While no assurance can be given, we believe this
announcement may provide some resolution with the border disputes, although we do not know in what
manner any resolution might appear.
28
Other Exploration Projects
Relating to other projects, we incurred $1.3 million during the year ended December 31, 2009.
The 2010 budget for other projects is $0.3 million. Contingent upon successful test results in
Utah and Indonesia and availability of funds, we may increase this budget to $20.4 million.
Either one of the two exploratory wells to be drilled in 2010 on the Budong PSC or the
completion of the well on the Mesaverde project can have a significant impact on our ability to
obtain financing, record reserves and generate cash flow in 2010 and beyond.
In Item 1 Business and Item 1A Risk Factors, we discuss the situation in Venezuela and how
the actions of the Venezuelan government have and continue to adversely affect our operations. Low
crude oil prices and the expectation that dividends from Petrodelta will be minimal over the next
two years has restricted our available cash and had a significant adverse effect on our ability to
obtain financing to acquire and develop growth opportunities elsewhere.
We will use our available cash and future access to capital markets to expand our diversified
strategy in a number of countries that fit our strategic investment criteria. In executing our
business strategy, we will strive to:
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maintain financial prudence and rigorous investment criteria; |
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access capital markets; |
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continue to create a diversified portfolio of assets; |
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preserve our financial flexibility; |
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use our experience and skills to acquire new projects; and |
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keep our organizational capabilities in line with our rate of growth. |
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To accomplish our strategy, we intend to: |
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Diversify our Political Risk: Acquire oil and natural gas fields in a number of
countries to diversify and reduce the overall political risk of our investment portfolio. |
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Seek Operational and Financial Control: We desire control of major decisions for
development, production, staffing and financing for each project for a period of time
sufficient for us to ensure maximum returns on investments. |
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Establish a Presence Through Joint Venture Partners and the Use of Local Personnel: We
seek to establish a presence in the countries and areas we operate through joint venture
partners to facilitate stronger governmental and business relationships. In addition, we
use local personnel to help us take advantage of local knowledge and experience and to
minimize costs. |
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Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time: We are
willing to agree to minimum capital expenditures or development commitments at the outset
of new projects, but we endeavor to structure such commitments to fulfill them over time
under a prudent plan of development, allowing near-term operating cash flow to help fund
further investment, thereby limiting our maximum cash exposure. We also seek to maximize
available local financing capacity to develop the hydrocarbons and associated
infrastructure. |
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Provide Technical Expertise: We believe there is an advantage in being able to provide
geological, geophysical and engineering expertise beyond what many companies or countries
possess internally. In addition to our in-house technical capabilities, we acquired a
minority equity investment in Fusion, a technical firm with significant experience in
providing leading edge geophysical, geosciences and reservoir engineering services in many
places in the world. Through this acquisition we have strategic access to these services. |
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Maintain a Prudent Financing Plan: We intend to maintain our financial flexibility by
closely monitoring spending, holding sufficient cash reserves, minimizing the use of
restricted cash, actively seeking |
29
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opportunities to reduce our weighted average cost of
capital and increase our access to debt and equity markets. |
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Manage Exploration Risks. We seek to manage the higher risk of exploration by
diversifying our prospect portfolio, applying state-of-the-art technology for analyzing
targets and focusing on opportunities in proven active hydrocarbon systems with
infrastructure. |
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Establish Various Sources of Production. We seek to establish new production from our
exploration and development efforts in a number of diverse markets and expect to monetize
production through operations or the sale of assets. |
Results of Operations
The following discussion should be read with the results of operations for each of the years
in the three-year period ended December 31, 2009 and the financial condition as of December 31,
2009 and 2008 in conjunction with our consolidated financial statements and related notes thereto.
Years Ended December 31, 2009 and 2008
We reported a net loss attributable to Harvest of $3.1 million, or $(0.09) diluted earnings
per share, for the year ended December 31, 2009, compared with a net loss attributable to Harvest
of $21.5 million, or $(0.63) diluted earnings per share, for the year ended December 31, 2008.
Revenues were higher for the year ended December 31, 2009 compared with the year ended
December 31, 2008 due to the Monument Butte wells coming on production in December 2009.
Total expenses and other non-operating (income) expense (in millions):
|
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|
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|
|
|
|
|
|
|
Year Ended |
|
|
|
|
|
|
December 31, |
|
|
Increase |
|
|
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
Depletion, depreciation and amortization |
|
$ |
0.4 |
|
|
$ |
0.2 |
|
|
$ |
0.2 |
|
Exploration expense |
|
|
7.8 |
|
|
|
16.4 |
|
|
|
(8.6 |
) |
Dry hole costs |
|
|
|
|
|
|
10.8 |
|
|
|
(10.8 |
) |
General and administrative |
|
|
21.9 |
|
|
|
27.2 |
|
|
|
(5.3 |
) |
Taxes other than on income |
|
|
1.0 |
|
|
|
(0.2 |
) |
|
|
1.2 |
|
Gain on financing transactions |
|
|
|
|
|
|
(3.4 |
) |
|
|
3.4 |
|
Investment earnings and other |
|
|
(1.1 |
) |
|
|
(3.7 |
) |
|
|
2.6 |
|
Interest expense |
|
|
|
|
|
|
1.7 |
|
|
|
(1.7 |
) |
Income tax expense |
|
|
1.2 |
|
|
|
|
|
|
|
1.2 |
|
Depletion and amortization expense per Boe produced during 2009 was $6.59.
Our accounting method for oil and gas properties is the successful efforts method. During the
year ended December 31, 2009, we incurred $4.3 million of exploration costs related to the
processing and reprocessing of seismic data related to ongoing operations, $2.8 million related to
other general business development activities and $0.7 million related to the write off of the
remaining carrying value of the Starks prospect. During the year ended December 31, 2008, we
incurred $16.4 million of exploration costs related to the purchase and re-processing of seismic
data related to our U.S. operations, acquisition of seismic data related to our Indonesia
operations, and other general business development activities. Also during the year ended December
31, 2008, we incurred $10.8 million of dry hole costs related to the Harvest Hunter #1 well, which
in January 2009 was determined to have no commercial quantities of hydrocarbons and was plugged and
abandoned.
General and administrative costs were lower in the year ended December 31, 2009, than in the
year ended December 31, 2008, primarily due to employee related expenses, lower general operations
and office costs, and the reversal of accruals no longer required, including penalties and interest
of $0.9 million on the resolved SENIAT
30
assessments. Taxes other than on income for the year ended
December 31, 2009, were higher than the year ended December 31, 2008 due to the reversal in 2008 of
a $1.1 million franchise tax provision that was no longer required.
We did not participate in any security exchange transactions in the year ended December 31,
2009. During the year ended December 31, 2008, we entered into a securities exchange transaction
exchanging U.S. government securities for U.S. Dollar indexed debt issued by the Venezuelan
government. This security exchange transaction resulted in a $3.4 million gain on financing
transactions for the year ended December 31, 2008.
Investment earnings and other decreased in the year ended December 31, 2009 compared to the
year ended December 31, 2008 due to lower interest rates earned on lower average cash balances.
Interest expense was lower for the year ended December 31, 2009 compared to the year ended
December 31, 2008 due to the repayment of debt in 2008.
For the year ended December 31, 2009, income tax expense was higher than that of the year
ended December 31, 2008 primarily due to additional income tax assessed in the Netherlands of $0.7
million as a result of financing activities, which was recorded in the first quarter of 2009, and
additional current income tax in the Netherlands of $0.5 million due to interest income earned from
loans to affiliates and on cash balances. No income tax benefit is recorded for the net operating
losses incurred as a full valuation allowance has been placed on the related deferred tax asset as
management believes that is more likely than not that additional net losses will not be realized
through future taxable income. There was no utilization of net operating loss carryforwards in the
year ended December 31, 2009.
Net income from unconsolidated equity affiliates includes two non-recurring adjustments:
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During the second quarter of 2009, Petrodelta recorded additional pension expense of $15.6
million ($5.0 million net to our 32 percent interest) in the three month period ended June 30,
2009 based on an actuarial study commissioned by PDVSA which was finalized during the
second quarter of 2009. During the fourth quarter of 2009, Petrodelta received a revised
allocation of its pension obligation from PDVSA which reflected an update to the actuarial study
based on a further refinement of assumption and a revised allocation methodology as a result of
an analysis of more detailed census data specific to each mixed company not previously
available. This revised allocation resulted in a decrease of $8.4 million ($2.7 million net to our
32 percent interest) to the pension and retirement plan costs as compared to those previously
recorded to Petrodelta in May 2009. This change in managements estimate related to the
pension and retirement plan costs was recorded in December 2009.
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Based on cash flow projections and considering Fusions current liquidity, we performed
a review at December 31, 2009 for impairment of our minority equity investment in Fusion.
Based on this review, we concluded that Fusions potential business opportunities did not
support its on-going cash flow requirements; and therefore, we recorded a $1.6 million
charge to fully impair the carrying value of our equity investment in Fusion at
December 31, 2009. |
See Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 7 Investment in Equity
Affiliates for additional information.
Years Ended December 31, 2008 and 2007
We reported a net loss attributable to Harvest of $21.5 million, or $(0.63) diluted earnings
per share, for the year ended December 31, 2008 compared to net income attributable to Harvest of
$60.1 million, or $1.59 diluted earnings per share, for the year end December 31, 2007.
We included the results of operations of Harvest Vinccler in our consolidated financial
statements and reflected the 20 percent ownership interest of OGTC as a noncontrolling interest in
2005 and the first quarter of 2006. Since April 1, 2006, our minority equity investment in
Petrodelta has been reflected under the equity method of accounting. We recorded the cumulative
effect from April 1, 2006 to December 31, 2007 in the three months ended December 31, 2007. The
year ended December 31, 2008 includes net income from unconsolidated equity affiliates for
Petrodelta on a current basis. See Part IV, Item 15, Notes to the Consolidated Financial
Statements, Note 7 Investment in Equity Affiliates Petrodelta, S.A. for Petrodeltas results of
operations which reflect the results for the years ended December 31, 2009, 2008 and 2007,
comparatively.
31
Revenue recorded for the year ended December 31, 2007 reflects the reversal of deferred
revenue recorded by Harvest Vinccler for 2005 and first quarter of 2006 deliveries pending
clarification on the calculation of crude prices under the Transitory Agreement. See Part IV, Item
15, Notes to the Consolidated Financial Statements, Note 1 Organization and Summary of
Significant Account Policies Revenue Recognition. There were no sales of oil and natural gas in
2008 or 2007 due to the conversion of the OSA to a minority equity investment in Petrodelta.
Total expenses and other non-operating (income) expense (in millions):
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|
|
|
|
|
|
|
|
|
Year Ended |
|
|
|
|
|
|
December 31, |
|
|
Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
Depreciation |
|
$ |
0.2 |
|
|
$ |
0.4 |
|
|
$ |
(0.2 |
) |
Exploration expense |
|
|
16.4 |
|
|
|
0.9 |
|
|
|
15.5 |
|
Dry hole costs |
|
|
10.8 |
|
|
|
|
|
|
|
10.8 |
|
General and administrative |
|
|
27.2 |
|
|
|
29.1 |
|
|
|
(1.9 |
) |
Taxes other than on income |
|
|
(0.2 |
) |
|
|
0.4 |
|
|
|
(0.6 |
) |
Gain on financing transactions |
|
|
(3.4 |
) |
|
|
(49.6 |
) |
|
|
46.2 |
|
Investment earnings and other |
|
|
(3.7 |
) |
|
|
(9.1 |
) |
|
|
5.4 |
|
Interest expense |
|
|
1.7 |
|
|
|
8.2 |
|
|
|
(6.5 |
) |
Income tax expense |
|
|
|
|
|
|
6.3 |
|
|
|
(6.3 |
) |
In December 2007, we changed our accounting method for oil and gas exploration and development
activities to the successful efforts method from the full cost method. During the year ended
December 31, 2008, we incurred $16.4 million of exploration costs related to the purchase and
re-processing of seismic data related to our U.S. operations, acquisition of seismic data related
to our Indonesia operations, and other general business development activities. Also during the
year ended December 31, 2008, we incurred $10.8 million of dry hole costs related to the Harvest
Hunter #1 well, which in January 2009 was determined to have no commercial quantities of
hydrocarbons and was plugged and abandoned. During the year ended December 31, 2007, we incurred
$0.9 million of exploration costs related to other foreign general business development.
General and administrative costs were lower in the year ended December 31, 2008, than in the
year ended December 31, 2007, primarily due to employee related expenses and lower contract
services. Taxes other than on income for the year ended December 31, 2008, were lower than the
year ended December 31, 2007 due to the reversal of a $1.1 million franchise tax provision that was
no longer required.
During the years ended December 31, 2008 and 2007, we entered into securities exchange
transactions exchanging U.S. government securities for U.S. Dollar indexed debt issued by the
Venezuelan government. These security exchange transactions resulted in a $3.4 million and $49.6
million gain on financing transactions for the years ended December 31, 2008 and 2007,
respectively.
Investment earnings and other decreased in the year ended December 31, 2008, as compared to
the same period of the prior year due to lower interest rates earned on lower cash balances.
Interest expense decreased due to the payment of Harvest Vincclers Bolivar denominated debt in
July of 2008.
For the year ended December 31, 2008, income tax expense, which is comprised of income tax on
our foreign activities and withholding tax on interest income from Harvest Vinccler, was lower than
that of the year ended December 31, 2007, partially due to the $49.6 million gain on financing
transactions occurring in the year ended December 31, 2007 compared to a $3.4 million gain on
financing transactions occurring in the year ended December 31, 2008. The reduction in income tax
expense was also partially due to the reduction in the rate of withholding tax on the Venezuela
interest, which went from 10 percent to 5 percent under the Netherlands-Venezuela double tax
treaty. No income tax benefit is recorded for the net operating losses incurred as a full
valuation allowance has been placed on the related deferred tax asset as management believes that
is more likely than not that additional net losses will not be realized through future taxable
income. There was no utilization of net operating loss carryforwards in the year ended December
31, 2008.
32
Capital Resources and Liquidity
The oil and natural gas industry is a highly capital intensive and cyclical business with
unique operating and financial risks (see Item 1A Risk Factors). We require capital principally
to fund the exploration and development of new oil and gas properties. For calendar year 2010, we
have preliminarily established an exploration and drilling budget of approximately $27.1 million.
We are concentrating a substantial portion of this budget on the development of our Antelope
prospect and Budong PSC. Contingent upon the successful test results of the exploratory well
drilled on the Antelope prospect, the exploratory wells to be drilled on the Budong PSC and
availability of funds, we have planned capital expenditures of up to $110.8 million to evaluate and
develop our
prospect portfolio in the United States and international locations, excluding Venezuelas self
funding program. We currently believe that Petrodelta will fund its own operations and continue to
pay dividends although no dividends are expected in 2010 based on our current forecast. In Item 1A
Risk Factors, we discuss a number of variables and risks related to our minority equity
investment in Petrodelta and exploration projects 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.
Based on our cash balance of $32 million at December 31, 2009, we will be required to raise
additional funds in order to fund our future operating and capital expenditures. As we disclosed
in previous filings, our cash is being used to fund oil and gas exploration projects and to a
lesser extent general and administrative costs. Through December 31, 2009, our exploration
expenditures outside of Venezuela have resulted in a modest amount of new proved reserves in Utah
in the United States. If we are not able to raise additional capital or prove up additional
sources of revenue, there will be a need to reduce our projected expenditures which could limit our
ability to operate our business. Currently, our primary source of cash is dividends from
Petrodelta. However, there is no certainty that Petrodelta will pay dividends in 2010 or 2011.
Our lack of cash flow and the unpredictability of cash dividends from Petrodelta could make it
difficult to obtain financing, and accordingly, there is no assurance adequate financing can be
raised. We continue to pursue, as appropriate, additional actions designed to generate liquidity
including seeking of financing sources, accessing equity and debt markets, exploration of our
properties worldwide, and cost reductions. In addition, we could delay discretionary capital
spending to future periods or sell assets as necessary to maintain the liquidity required to run
our operations, if necessary. There can be no assurances that any of these possible efforts will
be successful or adequate, and if they are not, our financial condition and liquidity could be
materially adversely affected.
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, we will pay interest
semi-annually and the 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 convertible notes, equivalent to a
conversion price of approximately $5.71 per share of common stock, subject to adjustment. The
notes are our general unsecured obligations, ranking equally with all of our other unsecured senior
indebtedness, if any, and senior in right of payment to any of our subordinated indebtedness, if
any. The 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. The net proceeds
of the offering to us were approximately $30.0 million, after deducting underwriting discounts,
commissions and estimated offering expenses. We intend to use these net proceeds to fund capital
expenditures and for working capital needs and general corporate purposes.
In addition, we are currently contemplating one particular additional source of financing
through an Islamic (sukuk) financing, in which one of our subsidiaries would form and contribute
certain assets to a partnership and subsequently sell a minority interest in the partnership to one
or more third parties for approximately $250 million. Although the terms of this transaction have
not been finalized, we anticipate that the terms would include our agreement to pay all or a
substantial portion of the dividends paid by Petrodelta to which we are entitled over the next five
or six years to reacquire all of the third-party partnership interests, including premiums thereon.
While we may be able to consummate this financing transaction during the first half of 2010, there
can be no assurances that this transaction will be consummated, and we may consider alternative
forms of additional financing if we deem necessary or advisable with respect to our operations from
time to time.
On February 5, 2003, Venezuela imposed currency controls and created CADIVI with the task of
establishing the detailed rules and regulations and generally administering the exchange control
regime. These
33
controls fix the exchange rate between the Bolivar and the U.S. Dollar and restrict the
ability to exchange Bolivars for U.S. Dollars and vice versa. The U.S. Dollar and Bolivar exchange
rates had not been adjusted since March 2005 until January 8, 2010 when the Venezuelan government
adjusted the exchange rate from 2.15 Bolivars per U.S. Dollar to 2.60 Bolivars per U. S. Dollar for
the food, health, medical and technology sectors; and 4.30 Bolivars per U. S. Dollar for all other
sectors not expressly established by the 2.60 Bolivar exchange rate.
The U.S. Dollar is the functional reporting currency for both Petrodelta and Harvest
Vinccler. The Bolivar is not readily convertible into the U.S. Dollar. The Venezuelan currency
conversion restriction has not adversely affected our ability to meet short-term loan obligations
and operating requirements for the foreseeable future.
Working Capital. Our capital resources and liquidity are affected by the ability of
Petrodelta to pay dividends. On April 23, 2009, Petrodeltas board of directors declared a
dividend of $51.9 million, $20.8 million net to HNR Finance ($16.6 million net to our 32 percent
interest). HNR Finance received the cash related to this dividend in the form of an advance
dividend in October 2008. We expect to receive future dividends from Petrodelta; however, we
expect the amount of any future dividends to be lower in the near term as Petrodelta reinvests most
of its earnings into the company in support of its drilling and appraisal activities. In June
2009, CVP issued instructions to all mixed companies regarding the accounting for deferred tax
assets. The mixed companies have been instructed to set up a reserve within the equity section of
the balance sheet for deferred tax assets. The setting up of the reserve had no effect on
Petrodeltas financial position, results of operation or cash flows. However, the new reserve
could have a negative impact on the amount of dividends received in the future. In addition to
reinvesting earnings into the company in support of its drilling and appraisal activities, the
decline in the price per barrel affects Petrodeltas ability to pay dividends. All available cash
will be used to meet current operating requirements and will not be available for dividends. See
Item 1 Business, Petrodelta and Item 1A Risk Factors for a more complete description of the
situation in Venezuela and other matters.
The net funds raised and/or used in each of the operating, investing and financing activities
are summarized in the following table and discussed in further detail below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
(in thousands except as indicated) |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Net cash provided by (used in) operating activities |
|
$ |
(34,945 |
) |
|
$ |
50,380 |
|
|
$ |
(20,655 |
) |
Net cash provided by (used in) investing activities |
|
|
(28,603 |
) |
|
|
(23,055 |
) |
|
|
69,960 |
|
Net cash used in financing activities |
|
|
(1,300 |
) |
|
|
(51,001 |
) |
|
|
(76,543 |
) |
|
|
|
|
|
|
|
|
|
|
Net decrease in cash |
|
$ |
(64,848 |
) |
|
$ |
(23,676 |
) |
|
$ |
(27,238 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working Capital |
|
|
34,206 |
|
|
|
77,010 |
|
|
|
111,534 |
|
Current Ratio |
|
|
3.0 |
|
|
|
3.0 |
|
|
|
3.6 |
|
Total Cash, including restricted cash |
|
|
32,317 |
|
|
|
97,165 |
|
|
|
127,610 |
|
Total Debt |
|
|
|
|
|
|
|
|
|
|
9,302 |
|
The decrease in working capital of $42.8 million was for capital expenditures and
administrative expenses.
Cash Flow from Operating Activities. During the year ended December 31, 2009, net cash used
in operating activities was approximately $34.9 million. During the year ended December 31, 2008,
net cash provided by operating activities was approximately $50.4 million. The $85.3 million
decrease was primarily due to the receipts in 2008 of a $72.5 million dividend net to HNR Finance
($58.0 million net to our 32 percent interest) and advance dividend of $20.8 million net to HNR
Finance ($16.6 million net to our 32 percent interest) from our unconsolidated equity affiliate and
payment of advances by PDVSA offset by payment of the accounts payable related party, repurchase of
treasury stock, payment of a dividend to the noncontrolling interest in Harvest-Vinccler Dutch
Holding, B.V., and capital expenditures.
Cash Flow from Investing Activities. During the year ended December 31, 2009, we had cash
capital expenditures of approximately $28.0 million. Of the 2009 expenditures, $0.4 million was
attributable to the West Bay project, $23.7 million was attributable to the Antelope prospect, $0.3
million was attributable to exploration
34
activity on the Budong PSC, $2.3 million was attributable to the Block 64 EPSA project and
$1.3 million on other projects. During the year ended December 31, 2008, we had cash capital
expenditures of approximately $26.3 million. Of the 2008 expenditures, $4.7 million was
attributable to the Gulf Coast prospects, $10.8 million was attributable to the Harvest Hunter #1
exploration well, $4.2 million was attributable to the Antelope prospect, $0.1 million was
attributable to the Budong PSC, $5.3 million was attributable to the Dussafu PSC, and $1.2 million
on other projects. During the year ended December 31, 2008, we increased our minority equity
investment in Fusion by purchasing an additional two percent interest for $2.2 million. During the
year ended December 31, 2008, $6.8 million of restricted cash used as collateral for loans which
were repaid was returned to us. During the year ended December 31, 2009 and 2008, we incurred $0.6
million and $1.3 million, respectively, of investigatory costs related to various international and
domestic exploration studies.
With the conversion to Petrodelta, 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 of $27.1 million for 2010 for U.S., Indonesia, Gabon
and Oman operations will be funded through our existing cash balances, the February 2010 debt
offering, other financing sources, accessing equity and debt markets, and cost reductions. In
addition, we could delay discretionary capital spending to future periods or sell assets as
necessary to maintain the liquidity required to run our operations, as warranted.
Cash Flow from Financing Activities. During the year ended December 31, 2009 we incurred $1.7
million in legal fees associated with prospective financing. During year ended December 31, 2008,
Harvest Vinccler repaid 20 million Bolivars (approximately $9.3 million) of its Bolivar denominated
debt, we redeemed the 20 percent minority interest in our Barbados affiliate, incurred $1.1 million
in legal fees associated with prospective financing, and we paid a dividend of $14.9 million to the
noncontrolling interest in Harvest-Vinccler Dutch Holding, B.V.
In July 2008, our Board of Directors authorized the purchase of up to $20 million of our
common stock from time to time through open market transactions. As of December 31, 2008, 1.2
million shares of stock had been purchased at an average cost of $10.17 per share for a total cost
of $12.2 million of the $20 million authorization. During the year ended December 31, 2009, no
stock was purchased under the program.
Contractual Obligations
We have a lease obligation of approximately $32,000 per month for our Houston office space.
This lease runs through July 2014. In addition, Harvest Vinccler has lease obligations for office
space in Caracas, Venezuela for approximately $10,000 per month. This lease runs through November
2010. We also have lease commitments for an office in Utah for approximately $6,000 per month, an
office in Singapore for approximately $19,000 per month, an office space in Indonesia for
approximately $5,000 per month, an office in Oman for approximately $5,000 per month and an office in London for approximately $24,000 per month. These
leases expire in September 2010, October 2010, March 2011, August 2011 and November 2010, respectively. Our
London office space is leased on a month-to-month basis with no long term commitment. We do not
have any long-term contractual commitments for any of our projects.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments (in thousands) Due by Period |
|
|
|
|
|
|
|
Less than |
|
|
|
|
|
|
|
|
|
|
After 4 |
|
Contractual Obligation |
|
Total |
|
|
1 Year |
|
|
1-2 Years |
|
|
3-4 Years |
|
|
Years |
|
Office Leases |
|
$ |
2,674 |
|
|
$ |
1,215 |
|
|
$ |
459 |
|
|
$ |
407 |
|
|
$ |
593 |
|
Asset Retirement Obligation |
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Obligations |
|
$ |
2,724 |
|
|
$ |
1,215 |
|
|
$ |
459 |
|
|
$ |
407 |
|
|
$ |
643 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official
exchange rate in February 2004, March 2005 and again in January 2010. The currency conversion
restrictions or the adjustment in the exchange rate have not had a material impact on us at this
time. Dividends from Petrodelta will be denominated in U.S. Dollars when paid. 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.
35
During the years ended December 31, 2009 and 2008, our net foreign exchange gains attributable
to our international operations were minimal. The U.S. Dollar and Bolivar exchange rates have 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. We have recognized significant exchange gains and losses in the past, resulting from
fluctuations in the relationship of the Venezuelan currency to the U.S. Dollar. 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.
An exemption under the Venezuelan Criminal Exchange Law for transactions in certain securities
results in an indirect securities transaction market of foreign currency exchange, through which
companies may obtain foreign currency legally without requesting it from the Venezuelan government.
Publicly available quotes do not exist for the securities transaction exchange rate but such rates
may be obtained from brokers. Securities transaction markets are used to move financial securities
in and out of Venezuela.
Critical Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of all wholly-owned and
majority-owned subsidiaries. The equity method of accounting is used for companies and other
investments in which we have significant influence. All intercompany profits, transactions and
balances have been eliminated.
Reporting and Functional Currency
The U.S. Dollar is our reporting and functional currency. Amounts denominated in non-U.S.
Dollar currencies are re-measured in 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.
The U.S. Dollar is the reporting and functional currency for all of our controlled
subsidiaries and Petrodelta.
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.
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 investment 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.
Property and Equipment
We follow the successful efforts method of accounting for our oil and gas properties. Under
this method, oil and natural gas lease acquisition costs are capitalized when incurred. Unproved
properties with individually significant acquisition costs are assessed quarterly on a
property-by-property basis, and any impairment in value is recognized. Unproved properties with
acquisition costs that are not individually significant are aggregated, and the portion of such
costs estimated to be nonproductive, based on historical experience, is amortized over the average
36
holding period. If the unproved properties are determined to be productive, the appropriate
related costs are transferred to proved oil and gas properties. Lease rentals are expensed as
incurred.
Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are
charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending
determination of whether the wells have discovered proved reserves. Exploratory drilling costs are
capitalized when drilling is completed if it is determined that there is economic producibility
supported by either actual production, conclusive formation test or by certain technical data. If
proved reserves are not discovered, such drilling costs are expensed. In some circumstances, it
may be uncertain whether proved reserves have been found when drilling has been completed. Such
exploratory well drilling costs may continue to be capitalized if the reserve quantity is
sufficient to justify its completion as a producing well and sufficient progress in assessing the
reserves and the economic and operating viability of the projects is being made. Costs to develop
proved reserves, including the costs of all development wells and related equipment used in
production of natural gas and crude oil, are capitalized.
Depreciation, depletion, and amortization of the cost of proved oil and natural gas properties
are calculated using the unit of production method. The reserve base used to calculate depletion,
depreciation or amortization for leasehold acquisition costs and the cost to acquire proved
properties is proved reserves. With respect to lease and well equipment costs, which include costs
and successful exploration drilling costs, the reserve base is proved developed reserves.
Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken
into account. Certain other assets are depreciated on a straight-line basis.
Assets are grouped in accordance with paragraph 30 of the accounting standard for financial
accounting and reporting by oil and gas producing companies. The basis for grouping is reasonable
aggregation of properties with a common geological structural feature or stratigraphic condition,
such as a reservoir or field.
Amortization rates are updated to reflect: 1) the addition of capital costs, 2) reserve
revisions (upwards or downwards) and additions, 3) property acquisitions and/or property
dispositions and 4) impairments.
We account for impairments of proved propertied under the provisions of the accounting
standard for accounting for the impairment or disposal of long-lived assets. When circumstances
indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a
producing field level to the amortized capitalized cost of the asset. If the future undiscounted
cash flows, based on our estimate of future crude oil and natural gas prices, operating costs,
anticipated production from proved reserves and other relevant data, are lower than the amortized
capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by
discounting the future cash flows at an appropriate risk-adjusted discount rate.
Reserves
In December 2009, we adopted revised oil and gas reserve estimation and disclosure
requirements which conforms the definition of proved, probable and possible reserves with the SEC
Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The
new accounting standard requires that the unweighted average, first-day-of-the-month price during
the 12-month period preceding the end of the year, rather than the year-end price, be used when
estimating reserve quantities and permits the use of reliable technologies to determine proved
reserves, if those technologies have been demonstrated to result in reliable conclusions about
reserves volumes. Prior-year data are presented in accordance with FASB oil and gas disclosure
requirements effective during those periods.
Proved reserves are those quantities of oil and gas which by analysis of geoscience and
engineering data can be estimated with reasonable certainty to be economically producible from a
given date forward from known reservoirs and under existing economic conditions, operating methods,
government regulations, etc., i.e., at prices as described above and costs as of the date the
estimates are made. Prices include consideration of changes in existing prices provided only by
contractual arrangements, and do not include adjustments based upon expected future conditions.
Probable reserves are those additional reserves that are less certain to be recovered than proved
reserves but which, together with proved reserves, are as likely as not to be recovered. Possible
reserves are those additional reserves which are less certain to be recovered than probable
reserves and thus the probability of achieving or exceeding the proved plus probable plus possible
reserves is low.
Reserves may be estimated using probabilistic methods in which there
is at least a 90 percent probability of recovery of proved reserves, at least a 50 percent probability of recovery of probable
reserves, and at least a 10 percent probability of recovery of possible reserves. Our probable reserves were calculated
using probabilistic methods and represent the 50 percent probability that the actual quantities recovered will be equal
to or greater than the proved plus probable estimate. The larger quantity of proved reserves plus probable reserves, as compared
to proved reserves only, is attributable largely to using a less conservative interpretation of reservoir size and recovery factor in
estimating probable reserves.
37
The estimate of reserves is made using available geological and reservoir data as well as
production performance data. These estimates are prepared by an independent third party petroleum
engineering consulting firm and revised, either upward or downward, as warranted by additional
data. Revisions are necessary due to changes in, among other things, reservoir performance, prices,
economic conditions and governmental restrictions, as well as
changes in the expected recovery associated with infill drilling. Decreases in prices, for
example, may cause a reduction in some proved reserves due to reaching economic limits earlier. A
material adverse change in the estimated volumes of proved reserves could have a negative impact on
DD&A expense and could result in the recognition of an impairment.
Accounting for Asset Retirement Obligation
If a reasonable estimate of the fair value of an obligation to perform site reclamation,
dismantle facilities or plug and abandon wells can be made, we record a liability (an asset
retirement obligation or ARO) on our consolidated balance sheet and capitalize the present value
of the asset retirement cost in oil and gas properties in the period in which the retirement
obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal
to the estimated future cost to satisfy the abandonment obligation assuming the normal operation of
the asset, using current prices that are escalated by an assumed inflation factor up to the
estimated settlement date, which is then discounted back to the date that the abandonment
obligation was incurred using an assumed cost of funds for our Company. After recording these
amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and
the additional capitalized costs are depreciated on a unit-of-production basis within the related
asset group. Accretion is included in operating expenses and depreciation is included in
depreciation, depletion and amortization on our consolidated statement of income.
Income Taxes
Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of
(a) future deductible/taxable amounts attributable to events that have been recognized on a
cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax
credit carry forwards. A valuation allowance for deferred tax assets is recorded when it is more
likely than not that the benefit from the deferred tax asset will not be realized.
New Accounting Pronouncements
In June 2009, the Financial Accounting Standards Board (FASB) issued an accounting standard
for subsequent events which establishes general standards of accounting for and disclosure of
events that occur after the balance sheet date but before financial statements are issued. This
standard is effective for interim or annual periods ending after June 15, 2009. We adopted this
standard effective June 15, 2009. The adoption of this standard did not have an effect on our
consolidated financial position, results of operations or cash flows.
In June 2009, the FASB issued an accounting standard for accounting for transfers of financial
assets. The objective in issuing this standard is to improve the relevance, representational
faithfulness and comparability of the information that a reporting entity provides in its financial
statements about a transfer of financial assets; the effects of a transfer on its financial
position, financial performance, and cash flows; and a transferors continuing involvement, if any,
in transferred financial assets. This standard is effective for annual periods beginning after
November 15, 2009. The adoption of this standard did not have a material impact on our
consolidated financial position, results of operations or cash flows.
In June 2009, the FASB issued an amendment to the financial interpretation to improve
financial reporting by enterprises involved with variable interest entities. This amendment is
effective for annual periods beginning after November 15, 2009. This amendment did not have a
material impact on our consolidated financial position, results of operations or cash flows.
In June 2009, the FASB issued an accounting standard that codifies and modifies the hierarchy
of generally accepted accounting principles. This standard is the source of authoritative GAAP
recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases
of the SEC under authority of federal securities laws are also sources of authoritative GAAP for
SEC registrants. This standard superseded all then-existing non-SEC accounting and reporting
standards. All other nongrandfathered non-SEC accounting literature
38
not included in this standard
is now nonauthoritative. This standard is effective for financial statements issued for interim
and annual periods ending after September 15, 2009. The adoption of this standard did not have an
impact on our consolidated financial position, results of operations or cash flows.
In December 2009, the FASB issued its final updates to oil and gas accounting rules to align
the oil and gas reserve estimation and disclosure requirements of Extractive Industries Oil and
Gas (Topic 932) with the requirements in the SECs final rule, Modernization of the Oil and Gas
Reporting Requirements, which was issued on December 31, 2008 and is effective as of December 31,
2009.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
|
|
|
Item 7A. |
|
Quantitative and Qualitative Disclosures About Market Risk |
We are exposed to market risk from adverse changes in oil and natural gas prices and
foreign exchange risk, as discussed below.
Oil Prices
As an independent oil producer, our revenue, other income and profitability, reserve values,
access to capital and future rate of growth are substantially dependent upon the prevailing prices
of crude oil and natural gas. Prevailing prices for such commodities are subject to wide
fluctuation in response to relatively minor changes in supply and demand and a variety of
additional factors beyond our control. Historically, prices received for oil production have been
volatile and unpredictable, and such volatility is expected to continue.
Foreign Exchange
The Bolivar is not readily convertible into the U.S. Dollar. We have utilized no currency
hedging programs to mitigate any risks associated with operations in Venezuela, and therefore our
financial results are subject to favorable or unfavorable fluctuations in exchange rates and
inflation in that country. Venezuela has imposed currency exchange controls (See Item 7
Managements Discussion and Analysis of Financial Condition and Results of Operations, Capital
Resources and Liquidity above).
|
|
|
Item 8. |
|
Financial Statements and Supplementary Data |
The information required by this item is included herein on pages S-1 through S-40.
|
|
|
Item 9. |
|
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
39
|
|
|
Item 9A. |
|
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 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.
Management
of the Company, with the participation of our principal executive officer and principal financial officer, evaluated the
effectiveness of the Companys disclosure controls and procedures.
Based on their evaluation as of December 31, 2009, 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.
Managements Report on Internal Control Over Financial Reporting. Our management is
responsible for establishing and maintaining adequate internal control over financial reporting, as
such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). Under the supervision and with
the participation of our management, including our principal executive officer and principal
financial officer, we conducted an evaluation of the effectiveness of our internal control over
financial reporting based on the Internal Control Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the Internal
Control Integrated Framework, our management concluded that our internal control over financial
reporting was effective as of December 31, 2009. The effectiveness of our internal control over
financial reporting as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which appears herein.
Managements Remediation Efforts. In our Annual Report on Form 10-K for the year ended
December 31, 2008, management concluded that the Company did not maintain effective controls over
the period-end financial reporting process as of December 31, 2008. Specifically, effective
controls did not exist to ensure that the deferred tax adjustments to reconcile net income reported
by Petrodelta under IFRS to that required by GAAP were completely and accurately identified and
that the necessary adjustments were appropriately analyzed and recorded on a timely basis.
During 2009, management has enhanced the controls over its equity investment to ensure that
the adequate information regarding Petrodeltas temporary deferred tax differences is obtained and
that a comprehensive analysis of such information is performed. Specifically, management has
requested further information related to the nature of each temporary deferred tax difference which
enables management to determine the impact on the deferred tax adjustment to reconcile net income
reported by Petrodelta under IFRS to that required under GAAP. The enhanced controls have enabled
management to ensure that the deferred tax adjustment to reconcile net income reported by
Petrodelta under IFRS to that required under GAAP is identified and completely and accurately
reconciled.
During the year ended December 31, 2009, management further enhanced the controls necessary to
ensure that all necessary adjustments are appropriately analyzed and recorded on a timely basis.
These enhancements were in place and operating effectively as of December 31, 2009.
Changes in Internal Control over Financial Reporting. There have been no
changes in internal control over financial reporting during the quarter ended December
31, 2009 that have materially affected or are reasonably likely to materially affect that
Companys internal control over financial reporting.
|
|
|
Item 9B. |
|
Other Information |
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Please refer to the information under the captions Election of Directors and Executive
Officers in our Proxy Statement for the 2010 Annual Meeting of Stockholders.
40
|
|
|
Item 11. |
|
Executive Compensation |
Please refer to the information under the caption Executive Compensation in our Proxy
Statement for the 2010 Annual Meeting of Stockholders.
|
|
|
Item 12. |
|
Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters |
Please refer to the information under the caption Stock Ownership in our Proxy
Statement for the 2010 Annual Meeting of Stockholders.
|
|
|
Item 13. |
|
Certain Relationships and Related Transactions, and Director
Independence |
Please refer to the information under the caption Certain Relationships and Related
Transactions in our Proxy Statement for the 2010 Annual Meeting of Stockholders.
Item 14. Principal Accountant Fees and Services
Please refer to the information under the caption Independent Registered Public
Accounting Firm in our Proxy Statement for the 2010 Annual Meeting of Stockholders.
41
PART IV
Item 15. Exhibits and Financial Statement Schedules
All other schedules are omitted because they are not applicable or the required information is
shown in the financial statements or the notes thereto.
(b) 3. Exhibits:
|
3.1 |
|
Amended and Restated Certificate of Incorporation. (Incorporated by reference
to Exhibit 3.1(i) to our Form 10-Q filed on August 13, 2002, 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 May 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 4.1 to our Form 10-Q filed on May 13, 2002, 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 |
|
Indenture dated as of February 17, 2010, between Harvest Natural Resources,
Inc. and U.S. Bank National Association, as trustee. (Incorporated by reference to
Exhibit 4.1 to our Form 8-K filed on February 18, 2010, File No. 1-10762.) |
|
|
4.5 |
|
First Supplemental Indenture dated as of February 17, 2010 between Harvest
Natural Resources, Inc. and U.S. Bank National Association, as trustee. (Incorporated
by reference to Exhibit 4.2 to our Form 8-K filed on February 18, 2010, File No.
1-10762.) |
42
|
4.6 |
|
Form of 8.25% Senior Convertible Notes due 2013. (Incorporated by reference to
Exhibit 4.3 to our Form 8-K filed on February 18, 2010, File No. 1-10762.) |
|
|
10.1 |
|
2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1
to our Registration Statement on Form S-8 filed on April 9, 2002 (Registration
Statement No. 333-85900).) |
|
|
10.2 |
|
Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by
reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on May 25,
2004 (Registration Statement No. 333-115841).) |
|
|
10.3 |
|
Form of Indemnification Agreement between Harvest Natural Resources, Inc.
and each Director and Executive Officer of the Company. (Incorporated by reference to
Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) |
|
|
10.4 |
|
Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement.
(Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23,
2005, File No. 1-10762.) |
|
|
10.5 |
|
Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock
Agreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on
February 23, 2005, File No. 1-10762.) |
|
|
10.6 |
|
Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock
Agreement. (Incorporated by reference to Exhibit 10.22 to our Form 10-K filed on
February 23, 2005, File No. 1-10762.) |
|
|
10.7 |
|
Employment Agreement dated September 12, 2005 between Harvest Natural
Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.4 to
our Form 10-Q filed on October 27, 2005, File No. 1-10762.) |
|
|
10.8 |
|
Employment Agreement dated September 15, 2005 between Harvest Natural
Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to
our Form 10-Q filed on October 27, 2005, File No. 1-10762.) |
|
|
10.9 |
|
Stock Option Agreement dated September 15, 2005, between Harvest Natural
Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.24 to
our Form 10-K filed on February 27, 2006, File No. 1-10762.) |
|
|
10.10 |
|
Stock Option Agreement dated September 15, 2005, between Harvest Natural
Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.25 to
our Form 10-K filed on February 27, 2006, File No. 1-10762.) |
|
|
10.11 |
|
Stock Option Agreement dated September 26, 2005, between Harvest Natural
Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.26 to our
Form 10-K filed on February 27, 2006, File No. 1-10762.) |
|
|
10.12 |
|
Harvest Natural Resources 2006 Long Term Incentive Plan. (Incorporated by
reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on June 1,
2006 [Registration Statement No. 333-134630].) |
|
|
10.13 |
|
Form of 2006 Long Term Incentive Plan Stock Option Agreement. (Incorporated
by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2006, File No.
1-10762.) |
|
|
10.14 |
|
Form of 2006 Long Term Incentive Plan Director Restricted Stock Agreement.
(Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2006,
File No. 1-10762.) |
43
|
10.15 |
|
Form of 2006 Long Term Incentive Plan Employee Restricted Stock Agreement.
(Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2006,
File No. 1-10762.) |
|
|
10.16 |
|
Stock Unit Award Agreement dated September 15, 2005 between Harvest
Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit
10.5 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
|
|
10.17 |
|
Stock Unit Award Agreement dated March 2, 2006 between Harvest Natural
Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.6 to
our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
|
|
10.18 |
|
Form of 2006 Long Term Incentive Plan Stock Option Agreement Five Year
Vesting, Seven Year Term. (Incorporated by reference to Exhibit 10.33 to our Form 10-K
filed on March 13, 2007, File No. 1-10762.) |
|
|
10.19 |
|
Amendment to Harvest Natural Resources 2006 Long Term Incentive Plan adopted
July 19, 2006. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on
May 3, 2007, File No. 1-10762.) |
|
|
10.20 |
|
Employment Agreement dated May 7, 2007 between Harvest Natural Resources,
Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q
filed on July 25, 2007, File No. 1-10762.) |
|
|
10.21 |
|
Stock Option Agreement dated May 7, 2007 between Harvest Natural
Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.2 to our
Form 10-Q filed on July 25, 2007, File No. 1-10762.) |
|
|
10.22 |
|
Employee Restricted Stock Agreement dated May 7, 2007 between Harvest
Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.3
to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) |
|
|
10.23 |
|
Contract for Conversion to a Mixed Company between Corporación Venezolana del
Petróleo, S.A., Harvest-Vinccler, S.C.A. and HNR Finance B.V. (Incorporated by
reference to Exhibit 10.1 to our Form 10-Q filed on November 1, 2007, File No.
1-10762.) |
|
|
10.24 |
|
Employment Agreement dated April 14, 2008 between Harvest Natural
Resources, Inc. and Patrick R. Oenbring. (Incorporated by reference to Exhibit 10.1 to
our Form 10-Q filed on May 1, 2008, File No. 1-10762.) |
|
|
10.25 |
|
Stock Option Agreement dated April 14, 2008 between Harvest Natural
Resources, Inc. and Patrick R. Oenbring. (Incorporated by reference to Exhibit 10.2 to
our Form 10-Q filed on May 1, 2008, File No. 1-10762.) |
|
|
10.26 |
|
Employee Restricted Stock Agreement dated April 14, 2008 between Harvest
Natural Resources, Inc. and Patrick R. Oenbring. (Incorporated by reference to Exhibit
10.3 to our Form 10-Q filed on May 1, 2008, File No. 1-10762.) |
|
|
10.27 |
|
Employment Agreement dated May 19, 2008 between Harvest Natural Resources,
Inc. and Stephen C. Haynes. (Incorporated by reference to Exhibit 10.1 to our Form
10-Q filed on August 7, 2008, File No. 1-10762.) |
|
|
10.28 |
|
Stock Option Agreement dated May 19, 2008 between Harvest Natural
Resources, Inc. and Stephen C. Haynes. (Incorporated by reference to Exhibit 10.2 to
our Form 10-Q filed on August 7, 2008, File No. 1-10762.) |
44
|
10.29 |
|
Employee Restricted Stock Agreement dated May 19, 2008 between Harvest
Natural Resources, Inc. and Stephen C. Haynes. (Incorporated by reference to Exhibit
10.3 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.) |
|
|
10.30 |
|
Employment Agreement dated May 19, 2008 between Harvest Natural Resources,
Inc. and G. Michael Morgan. (Incorporated by reference to Exhibit 10.4 to our Form
10-Q filed on August 7, 2008, File No. 1-10762.) |
|
|
10.31 |
|
Stock Option Agreement dated May 19, 2008 between Harvest Natural
Resources, Inc. and G. Michael Morgan. (Incorporated by reference to Exhibit 10.5 to
our Form 10-Q filed on August 7, 2008, File No. 1-10762.) |
|
|
10.32 |
|
Employee Restricted Stock Agreement dated May 19, 2008 between Harvest
Natural Resources, Inc. and G. Michael Morgan. (Incorporated by reference to Exhibit
10.6 to our Form 10-Q filed on August 7, 2008, File No. 1-10762.) |
|
|
10.33 |
|
Placement Agent Agreement dated February 10, 2010, by and among Harvest
Natural Resources, Inc., as issuer, and Lazard Capital Markets LLC and Madison Williams
and Company LLC, as placement agents, relating to the 8.25% Senior Convertible Notes
due 2013. (Incorporated by reference to Exhibit 10.1 to our Form 8-K filed on February
11, 2010, File No. 1-10762.) |
|
|
10.34 |
|
Form of Standard Subscription Agreement, to be entered into by and among
Harvest Natural Resources, Inc. and certain purchasers signatory thereto.
(Incorporated by reference to Exhibit 10.2 to our Form 8-K filed on February 11, 2010,
File No. 1-10762.) |
|
|
10.35 |
|
Form of Subscription Agreement, to be entered into by and among Harvest
Natural Resources, Inc. and certain purchasers signatory thereto. (Incorporated by
reference to Exhibit 10.3 to our Form 8-K filed on February 11, 2010, File No.
1-10762.) |
|
|
21.1 |
|
List of subsidiaries. |
|
|
23.1 |
|
Consent of PricewaterhouseCoopers LLP. |
|
|
23.2 |
|
Consent of Ryder Scott Company, LP. |
|
|
23.3 |
|
Consent of HLB PGFA Perales, Pistone & Asociados Caracas, Venezuela. |
|
|
31.1 |
|
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
executed by James A. Edmiston, President and Chief Executive Officer. |
|
|
31.2 |
|
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
executed by Stephen C. Haynes, Vice President, Chief Financial Officer and Treasurer. |
|
|
32.1 |
|
Certification accompanying Annual Report on Form 10-K 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 Annual Report on Form 10-K 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. |
|
|
99.1 |
|
Reserve report dated February 26, 2009 between Harvest (US) Holdings, Inc. and
Ryder Scott Company. |
|
|
99.2 |
|
Reserve report dated February 26, 2009 between HNR Finance B.V. and Ryder Scott
Company. |
|
|
|
|
|
Identifies management contracts or compensating plans or arrangements
required to be filed as an exhibit hereto pursuant to Item 15(a) and (b) of Form 10-K. |
45
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Harvest Natural Resources, Inc.:
In our opinion, the consolidated financial statements listed in the index appearing under Item
15(a)1 present fairly, in all material respects, the financial position of Harvest Natural
Resources, Inc. and its subsidiaries at December 31, 2009 and December 31, 2008, and the results of
their operations and their cash flows for each of the three years in the period ended December 31,
2009 in conformity with accounting principles generally accepted in the United States of America.
In addition, in our opinion, the financial statement schedule listed in the index appearing as
Schedule II in Item 15(a)2 presents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial statements. Also in our
opinion, the Company maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2009, based on criteria established in Internal Control -
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO). The Companys management is responsible for these
financial statements and financial statement schedule, for maintaining
effective internal control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting, included in Managements Report on Internal Control Over
Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these
financial statements, the financial statement schedule and on the Companys internal control over financial reporting based on our
integrated audits. We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the financial statements are free of material
misstatement and whether effective internal control over financial reporting was maintained in all
material respects. Our audits of the financial statements included examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and evaluating the overall
financial statement presentation. Our audit of internal control over financial reporting included
obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, and testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a
reasonable basis for our opinions.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in
which it accounts for noncontrolling interests effective January 1, 2009. As discussed in Note 1
to the consolidated financial statements, the Company changed the manner in which it estimates the
quantities of proved oil and natural gas reserves in 2009.
A companys internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
companys internal control over financial reporting includes those policies and procedures that (i)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
|
|
|
|
|
|
|
|
/s/ PricewaterhouseCoopers LLP
|
|
Houston, Texas |
|
March 16, 2010 |
|
|
|
S-1
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(in thousands, except per share data) |
|
ASSETS |
|
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
32,317 |
|
|
$ |
97,165 |
|
Accounts and notes receivable, net |
|
|
11,478 |
|
|
|
11,570 |
|
Advances to equity affiliate |
|
|
4,927 |
|
|
|
3,732 |
|
Prepaid expenses and other |
|
|
2,214 |
|
|
|
3,964 |
|
|
|
|
|
|
|
|
TOTAL CURRENT ASSETS |
|
|
50,936 |
|
|
|
116,431 |
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS |
|
|
3,613 |
|
|
|
3,316 |
|
INVESTMENT IN EQUITY AFFILIATES |
|
|
233,989 |
|
|
|
218,982 |
|
PROPERTY AND EQUIPMENT: |
|
|
|
|
|
|
|
|
Oil and gas properties (successful efforts method) |
|
|
58,543 |
|
|
|
22,328 |
|
Other administrative property |
|
|
3,085 |
|
|
|
2,368 |
|
|
|
|
|
|
|
|
|
|
|
61,628 |
|
|
|
24,696 |
|
Accumulated depreciation and amortization |
|
|
(1,387 |
) |
|
|
(1,159 |
) |
|
|
|
|
|
|
|
|
|
|
60,241 |
|
|
|
23,537 |
|
|
|
|
|
|
|
|
|
|
$ |
348,779 |
|
|
$ |
362,266 |
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
Accounts payable, trade and other |
|
$ |
696 |
|
|
$ |
1,662 |
|
Advance from equity affiliate |
|
|
|
|
|
|
20,750 |
|
Accrued expenses |
|
|
10,253 |
|
|
|
12,241 |
|
Accrued interest |
|
|
4,691 |
|
|
|
4,691 |
|
Income taxes payable |
|
|
1,090 |
|
|
|
77 |
|
|
|
|
|
|
|
|
TOTAL CURRENT LIABILITIES |
|
|
16,730 |
|
|
|
39,421 |
|
|
|
|
|
|
|
|
|
|
ASSET RETIREMENT LIABILITY |
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
December 31, 2009 and 2008; issued 39,495 shares and 39,128
shares at December 31, 2009 and 2008, respectively |
|
|
395 |
|
|
|
391 |
|
Additional paid-in capital |
|
|
213,337 |
|
|
|
208,868 |
|
Retained earnings |
|
|
126,244 |
|
|
|
129,351 |
|
Treasury stock, at cost, 6,448 shares and 6,444 shares at
December 31, 2009 and 2008, respectively |
|
|
(65,383 |
) |
|
|
(65,368 |
) |
|
|
|
|
|
|
|
TOTAL HARVEST STOCKHOLDERS EQUITY |
|
|
274,593 |
|
|
|
273,242 |
|
NONCONTROLLING INTEREST |
|
|
57,406 |
|
|
|
49,603 |
|
|
|
|
|
|
|
|
TOTAL EQUITY |
|
|
331,999 |
|
|
|
322,845 |
|
|
|
|
|
|
|
|
|
|
$ |
348,779 |
|
|
$ |
362,266 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
S-2
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(in thousands, except per share data) |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
160 |
|
|
$ |
|
|
|
$ |
11,217 |
* |
Gas sales |
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
181 |
|
|
|
|
|
|
|
11,217 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
|
436 |
|
|
|
201 |
|
|
|
384 |
|
Exploration expense |
|
|
7,824 |
|
|
|
16,402 |
|
|
|
850 |
|
Dry hole costs |
|
|
|
|
|
|
10,828 |
|
|
|
|
|
General and administrative |
|
|
21,854 |
|
|
|
27,215 |
|
|
|
29,096 |
|
Taxes other than on income |
|
|
1,026 |
|
|
|
(206 |
) |
|
|
423 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31,140 |
|
|
|
54,440 |
|
|
|
30,753 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from Operations |
|
|
(30,959 |
) |
|
|
(54,440 |
) |
|
|
(19,536 |
) |
Other Non-Operating Income (Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on Financing Transactions |
|
|
|
|
|
|
3,421 |
|
|
|
49,623 |
|
Investment earnings and other |
|
|
1,085 |
|
|
|
3,663 |
|
|
|
9,051 |
|
Interest expense |
|
|
(5 |
) |
|
|
(1,730 |
) |
|
|
(8,224 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,080 |
|
|
|
5,354 |
|
|
|
50,450 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Consolidated Companies Before Income Taxes |
|
|
(29,879 |
) |
|
|
(49,086 |
) |
|
|
30,914 |
|
Income Tax Expense |
|
|
1,182 |
|
|
|
25 |
|
|
|
6,312 |
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Consolidated Companies |
|
|
(31,061 |
) |
|
|
(49,111 |
) |
|
|
24,602 |
|
Net Income from Unconsolidated Equity Affiliates |
|
|
35,757 |
|
|
|
34,576 |
|
|
|
55,297 |
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
|
4,696 |
|
|
|
(14,535 |
) |
|
|
79,899 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Net Income Attributable to Noncontrolling Interest |
|
|
7,803 |
|
|
|
6,929 |
|
|
|
19,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to Harvest |
|
$ |
(3,107 |
) |
|
$ |
(21,464 |
) |
|
$ |
60,118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to Harvest Per Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.09 |
) |
|
$ |
(0.63 |
) |
|
$ |
1.65 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(0.09 |
) |
|
$ |
(0.63 |
) |
|
$ |
1.59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Recognition of deferred revenue in 2007 See Note 1 Organization and Summary of Significant
Accounting Policies Revenue Recognition. |
See accompanying notes to consolidated financial statements.
S-3
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common |
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
|
|
|
|
Non- |
|
|
|
|
|
|
Shares |
|
|
Common |
|
|
Paid-in |
|
|
Retained |
|
|
Treasury |
|
|
Controlling |
|
|
Total |
|
|
|
Issued |
|
|
Stock |
|
|
Capital |
|
|
Earnings |
|
|
Stock |
|
|
Interest |
|
|
Equity |
|
Balance at January 1, 2007 |
|
|
37,974 |
|
|
$ |
380 |
|
|
$ |
194,176 |
|
|
$ |
90,697 |
|
|
$ |
(3,844 |
) |
|
$ |
37,765 |
|
|
$ |
319,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of stock options |
|
|
402 |
|
|
|
4 |
|
|
|
1,934 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,938 |
|
Employee stock-based
compensation |
|
|
137 |
|
|
|
1 |
|
|
|
5,828 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,829 |
|
Purchase of Treasury Shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(32,647 |
) |
|
|
|
|
|
|
(32,647 |
) |
Net Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60,118 |
|
|
|
|
|
|
|
19,781 |
|
|
|
79,899 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007 |
|
|
38,513 |
|
|
|
385 |
|
|
|
201,938 |
|
|
|
150,815 |
|
|
|
(36,491 |
) |
|
|
57,546 |
|
|
|
374,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of stock options |
|
|
547 |
|
|
|
5 |
|
|
|
1,560 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,565 |
|
Employee stock-based
compensation |
|
|
68 |
|
|
|
1 |
|
|
|
5,370 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,371 |
|
Purchase of Treasury Shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(28,877 |
) |
|
|
|
|
|
|
(28,877 |
) |
Distribution to noncontrolling
Interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,872 |
) |
|
|
(14,872 |
) |
Net Income (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,464 |
) |
|
|
|
|
|
|
6,929 |
|
|
|
(14,535 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008 |
|
|
39,128 |
|
|
|
391 |
|
|
|
208,868 |
|
|
|
129,351 |
|
|
|
(65,368 |
) |
|
|
49,603 |
|
|
|
322,845 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of stock options |
|
|
205 |
|
|
|
2 |
|
|
|
384 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
386 |
|
Employee stock-based
compensation |
|
|
162 |
|
|
|
2 |
|
|
|
4,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,087 |
|
Purchase of Treasury Shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15 |
) |
|
|
|
|
|
|
(15 |
) |
Net Income (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,107 |
) |
|
|
|
|
|
|
7,803 |
|
|
|
4,696 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009 |
|
|
39,495 |
|
|
$ |
395 |
|
|
$ |
213,337 |
|
|
$ |
126,244 |
|
|
$ |
(65,383 |
) |
|
$ |
57,406 |
|
|
$ |
331,999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
S-4
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Cash Flows From Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
4,696 |
|
|
$ |
(14,535 |
) |
|
$ |
79,899 |
|
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
|
436 |
|
|
|
201 |
|
|
|
384 |
|
Dry hole costs |
|
|
|
|
|
|
10,828 |
|
|
|
|
|
Gain on financing transactions |
|
|
|
|
|
|
(3,421 |
) |
|
|
(49,623 |
) |
Net income from unconsolidated equity affiliates |
|
|
(35,757 |
) |
|
|
(34,576 |
) |
|
|
(55,297 |
) |
Non-cash compensation related charges |
|
|
4,087 |
|
|
|
6,061 |
|
|
|
6,108 |
|
Deferred income taxes |
|
|
|
|
|
|
|
|
|
|
5,608 |
|
Dividend received from equity affiliate |
|
|
|
|
|
|
72,530 |
|
|
|
|
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts and notes receivable |
|
|
92 |
|
|
|
548 |
|
|
|
393 |
|
Advances to equity affiliate |
|
|
(1,195 |
) |
|
|
12,620 |
|
|
|
2,794 |
|
Prepaid expenses and other |
|
|
(1,055 |
) |
|
|
(5,632 |
) |
|
|
214 |
|
Accounts payable |
|
|
(966 |
) |
|
|
(2,957 |
) |
|
|
2,122 |
|
Accounts payable, related party |
|
|
|
|
|
|
(10,093 |
) |
|
|
456 |
|
Advance from equity affiliate |
|
|
|
|
|
|
20,750 |
|
|
|
|
|
Accrued expenses |
|
|
(6,296 |
) |
|
|
(1,073 |
) |
|
|
(1,251 |
) |
Accrued interest |
|
|
|
|
|
|
(445 |
) |
|
|
(1,714 |
) |
Deferred revenue |
|
|
|
|
|
|
|
|
|
|
(11,217 |
) |
Income taxes payable |
|
|
1,013 |
|
|
|
(426 |
) |
|
|
469 |
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used In) Operating Activities |
|
|
(34,945 |
) |
|
|
50,380 |
|
|
|
(20,655 |
) |
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Additions of property and equipment |
|
|
(28,022 |
) |
|
|
(26,317 |
) |
|
|
(647 |
) |
Investments in equity affiliates |
|
|
|
|
|
|
(2,161 |
) |
|
|
(7,388 |
) |
(Increase) decrease in restricted cash |
|
|
|
|
|
|
6,769 |
|
|
|
82,120 |
|
Investment costs |
|
|
(581 |
) |
|
|
(1,346 |
) |
|
|
(4,125 |
) |
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used In) Investing Activities |
|
|
(28,603 |
) |
|
|
(23,055 |
) |
|
|
69,960 |
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds from issuances of common stock |
|
|
386 |
|
|
|
1,565 |
|
|
|
1,938 |
|
Purchase of treasury stock |
|
|
|
|
|
|
(29,416 |
) |
|
|
(32,755 |
) |
Financing costs |
|
|
(1,686 |
) |
|
|
(1,075 |
) |
|
|
|
|
Payments of note payable |
|
|
|
|
|
|
(7,211 |
) |
|
|
(45,726 |
) |
Dividend paid to minority interest |
|
|
|
|
|
|
(14,864 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used In Financing Activities |
|
|
(1,300 |
) |
|
|
(51,001 |
) |
|
|
(76,543 |
) |
|
|
|
|
|
|
|
|
|
|
Net Decrease in Cash and Cash Equivalents |
|
|
(64,848 |
) |
|
|
(23,676 |
) |
|
|
(27,238 |
) |
Cash and Cash Equivalents at Beginning of Year |
|
|
97,165 |
|
|
|
120,841 |
|
|
|
148,079 |
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Year |
|
$ |
32,317 |
|
|
$ |
97,165 |
|
|
$ |
120,841 |
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosures of Cash Flow Information: |
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for interest expense |
|
$ |
5 |
|
|
$ |
768 |
|
|
$ |
7,972 |
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for income taxes |
|
$ |
169 |
|
|
$ |
456 |
|
|
$ |
201 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
S-5
Supplemental Schedule of Noncash Investing and Financing Activities:
During the year ended December 31, 2009, we issued 0.2 million shares of restricted stock
valued at $0.7 million. Also, some of our employees elected to pay withholding tax on restricted
stock grants on a cashless basis which resulted in 3,757 shares being added to treasury stock at
cost.
During the year ended December 31, 2008, we issued 0.2 million of restricted stock valued at
$2.0 million; most of our employees elected to pay withholding tax on restricted stock grants on a
cashless basis which resulted in 14,457 shares being added to treasury at cost; and 106,000 shares
held in treasury were reissued as restricted stock.
During the year ended December 31, 2007, we issued 0.3 million shares of restricted stock
valued at $2.6 million; most of our employees elected to pay withholding tax on restricted stock
grants on a cashless basis which resulted in 16,042 shares being added to treasury stock at cost;
and 20,000 shares held in treasury were reissued as restricted stock.
See accompanying notes to consolidated financial statements.
S-6
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Note 1 Organization and Summary of Significant Accounting Policies
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) through our ownership in Petrodelta, S.A.
(Petrodelta). HNR Finance B.V. (HNR Finance) has a 40 percent ownership interest in
Petrodelta. As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent
interest in Petrodelta, 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 eight percent equity interest. Corporación Venezolana
del Petroleo S.A. (CVP) owns the remaining 60 percent of Petrodelta. Petrodelta is governed by
its own charter and bylaws. We have exploration acreage in the Gulf Coast Region of the United
States, the Antelope prospect in the Western 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). We also have
production from the Monument Butte project in the Antelope prospect. See Note 8 United States,
Note 9 Indonesia, Note 10 Gabon, Note 11 Oman and Note 12 China.
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.
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.
Reporting and Functional Currency
The United States Dollar (U.S. Dollar) is our reporting and functional currency. Amounts
denominated in non-U.S. Dollar currencies are re-measured in 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.
The U.S. Dollar is the reporting and functional currency for all of our controlled
subsidiaries and Petrodelta.
Revenue Recognition
Until March 31, 2006, each quarter, Harvest Vinccler, S.C.A. (Harvest Vinccler) invoiced
Petroleos de Venezuela S.A. (PDVSA), based on barrels of oil accepted by PDVSA during the
quarter, using quarterly adjusted U.S. Dollar contract service fees per barrel. With the formation
of Petrodelta in 2007, Harvest Vinccler recognized deferred revenue of $11.2 million for 2005 and
first quarter 2006 deliveries that had been deferred pending clarification on the calculation of
crude prices under a transitory agreement signed in August 2005 between Harvest Vinccler and PDVSA.
S-7
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.
Fair Value Measurements
We adopted the accounting standard for fair value measurements for financial assets as of
January 1, 2008 and for non-financial assets and liabilities as of January 1, 2009. This standard
provides guidance for using fair value to measure assets and liabilities. This standard also
clarifies the principle that fair value should be based on the assumptions that market participants
would use when pricing the asset or liability and establishes a fair value hierarchy, giving the
highest priority to quoted prices in active markets and the lowest priority to unobservable data.
The standard applies whenever other standards require assets or liabilities to be measured at fair
value. The adoption of this standard had no impact on our consolidated financial position, results
of operations or cash flows.
At December 31, 2009 and 2008, cash and cash equivalents include $26.8 million and $88.6
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 for identical assets which are defined as
Level 1 of the fair value hierarchy based on the criteria in the accounting standard for fair
value measurements.
Credit Risk and Operations
All of our total consolidated revenues in 2007 related to operations in Venezuela.
Petrodeltas sole source of revenues for its production is PDVSA Petroleo S.A. (PPSA), a 100
percent owned subsidiary of PDVSA, which maintains full ownership of all hydrocarbons in its
fields. The sale of oil and natural gas by Petrodelta to the Venezuelan government is pursuant to
a Contract for Sale and Purchase of Hydrocarbons with PPSA which was signed on January 17, 2008.
Accounts and 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 the accounting standard for
accounting by creditors for impairment of a loan. 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.
During the year ended December 31, 2008, we reclassified $2.7 million of prepaid land costs
for the Antelope project to notes receivable. The note is due in less than one year and bears
interest at a rate of 12 percent and is secured by a revenue interest in a well currently being
evaluated. At December 31, 2009, notes receivable plus accrued interest was approximately $3.3
million.
Other Assets
Other assets consist of investigative costs associated with new business development projects.
These costs are reclassified to oil and natural gas properties or expensed depending on
managements assessment of the likely outcome
S-8
of the project. During the year ended December 31,
2009, $1.4 million was reclassified to oil and gas properties and $1.7 million was reclassified to
exploration expense. During the year ended December 31, 2008, $3.8 million was reclassified to oil
and gas properties and $1.2 million was reclassified to exploration expense.
Property and Equipment
The major components of property and equipment at December 31 are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Proved property costs |
|
$ |
1,646 |
|
|
$ |
|
|
Unproved property costs |
|
|
54,111 |
|
|
|
20,960 |
|
Oilfield inventories |
|
|
2,786 |
|
|
|
1,368 |
|
Furniture and fixtures |
|
|
3,085 |
|
|
|
2,368 |
|
|
|
|
|
|
|
|
|
|
|
61,628 |
|
|
|
24,696 |
|
Accumulated depletion, impairment and depreciation |
|
|
(1,387 |
) |
|
|
(1,159 |
) |
|
|
|
|
|
|
|
|
|
$ |
60,241 |
|
|
$ |
23,537 |
|
|
|
|
|
|
|
|
Properties and equipment are stated at cost less accumulated depletion, depreciation and
amortization (DD&A). Costs of improvements that appreciably improve the efficiency or productive
capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are
expensed as incurred. Upon retirement or sale, the cost of properties and equipment, net of the
related accumulated DD&A, is removed and, if appropriate, gains or losses are recognized in
investment earnings and other.
We follow the successful efforts method of accounting for our oil and gas properties. Under
this method, exploration costs such as exploratory geological and geophysical costs, delay rentals
and exploration overhead are charged against earnings as incurred. Costs of drilling exploratory
wells are capitalized pending determination of whether proved reserves can be attributed to the
area as a result of drilling the well. If management determines that commercial quantities of
hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are
charged to exploration expense. During the year ended December 31, 2008, we charged to exploration
expense $10.8 million of exploratory well costs associated with the Harvest Hunter #1. Costs of
drilling successful exploratory wells, all development wells, and related production equipment and
facilities are capitalized and depleted or depreciated using the unit-of-production method as oil
and gas is produced. Depletion expense, which was all attributable to the Monument Butte project,
for the year ended December 31, 2009, was $0.03 million ($6.59 per equivalent barrel).
Leasehold acquisition costs are initially capitalized. Acquisition costs of unproved
leaseholds are assessed for impairment during the holding period and transferred to proved oil and
gas properties to the extent associated with successful exploration activities. Costs of
maintaining and retaining undeveloped leaseholds, as well as amortization and impairment of
unsuccessful leases, are included in exploration expense. Costs of expired or abandoned leases are
charged to exploration expense, while costs of productive leases are transferred to proved oil and
gas properties.
Proved oil and gas properties are reviewed for impairment at a level for which identifiable
cash flows are independent of cash flows of other assets when facts and circumstances indicate that
their carrying amounts may not be recoverable. In performing this review, future net cash flows are
determined based on estimated future oil and gas sales revenues less future expenditures necessary
to develop and produce the reserves. If the sum of these undiscounted estimated future net cash
flows is less than the carrying amount of the property, an impairment loss is recognized for the
excess, if any, of the propertys carrying amount over its estimated fair value, which is generally
based on discounted future net cash flows. No impairment of proved oil and gas properties was
required in 2009.
Costs of drilling and equipping successful exploratory wells, development wells, asset
retirement liabilities and costs to construct or acquire offshore platforms and other facilities,
are depreciated using the unit-of-production method based on total estimated proved developed
reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred
from unproved leaseholds, are depleted using the unit-of-production method
S-9
based on total estimated
proved reserves. All other properties are stated at historical acquisition cost, net of allowance
for impairment, and depreciated using the straight-line method over the useful lives of the assets.
Undeveloped property costs, including oilfield inventories, consist of $3.1 million for West
Bay, $36.4 million for Mesaverde, $2.0 million for the Budong-Budong production sharing contract
(Budong PSC), $6.9 million for the Dussafu Marin exploration production sharing contract
(Dussafu PSC), $3.8 million for the Oman
exploration and production sharing agreement (Block 64 EPSA), $3.0 million for WAB-21, and
$1.7 million for other projects.
Depreciation of furniture and fixtures is computed using the straight-line method with
depreciation rates based upon the estimated useful life of the property, generally 5 years.
Leasehold improvements are depreciated over the life of the applicable lease. Depreciation expense
was $0.4 million, $0.2 million and $0.4 million for the years ended December 31, 2009, 2008 and
2007, respectively.
Reserves
In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which
is effective for reporting 2009 reserve information. In January 2010, the Financial Accounting
Standards Board (FASB) issued its authoritative guidance on extractive activities for oil and gas
to align its requirements with the SECs final rule. We adopted the guidance as of December 31,
2009 in conjunction with our year-end reserve report as a change in accounting principle that is
inseparable from a change in accounting estimate. Such a change is accounted for prospectively
under the authoritative accounting guidance. Comparative disclosures applying the new for periods
before the adoption of the FASBs final rule are not required.
The adoption of the FASBs final rule on December 31, 2009 impacted our financial statements
and other disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009, as
follows:
|
|
|
All oil and gas reserves volumes presented as of and for the year ended December 31,
2009 were prepared using the updated reserves rules and are not on a basis comparable with
prior periods. The change in comparability occurred because the FASBs final rule requires
the use of the unweighted 12-month average of the first-day-of-the-month reference price
for the prior twelve month period and permits the use of reliable technologies to support
reserve estimates. Under the previous reserve estimation rules, which are no longer in
effect, our reserves would have been calculated using end of period prices. |
|
|
|
The impairment review of our proved oil and gas properties used undiscounted estimated
future net cash flows models for our estimated proved developed reserves which were
calculated using the FASBs final rule. |
|
|
|
We historically have applied a policy of using our year-end proved reserves to calculate
our fourth quarter depletion rate. As a result, the estimate of proved reserves for
determining our deletion rate and resulting expense for the fourth quarter of 2009 is not
on a basis comparable to the prior quarters of prior years. |
The impact of the adoption of the FASBs final rule on our financial statements is not
practicable to estimate due to the operational and technical challenges associated with calculating
a cumulative effect of adoption by preparing reserve reports under both the old and new rules.
The process for preparation of our oil and gas reserves estimates is completed in accordance
with our prescribed internal control procedures, which include verification of data provided for,
management reviews and review of the independent third party reserves report. The technical
employee responsible for overseeing the process for preparation of the reserves estimates has a
Bachelor of Arts in Engineering Science, a Master of Science in Petroleum Engineering, has more
than 25 years of experience in reservoir engineering and is a member of the Society of Petroleum
Engineers.
All reserve information in this report is based on estimates prepared by Ryder Scott Company
L.P. (Ryder Scott), independent petroleum engineers. The technical personnel responsible for
preparing the reserve estimates at Ryder Scott meet the requirements regarding qualifications,
independence, objectivity and confidentiality set
S-10
forth in the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum
Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists
and petrophysicists; they do not own an interest in our properties and are not employed on a
contingent fee basis.
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 in the
year ended December 31, 2009. Changes in asset retirement obligations during the year ended
December 31, 2009 were as follows (in thousands):
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
Asset retirement obligations beginning of period |
|
$ |
|
|
Liabilities recorded during the period |
|
|
50 |
|
Liabilities settled during the period |
|
|
|
|
Revisions in estimated cash flows |
|
|
|
|
Accretion expense |
|
|
|
|
|
|
|
|
Asset retirement obligations end of period |
|
$ |
50 |
|
|
|
|
|
Income Taxes
Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of
(a) future deductible/taxable amounts attributable to events that have been recognized on a
cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax
credit carryforwards. A valuation allowance for deferred tax assets is recorded when it is more
likely than not that the benefit from the deferred tax asset will not be realized. With the
formation of Petrodelta, Harvest Vinccler recognized the deferred tax related to the deferred
revenue discussed above.
Financial Instruments
Our financial instruments that are exposed to concentrations of credit risk consist primarily
of cash and cash equivalents and accounts receivable. 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.
Noncontrolling Interests
We adopted the accounting standard for noncontrolling interests in consolidated financial
statements as of January 1, 2009. This standard establishes accounting and reporting standards for
ownership interests in subsidiaries held by parties other than the parent, the amount of
consolidated net income attributable to the parent and to the noncontrolling interest, changes in a
parents ownership interest and the valuation of retained noncontrolling equity investments when a
subsidiary is deconsolidated. This standard also establishes reporting requirements that provide
sufficient disclosures that clearly identify and distinguish between the interest of the parent and
the interests of the noncontrolling owner. The retrospective adoption of this standard impacted
the presentation of our consolidated financial position, results of operations and cash flows.
New Accounting Pronouncements
In June 2009, the Financial Accounting Standards Board (FASB) issued an accounting standard
for subsequent events which establishes general standards of accounting for and disclosure of
events that occur after the balance sheet date but before financial statements are issued. This
standard is effective for interim or annual periods ending after June 15, 2009. We adopted this
standard effective June 15, 2009. The adoption of this standard did not have an effect on our
consolidated financial position, results of operations or cash flows.
S-11
In June 2009, the FASB issued an accounting standard for accounting for transfers of financial
assets. The objective in issuing this standard is to improve the relevance, representational
faithfulness and comparability of the information that a reporting entity provides in its financial
statements about a transfer of financial assets; the effects of a transfer on its financial
position, financial performance, and cash flows; and a transferors continuing involvement, if any,
in transferred financial assets. This standard is effective for annual periods beginning after
November 15, 2009. The adoption of this standard did not have a material impact on our
consolidated financial position, results of operations or cash flows.
In June 2009, the FASB issued an amendment to the financial interpretation to improve
financial reporting by enterprises involved with variable interest entities. This amendment is
effective for annual periods beginning after November 15, 2009. This amendment did not have a
material impact on our consolidated financial position, results of operations or cash flows.
In June 2009, the FASB issued an accounting standard that codifies and modifies the hierarchy
of generally accepted accounting principles. This standard is the source of authoritative GAAP
recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases
of the Securities and Exchange Commission (SEC) under authority of federal securities laws are
also sources of authoritative GAAP for SEC registrants. This standard superseded all then-existing
non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting
literature not included in this standard is now nonauthoritative. This standard is effective for
financial statements issued for interim and annual periods ending after September 15, 2009. The
adoption of this standard did not have an impact on our consolidated financial position, results of
operations or cash flows.
In December 2009, the FASB issued its final updates to oil and gas accounting rules to align
the oil and gas reserve estimation and disclosure requirements of Extractive Industries Oil and
Gas (Topic 932) with the requirements in the SECs final rule, Modernization of the Oil and Gas
Reporting Requirements, which was issued on December 31, 2008 and is effective for the year ended
December 31, 2009. We have complied with the disclosure requirements in our Annual Report on Form
10-K for the year ended December 31, 2009.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure
of contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. The most significant estimates
pertain to proved oil and natural gas reserve volumes and future development costs. Actual results
could differ from those estimates.
Reclassifications
Certain items in 2008 have been reclassified to conform to the 2009 financial statement
presentation.
Note 2 Long-Term Debt and Liquidity
In November 2006, Harvest Vinccler entered into a three-year term loan with a Venezuelan bank
to pay the SENIAT, the Venezuelan income tax authority, income tax assessments and related
interest, refinance a portion of a 105 million Venezuela Bolivar (Bolivar) loan and to fund
operating requirements. The loan was collateralized by a $6.8 million deposit plus interest in a
U.S. bank. On July 9, 2008, the loan was repaid in full and the cash collateral returned to us.
We have no other debt obligations.
We have incurred $2.8 million in costs related to ongoing negotiations for a future financing.
If successful, these costs will be amortized over the life of the financial instrument.
Liquidity Based on our cash balance of $32.3 million at December 31, 2009, we will be
required to raise additional funds in order to fund our future operating and capital expenditures.
As we disclosed in previous filings, our cash is being used to fund oil and gas exploration
projects and to a lesser extent general and administrative costs. Currently, our primary source of
cash is dividends from Petrodelta. However, there is no certainty that
S-12
Petrodelta will pay
dividends in 2010 or 2011. Our lack of cash flow and the unpredictability of cash dividends from
Petrodelta could make it difficult to obtain financing, and accordingly, there is no assurance
adequate financing can be raised. We continue to pursue, as appropriate, additional actions
designed to generate liquidity including seeking of financing sources, accessing equity and debt
markets, exploration of our properties worldwide, and cost reductions. In addition, we could delay
discretionary capital spending to future periods or sell assets as necessary to maintain the
liquidity required to run our operations, if necessary. There can be no assurances that any of
these possible efforts will be successful or adequate, and if they are not, our financial condition
and liquidity could be materially adversely affected.
Note 3 Commitments and Contingencies
We have employment contracts with seven executive officers which provide for annual base
salaries, eligibility for bonus compensation and various benefits. The contracts provide for a
lump sum payment as a multiple of base salary in the event of termination of employment without
cause. In addition, these contracts provide for payments as a multiple of base salary and bonus,
excise tax reimbursement, outplacement services and a continuation of benefits in the event of
termination without cause following a change in control. By providing one year notice, these
agreements may be terminated by either party on or after May 31, 2010.
In April 2004, we signed a ten-year lease for office space in Houston, Texas, for
approximately $17,000 per month. In December 2008, we signed a five-year lease for additional
office space in Houston, Texas, for approximately $15,000 per month. In November 2008, Harvest
Vinccler extended its lease for office space in Caracas, Venezuela for two years for approximately
$10,000 per month. In August 2008, we signed a two-year lease in Roosevelt, Utah for approximately
$6,000 per month. In October 2008, we signed a two-year lease for office space in Singapore for
approximately $19,000 per month. In April 2009, we signed a two-year lease for office space in
Indonesia for approximately $5,000 per month. In September 2009, we signed a two-year lease for
office space in Oman for approximately $5,000 per month. In November 2009, we signed a one-year lease for office space in London for approximately
$24,000 per month. We do not have any long-term contractual
commitments for any of our projects.
Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural
Resources, Inc., Chemex, Inc., Benton-Vinccler, C.A., Gale Campbell and Sheila Campbell in the
District Court for Harris County, Texas. This suit was brought in May 2003 by Excel alleging,
among other things, breach of a consulting agreement between Excel and us, misappropriation of
proprietary information and trade secrets, and fraud. Excel seeks actual and exemplary damages,
injunctive relief and attorneys fees. In April 2007, the court set the case for trial. The trial
date, reset for the first quarter of 2009, had been stayed indefinitely. On October 20, 2009, the
stay was lifted. A trial date of November 1, 2010 has been set. We dispute Excels 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 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. |
S-13
|
|
|
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. |
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.
In June 2007, the SENIAT issued an assessment for taxes in the amount of $0.4 million for
Harvest Vincclers failure to withhold VAT from vendors during 2005. Also, the SENIAT imposed
penalties and interest in the amount of $1.3 million for Harvest Vincclers failure to withhold
VAT. In July 2008, the SENIAT adjusted the assessment for penalties and interest to the change in
tax units as mandated by the Venezuelan tax code and issued a new assessment for $2.3 million. The
change in assessment resulted in an additional $1.0 million expense recorded in the year ended
December 31, 2008. In August 2008, Harvest Vinccler filed an appeal in the tax courts and
presented a proposed settlement with the SENIAT. In October 2008, after consideration of our
proposed settlement, the SENIAT offered a counter-proposal which Harvest Vinccler accepted.
Throughout 2009, the General Attorney Office and Harvest-Vinccler agreed several times to resuspend
the case while the Finance Minister and the SENIAT confirmed their acceptance to the proposed
settlement. On December 30, 2009, Harvest Vinccler settled the case for 3.1 million Bolivars
(approximately $1.4 million) for penalties and interest and closed the case with the SENIATs
concurrence. As a result of the settlement, in December 2009, Harvest Vinccler reversed $0.9
million of accrued penalties and interest previously accrued based on notices received from the
SENIAT.
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.
S-14
Note 4 Taxes
Taxes Other Than on Income
The components of taxes other than on income were (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Franchise taxes |
|
$ |
182 |
|
|
$ |
(951 |
) |
|
$ |
166 |
|
Severance taxes |
|
|
11 |
|
|
|
|
|
|
|
|
|
Payroll and other taxes |
|
|
833 |
|
|
|
745 |
|
|
|
257 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,026 |
|
|
$ |
(206 |
) |
|
$ |
423 |
|
|
|
|
|
|
|
|
|
|
|
During the year ended December 31, 2008, we reversed a $1.1 million franchise tax provision
that is no longer required.
Taxes on Income
The tax effects of significant items comprising our net deferred income taxes as of
December 31, 2009, are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Operating loss carryforwards |
|
$ |
15,599 |
|
|
$ |
7,547 |
|
Dry hole costs |
|
|
|
|
|
|
4,060 |
|
Stock options |
|
|
1,426 |
|
|
|
1,680 |
|
Valuation allowance |
|
|
(17,025 |
) |
|
|
(7,841 |
) |
|
|
|
|
|
|
|
Net deferred tax asset |
|
|
|
|
|
|
5,446 |
|
|
|
|
|
|
|
|
|
|
Deferred tax liability: |
|
|
|
|
|
|
|
|
Tax on undistributed earnings |
|
|
|
|
|
|
(5,446 |
) |
|
|
|
|
|
|
|
Net deferred tax asset (liability) |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
We currently have undistributed earnings from foreign affiliates of $5.9 million at our
Netherlands Antilles subsidiary, HNR Energia B.V. The full amount would be subject to United
States income tax if distributed to us.
The valuation allowance increased by $9.2 million as a result of additional net operating
losses and tax benefits that we do not expect to fully realize through future taxable income.
Realization of deferred tax assets associated with net operating loss carryforwards is dependent
upon generating sufficient taxable income prior to their expiration. Management anticipates that
additional losses will be generated and that it is more likely than not that they will not be
realized through future taxable income. Management further anticipates that any unremitted foreign
earnings will be reinvested outside of the U.S.
The components of income before income taxes are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Income (loss) before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
(22,357 |
) |
|
$ |
(34,760 |
) |
|
$ |
(17,786 |
) |
Foreign |
|
|
(7,522 |
) |
|
|
(14,326 |
) |
|
|
48,700 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(29,879 |
) |
|
$ |
(49,086 |
) |
|
$ |
30,914 |
|
|
|
|
|
|
|
|
|
|
|
S-15
The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
39 |
|
|
$ |
(128 |
) |
|
$ |
400 |
|
Foreign |
|
|
1,143 |
|
|
|
153 |
|
|
|
5,912 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,182 |
|
|
|
25 |
|
|
|
6,312 |
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
Foreign |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,182 |
|
|
$ |
25 |
|
|
$ |
6,312 |
|
|
|
|
|
|
|
|
|
|
|
A comparison of the income tax expense (benefit) at the federal statutory rate to our
provision for income taxes is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Computed tax expense (benefit) at the statutory rate |
|
$ |
(10,458 |
) |
|
$ |
(17,180 |
) |
|
$ |
10,820 |
|
Effect of foreign source income and rate differentials on
foreign income |
|
|
3,775 |
|
|
|
5,167 |
|
|
|
(11,140 |
) |
Change in valuation allowance |
|
|
9,184 |
|
|
|
6,059 |
|
|
|
1,085 |
|
Tax on undistributed earnings |
|
|
|
|
|
|
5,446 |
|
|
|
|
|
Deemed income inclusion under Subpart F |
|
|
|
|
|
|
968 |
|
|
|
12,942 |
|
Net operating loss utilization |
|
|
|
|
|
|
|
|
|
|
(7,306 |
) |
Foreign disregarded entities |
|
|
21 |
|
|
|
(268 |
) |
|
|
|
|
Return to accrual adjustment |
|
|
(1,093 |
) |
|
|
(166 |
) |
|
|
|
|
Other |
|
|
(247 |
) |
|
|
(1 |
) |
|
|
(89 |
) |
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
$ |
1,182 |
|
|
$ |
25 |
|
|
$ |
6,312 |
|
|
|
|
|
|
|
|
|
|
|
Rate differentials for foreign income result from tax rates different from the U.S. tax rate
being applied in foreign jurisdictions.
At December 31, 2009, we had, for federal income tax purposes, operating loss carryforwards of
approximately $44.4 million, expiring in the years 2026 through 2029.
Accounting for Uncertainty in Income Taxes
Effective January 1, 2007, we adopted the interpretation for accounting for uncertainty in
income taxes which was an interpretation of the accounting standard accounting for income taxes.
This interpretation created a single model to address accounting for uncertainty in tax positions.
This interpretation clarifies the accounting for income taxes, by prescribing a minimum recognition
threshold a tax position is required to meet before being recognized in the financial statements.
We or one of our subsidiaries files income tax returns in the U.S. federal jurisdiction, and
various states and foreign jurisdictions. With few exceptions, we are no longer subject to U.S.
federal, state and local, or non-U.S. income tax examinations by tax authorities for years prior to
2006. To date, the Internal Revenue Service (IRS) has not performed an examination of our U.S.
income tax returns for 2006 through 2008.
We do not have any unrecognized tax benefits or loss contingencies.
Note 5 Stock Option and Stock Purchase Plans
In May 2006, our shareholders approved the 2006 Long Term Incentive Plan (the 2006 Plan).
The 2006 Plan provides for the issuance of up to 1,825,000 shares of our common stock in
satisfaction of exercised stock options, stock appreciation rights (SARs) and restricted stock to
eligible participants including employees, non-employee directors and consultants of our company or
subsidiaries. Under the 2006 Plan, no more than 325,000 shares may be granted as restricted stock.
No individual may be granted more than 900,000 options or SARs and no more than 175,000 shares of
restricted stock during any period of three consecutive calendar years. The exercise price of
stock options granted under the 2006 Plan must be no less than the fair market value of our common
stock on the date of grant. All options granted through December 31, 2006 vest ratably over a
three to five year period
S-16
from their dates of grant and expire seven to ten years from grant date.
Restricted stock granted to employees or consultants to date is subject to a restriction period of
not less than 36 months during which the stock will be
deposited with Harvest and is subject to forfeiture under certain circumstances. Restricted stock
granted to non-employee directors vests as to one-third of the shares on each anniversary of the
date of grant of the award provided that he is still a director on that date. The 2006 Plan also
permits the granting of performance awards to eligible employees and consultants. Performance
awards are paid only in cash and are based upon achieving established indicators of performance
over an established period of time of at least one year. No employee or consultant shall be
granted a performance award during a calendar year that could result in a cash payment of more than
$5.0 million. In the event of a change in control, any restrictions on restricted stock will
lapse, the indicators of performance under a performance award will be treated as having been
achieved and any outstanding options and SARs will vest and become exercisable.
In May 2004, our shareholders approved the 2004 Long Term Incentive Plan (the 2004 Plan).
The 2004 Plan provides for the issuance of up to 1,750,000 shares of our common stock in
satisfaction of exercised stock options, stock appreciation rights (SARs) and restricted stock to
eligible participants including employees, non-employee directors and consultants of our company or
subsidiaries. Under the 2004 Plan, no more than 438,000 shares may be granted as restricted stock,
and no individual may be granted more than 110,000 shares of restricted stock or 438,000 in options
over the life of the Plan. The exercise price of stock options granted under the 2004 Plan must be
no less than the fair market value of our common stock on the date of grant. All options granted
to date vest ratably over a three-year period from their dates of grant and expire ten years from
grant date. Restricted stock granted to employees or consultants to date is subject to a
restriction period of not less than 36 months during which the stock will be deposited with Harvest
and is subject to forfeiture under certain circumstances. Restricted stock granted to non-employee
directors vests as to one-third of the shares on each anniversary of the date of grant of the award
provided that he is still a director on that date (as amended). The 2004 Plan also permits the
granting of performance awards to eligible employees and consultants. Performance awards are paid
only in cash and are based upon achieving established indicators of performance over an established
period of time of at least one year. Performance awards granted under the Plan may not exceed $5.0
million in a calendar year and may not exceed $2.5 million to any one individual in a calendar
year. In the event of a change in control, any restrictions on restricted stock will lapse, the
indicators of performance under a performance award will be treated as having been achieved and any
outstanding options and SARs will vest and become exercisable.
In July 2001, our shareholders approved the 2001 Long Term Stock Incentive Plan (the 2001
Plan). The 2001 Plan provides for grants of options to purchase up to 1,697,000 shares of our
common stock in the form of Incentive Stock Options and Non-Qualified Stock Options to eligible
participants including employees of our company or subsidiaries, directors, consultants and other
key persons. The exercise price of stock options granted under the 2001 Plan must be no less than
the fair market value of our common stock on the date of grant. No officer may be granted more
than 500,000 options during any one fiscal year, as adjusted for any changes in capitalization,
such as stock splits. In the event of a change in control, all outstanding options become
immediately exercisable to the extent permitted by the plan. All options granted to date vest
ratably over a three-year period from their dates of grant and expire ten years from grant date.
Since 1989 we have adopted several other stock option plans under which options to purchase
shares of our common stock have been granted to employees, officers, directors, independent
contractors and consultants. Options granted under these plans have been at prices equal to the
fair market value of the stock on the grant dates. Options granted under the plans are generally
exercisable in varying cumulative periodic installments after one year and cannot be exercised more
than ten years after the grant dates. Following the adoption of the 2001 Plan, no options may be
granted under any of these plans.
S-17
A summary of the status of our stock option plans as of December 31, 2009, 2008 and 2007 and
changes during the years ending on those dates is presented below (shares in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
Weighted |
|
|
Weighted |
|
|
Weighted |
|
|
|
Average |
|
|
Average |
|
|
Average |
|
|
|
Exercise |
|
|
Exercise |
|
|
Exercise |
|
|
|
Price |
|
|
Shares |
|
|
Price |
|
|
Shares |
|
|
Price |
|
|
Shares |
|
Outstanding at beginning of the year: |
|
$ |
8.54 |
|
|
|
3,783 |
|
|
$ |
7.80 |
|
|
|
4,172 |
|
|
$ |
7.70 |
|
|
|
4,123 |
|
Options granted |
|
|
4.60 |
|
|
|
118 |
|
|
|
10.28 |
|
|
|
444 |
|
|
|
9.63 |
|
|
|
866 |
|
Options exercised |
|
|
(2.11 |
) |
|
|
(205 |
) |
|
|
(2.86 |
) |
|
|
(548 |
) |
|
|
(4.73 |
) |
|
|
(397 |
) |
Options cancelled |
|
|
(2.95 |
) |
|
|
(333 |
) |
|
|
(11.34 |
) |
|
|
(285 |
) |
|
|
(13.49 |
) |
|
|
(420 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of the year |
|
|
9.35 |
|
|
|
3,363 |
|
|
|
8.54 |
|
|
|
3,783 |
|
|
|
7.80 |
|
|
|
4,172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of the year |
|
|
9.09 |
|
|
|
2,066 |
|
|
|
7.23 |
|
|
|
2,147 |
|
|
|
5.87 |
|
|
|
2,372 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant option groups outstanding at December 31, 2009 and related weighted average
price and life information follow (shares in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding |
|
|
Exercisable |
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
Range of |
|
Number |
|
|
Remaining |
|
|
Average |
|
|
Aggregate |
|
|
Number |
|
|
Average |
|
|
Aggregate |
|
Exercise |
|
Outstanding |
|
|
Contractual |
|
|
Exercise |
|
|
Intrinsic |
|
|
Exercisable |
|
|
Exercise |
|
|
Intrinsic |
|
Prices |
|
at 12/31/09 |
|
|
Life |
|
|
Price |
|
|
Value |
|
|
at 12/31/09 |
|
|
Price |
|
|
Value |
|
$1.55 - $2.07 |
|
|
336 |
|
|
|
0.6 |
|
|
$ |
1.71 |
|
|
$ |
1,205 |
|
|
|
336 |
|
|
$ |
1.71 |
|
|
$ |
1,205 |
|
$4.60 - $7.10 |
|
|
274 |
|
|
|
4.2 |
|
|
|
5.31 |
|
|
|
107 |
|
|
|
156 |
|
|
|
5.86 |
|
|
|
25 |
|
$8.78 - $10.91 |
|
|
2,167 |
|
|
|
5.0 |
|
|
|
10.02 |
|
|
|
|
|
|
|
1,001 |
|
|
|
9.75 |
|
|
|
|
|
$12.25 - $13.90 |
|
|
586 |
|
|
|
3.6 |
|
|
|
13.13 |
|
|
|
|
|
|
|
573 |
|
|
|
13.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,363 |
|
|
|
|
|
|
|
|
|
|
$ |
1,312 |
|
|
|
2,066 |
|
|
|
|
|
|
$ |
1,230 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic value in the preceding table represents the total pretax
intrinsic value based on our closing stock price of $5.29 of December 31, 2009, which would have
been received by the option holders had all option holders exercised their options as of that date.
The value of each option grant is estimated on the date of grant using the Black-Scholes
option pricing model with the following weighted-average assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
For options granted during: |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Weighted average fair value |
|
$ |
4.60 |
|
|
$ |
5.85 |
|
|
$ |
4.67 |
|
Weighted averaged expected life |
|
|
7 |
|
|
|
7 |
|
|
|
7 |
|
Valuation assumptions: |
|
|
|
|
|
|
|
|
|
|
|
|
Expected volatility |
|
|
68.9 |
% |
|
|
46.6-49.7 |
% |
|
|
47.7-48.7 |
% |
Risk-free interest rate |
|
|
3.5 |
% |
|
|
3.0-3.9 |
% |
|
|
4.5%-4.6 |
% |
Expected dividend yield |
|
|
0 |
% |
|
|
0 |
% |
|
|
0 |
% |
Expected annual forfeitures |
|
|
3 |
% |
|
|
3 |
% |
|
|
3 |
% |
The Black-Scholes option pricing model was developed for use in estimating the value of traded
options that have no vesting restrictions and are fully transferable. In addition, option pricing
models require the input of highly subjective assumptions, including the expected stock price
volatility and expected life. The expected volatility is based on historical volatilities of our
stock. Historical data is used to estimate option exercise and employee termination within the
valuation model. The expected term of options granted is derived from the output of the option
valuation model and represents the period of time that options are expected to be outstanding. The
risk-free rate for the periods within the contractual life of the option is based on the U.S.
Treasury yield curve in effect at the time of grant.
A summary of our nonvested options as of December 31, 2009, and changes during the year ended
December 31, 2009, is presented below (shares in thousands):
S-18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average |
|
|
|
Nonvested |
|
|
Grant-Date |
|
|
|
Options |
|
|
Fair Value |
|
Nonvested at January 1, 2009 |
|
|
1,979 |
|
|
$ |
5.80 |
|
Granted |
|
|
118 |
|
|
|
3.13 |
|
Vested |
|
|
(567 |
) |
|
|
(5.82 |
) |
Forfeited |
|
|
(10 |
) |
|
|
(5.64 |
) |
|
|
|
|
|
|
|
|
Nonvested at December 31, 2009 |
|
|
1,520 |
|
|
|
5.59 |
|
|
|
|
|
|
|
|
|
As of December 31, 2009, there was $3.7 million of total unrecognized compensation cost
related to nonvested share-based compensation arrangements granted under our plans. That cost is
expected to be recognized over the next three to four years. The total fair value of shares vested
during the years ended December 31, 2009, 2008 and 2007 was $2.6 million, $4.0 million and $4.5
million, respectively.
In addition to options issued pursuant to the plans, options have been issued to new hire
employees as employment inducement grants under a New York Stock Exchange (NYSE) exception.
These options were granted in 2007 and 2008 between $10.07 and $12.63 and vest over three years.
At December 31, 2009, a total of 360,000 options issued outside of the plans were outstanding and
136,666 options were exercisable.
Stock options of 0.2 million were exercised in the year ended December 31, 2009 resulting in
cash proceeds of $0.4 million. Stock options of 0.5 million were exercised in the year ended
December 31, 2008 resulting in cash proceeds of $1.6 million.
Treasury Stock Buy-Back Program
In July 2008, our Board of Directors authorized the purchase of up to $20 million of our
common stock from time to time through open market transactions. As of December 31, 2008, 1.2
million shares of stock had been purchased at an average cost of $10.17 per share for a total cost
of $12.2 million of the $20 million authorization. During the year ended December 31, 2009, no
stock was purchased under this program.
Note 6 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. The
results of operations and economic benefits of our minority equity investment in Petrodelta from
April 1, 2006 through December 31, 2007 were recorded in the three months ended December 31, 2007
as Net Income from Unconsolidated Equity Affiliates. Oil and gas sales for 2007 is the recognition
of the deferred revenue recorded by Harvest Vinccler for 2005 and first quarter 2006 deliveries
pending clarification on the calculation of crude prices under the Transitory Agreement (see Note 1
Organization and Summary of Significant Accounting Policies, Revenue Recognition). 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.
S-19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Segment Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales: |
|
|
|
|
|
|
|
|
|
|
|
|
United States and other |
|
$ |
181 |
|
|
$ |
|
|
|
$ |
|
|
Venezuela |
|
|
|
|
|
|
|
|
|
|
11,217 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales |
|
|
181 |
|
|
|
|
|
|
|
11,217 |
|
|
|
|
|
|
|
|
|
|
|
Segment Income (Loss) Attributable to Harvest |
|
|
|
|
|
|
|
|
|
|
|
|
Venezuela |
|
|
39,696 |
|
|
|
33,020 |
|
|
|
79,878 |
|
Indonesia |
|
|
(5,124 |
) |
|
|
(8,966 |
) |
|
|
(7 |
) |
United States and other |
|
|
(37,679 |
) |
|
|
(45,518 |
) |
|
|
(19,753 |
) |
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Harvest |
|
$ |
(3,107 |
) |
|
$ |
(21,464 |
) |
|
$ |
60,118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(in thousands) |
|
Operating Segment Assets |
|
|
|
|
|
|
|
|
Venezuela |
|
$ |
249,484 |
|
|
$ |
231,755 |
|
Indonesia |
|
|
5,893 |
|
|
|
1,556 |
|
United States and other |
|
|
113,555 |
|
|
|
152,184 |
|
|
|
|
|
|
|
|
|
|
|
368,932 |
|
|
|
385,495 |
|
Intersegment eliminations |
|
|
(20,153 |
) |
|
|
(23,229 |
) |
|
|
|
|
|
|
|
|
|
$ |
348,779 |
|
|
$ |
362,266 |
|
|
|
|
|
|
|
|
Note 7 Investment in Equity Affiliates
Petrodelta, S.A.
On October 25, 2007, the Venezuelan Presidential Decree which formally transferred to
Petrodelta the rights to the Petrodelta Fields subject to the conditions of the Conversion Contract
was published in the Official Gazette. Petrodelta will engage in the exploration, production,
gathering, transportation and storage of hydrocarbons from the Petrodelta Fields for a maximum of
20 years from that date. Petrodelta has undertaken its operations in accordance with Petrodeltas
business plan as set forth in the Conversion Contract. Under the 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. On February 4, 2010, Petrodeltas board of
directors endorsed a capital budget of $205 million for Petrodeltas 2010 business plan.
The sale of oil and gas by Petrodelta to the Venezuelan
government is pursuant to a Contract for Sale and Purchase of
Hydrocarbons with PPSA signed on January 17, 2008. The form of the agreement is
set forth in the Conversion Contract. Crude oil delivered from the Petrodelta Fields to 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. 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 of each invoice within 60 days of the end of the
invoiced production month by wire transfer, in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered, and in Bolivars
in the case of payment for natural gas delivered, in immediately available funds to the bank accounts designated by Petrodelta. Any
dividend paid by Petrodelta will be made in U.S. Dollars.
On April 23, 2009, Petrodeltas board of directors declared a dividend of $51.9 million, $20.8
million net to HNR Finance ($16.6 million net to our 32 percent interest), which represents
Petrodeltas net income as reported under International Financial Reporting Standards (IFRS) for
the six months ended June 30, 2008. HNR Finance received the cash related to this dividend in the
form of an advance dividend in October 2008.
On April 15, 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 was based on prices for Brent crude. On
July 10, 2008, the Venezuelan government published an amendment to the Windfall Profits Tax
(amended Windfall Profits Tax) to be calculated on the Venezuelan Export Basket (VEB) of prices
as published by the Ministry of the Peoples Power for Energy and Petroleum (MENPET). The
amended Windfall Profits Tax was made retroactive to April 15, 2008, the date of the original
Windfall Profits Tax. As instructed by CVP, Petrodelta has applied the amended Windfall Profits
Tax to gross oil production delivered to PDVSA since April 15, 2008 when the tax was enacted. The
amended 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 amended Windfall Profits Tax is reported as expense on the income statement and is deductible
for Venezuelan tax purposes. Petrodelta recorded $0.9 million and $56.4 million of expense for the
amended Windfall Profits Tax during the years ended December 31, 2009 and 2008, respectively.
S-20
During the second quarter of 2009, PDVSA completed an actuarial study for their pension and
retirement plan. This pension and retirement plan covers all PDVSA employees and mixed
companies employees. Petrodelta is not required to reimburse the pension costs to PDVSA until
PDVSA pays the pension benefits to employees. In May 2009, upon completion of the review of
this actuarial study, PDVSA sent a statement to Petrodelta for its respective costs associated with
the pension and retirement plan. Petrodelta recorded additional pension expense of $15.6 million
($5.0 million net to our 32 percent interest) in the three month period ended June 30, 2009 based
on the statement received. The pension adjustment resulted from the completion of the first full
actuary study by PDVSA related to its employees that provide services to the mixed companies
and a refinement of managements assumptions related to credit for past service costs covering
the period from January 2008, when the Harvest Vinccler employees were migrated to PDVSA
payroll, through May 2009. At this time PDVSA did not have specific benefit information
related to each individual mixed company and thus allocated the pension obligation to each
mixed company assuming that the employees serving each of the mixed companies had the same
characteristics. The pension adjustment was a change in Petrodelta managements estimate based
on the new information provided by PDVSA.
During the fourth quarter of 2009, PDVSA completed an updated actuarial study as of December
31, 2009. This study was based on a further refinement of assumptions for each of the mixed
companies, including Petrodelta and a new allocation methodology as PDVSA gathered during
2009 all relevant information for each of the mixed companies. The revised pension obligation
allocated to Petrodelta resulted in a decrease of $8.4 million ($2.7 million net to our 32 percent
interest) to the pension and retirement plan costs as compared to those previously recorded to
Petrodelta in May 2009. This change in managements estimate related to the pension and
retirement plan costs was recorded in December 2009. Pension costs at December 31, 2009
reasonably reflect Petrodeltas employee demographic and plan conditions. The additional
pension cost is not tax deductible until future periods when the pension is settled in cash. The
provision for the pension plan is subject to future revisions, both upwards and downwards, based
on changes in assumptions, the terms of the relevant plans, the allocation methodology or other prospective amendments or changes as determined by PDVSA.
In June 2009, CVP issued instructions to Petrodelta to set up a reserve within the equity
section of the balance sheet for deferred tax assets. Petrodeltas bylaws state that Petrodeltas
shareholders are required to approve the setting up of special reserves. In August 2009,
Petrodeltas board of directors approved the setting up of the reserve. Although this reserve has
no effect on Petrodeltas financial position, results of operation or cash flows, it has the effect
of limiting future dividends to net income adjusted for deferred tax assets. Past dividends
received from Petrodelta represented Petrodeltas net income as reported under IFRS. However,
Article 307 of the Venezuelan Commerce Code states that distributions and payments of dividends
must meet two conditions: 1) the retained earnings of the entity should be liquid and realizable,
and 2) the entity has enough cash to pay and distribute the dividend. Deferred taxes are not
liquid or realizable as cash until the items giving rise to the deferred tax are recognized in the
entitys tax return. Therefore, CVPs instructions are to ensure future dividends are declared and
paid as stated under Venezuelan law. Article 307 also states that shareholders are not obligated
to restore dividends that have been distributed in good faith according to the entitys balances
and sets the statute of limitations for an entity to claim restoration of dividends at five years.
In 2005, Venezuela modified the Science and Technology Law (referred to as LOCTI in
Venezuela) to require companies doing business in Venezuela to invest, contribute, or spend a
percentage of their gross revenue on projects to promote inventions or investigate technology in
areas deemed critical to Venezuela. LOCTI requires major corporations engaged in activities
covered by the Hydrocarbon and Gaseous Hydrocarbon Law (OHL) to contribute two percent of their
gross revenue generated in Venezuela from activities specified in the OHL. The contribution is
based on the previous 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 expects PDVSA to continue
requesting and receiving waivers, Petrodelta has not accrued a liability to LOCTI for the year
ended December 31, 2009. The potential exposure to LOCTI for the year ended December 31, 2009 is
$9.5 million, $4.8 million net of tax ($1.5 million net to our 32 percent interest).
Petrodeltas reporting and functional currency is the U.S. Dollar. HNR Finance owns a 40
percent interest in Petrodelta and recorded its share of the earnings of Petrodelta from April 1,
2006 to December 31, 2007 in the three months ended December 31, 2007. The years ended
December 31, 2009 and 2008 include net income from unconsolidated equity affiliates for Petrodelta
on a current basis. 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 December 31,
2009, 2008 and 2007, and for the years ended December 31, 2009, 2008 and 2007:
S-21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(in thousands) |
|
Barrels of oil sold |
|
|
7,835 |
|
|
|
5,505 |
|
|
|
5,374 |
|
MCF of gas sold |
|
|
4,397 |
|
|
|
10,700 |
|
|
|
13,456 |
|
Total Boe |
|
|
8,568 |
|
|
|
7,288 |
|
|
|
7,616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average price per barrel |
|
$ |
57.62 |
|
|
$ |
83.22 |
|
|
$ |
58.61 |
|
Average price per mcf |
|
$ |
1.54 |
|
|
$ |
1.54 |
|
|
$ |
1.54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
451,473 |
|
|
$ |
458,113 |
|
|
$ |
314,928 |
|
Gas sales |
|
|
6,778 |
|
|
|
16,506 |
|
|
|
20,789 |
|
Royalty |
|
|
(156,799 |
) |
|
|
(168,790 |
) |
|
|
(114,847 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
301,452 |
|
|
|
305,829 |
|
|
|
220,870 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
48,311 |
|
|
|
52,946 |
|
|
|
21,352 |
|
Workovers |
|
|
|
|
|
|
24,663 |
|
|
|
2,400 |
|
Depletion, depreciation and amortization |
|
|
33,666 |
|
|
|
25,509 |
|
|
|
18,549 |
|
General and administrative |
|
|
9,746 |
|
|
|
5,974 |
|
|
|
19,880 |
|
Windfall profits tax |
|
|
882 |
|
|
|
56,377 |
|
|
|
|
|
Taxes other than on income |
|
|
|
|
|
|
|
|
|
|
2,747 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
92,605 |
|
|
|
165,469 |
|
|
|
64,928 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Operations |
|
|
208,847 |
|
|
|
140,360 |
|
|
|
155,942 |
|
Interest expense |
|
|
(3,617 |
) |
|
|
(2,329 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before Income Tax |
|
|
205,230 |
|
|
|
138,031 |
|
|
|
155,942 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current income tax expense |
|
|
105,868 |
|
|
|
69,374 |
|
|
|
85,849 |
|
Deferred income tax benefit |
|
|
(43,922 |
) |
|
|
(52,560 |
) |
|
|
(21,348 |
) |
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
143,284 |
|
|
|
121,217 |
|
|
|
91,441 |
|
Adjustment to reconcile to reported Net Income from
Unconsolidated Equity Affiliate: |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax benefit |
|
|
38,516 |
|
|
|
34,827 |
|
|
|
12,343 |
|
|
|
|
|
|
|
|
|
|
|
Net Income Equity Affiliate |
|
|
104,768 |
|
|
|
86,390 |
|
|
|
79,098 |
|
Equity interest in unconsolidated equity affiliate |
|
|
40 |
% |
|
|
40 |
% |
|
|
40 |
% |
|
|
|
|
|
|
|
|
|
|
Income before amortization of excess basis in equity affiliate |
|
|
41,907 |
|
|
|
34,556 |
|
|
|
31,639 |
|
Amortization of excess basis in equity affiliate |
|
|
(1,356 |
) |
|
|
(1,155 |
) |
|
|
(2,530 |
) |
Conform depletion expense to GAAP |
|
|
183 |
|
|
|
2,533 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from unconsolidated equity affiliate |
|
$ |
40,734 |
|
|
$ |
35,934 |
|
|
$ |
29,109 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(in thousands) |
|
Current assets |
|
$ |
404,825 |
|
|
$ |
311,017 |
|
Property and equipment |
|
|
265,442 |
|
|
|
211,760 |
|
Other assets |
|
|
141,245 |
|
|
|
97,323 |
|
Current liabilities |
|
|
345,812 |
|
|
|
260,234 |
|
Other liabilities |
|
|
33,600 |
|
|
|
19,174 |
|
Net equity |
|
|
432,100 |
|
|
|
340,692 |
|
S-22
Fusion Geophysical, LLC (Fusion)
Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir
engineering. The purchase of Fusion extends our technical ability and global reach to support a
more organic growth and exploration strategy. Our 49 percent minority equity investment in Fusion
is accounted for using the equity method of accounting. In October 2008, we increased our minority
equity investment in Fusion from 45 percent to 49 percent for $2.2 million. Operating revenue and
total assets represent 100 percent of Fusion. No dividends were declared or paid during the years
ended December 31, 2009, 2008 and 2007, respectively. Summarized financial information for Fusion
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Operating Revenues |
|
$ |
11,089 |
|
|
$ |
13,063 |
|
|
$ |
7,392 |
|
Net Income (Loss) |
|
$ |
(4,798 |
) |
|
$ |
(1,290 |
) |
|
$ |
527 |
|
Equity interest in unconsolidated equity affiliate |
|
|
49 |
% |
|
|
49 |
% |
|
|
45 |
% |
|
|
|
|
|
|
|
|
|
|
Net income (loss) from unconsolidated equity affiliate |
|
|
(2,351 |
) |
|
|
(632 |
) |
|
|
237 |
|
Amortization of fair value of intangibles |
|
|
(995 |
) |
|
|
(726 |
) |
|
|
(656 |
) |
Impairment of investment |
|
|
(1,631 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from unconsolidated equity affiliate |
|
$ |
(4,977 |
) |
|
$ |
(1,358 |
) |
|
$ |
(419 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December, 31 |
|
|
|
2009 |
|
|
2008 |
|
Current assets |
|
$ |
2,726 |
|
|
$ |
7,864 |
|
Total assets |
|
|
30,205 |
|
|
|
30,633 |
|
Current liabilities |
|
|
8,024 |
|
|
|
7,294 |
|
Total liabilities |
|
|
12,242 |
|
|
|
8,281 |
|
Approximately 29 percent, 26 percent and 7 percent of Fusions revenue for the years ended
December 31, 2009, 2008 and 2007, respectively, was earned from Harvest or equity affiliates.
On April 9, 2009, we entered into a service agreement with Fusion whereby we prepaid $1.5
million for certain services to be performed in connection with certain projects as defined in the
service agreement. The services are to be performed in accordance with the existing consulting
agreement. Upon written notice to Fusion, the projects and types of services can be amended. The
unapplied portion of the prepayment advance bears interest at an annual rate of 12 percent which
will be added to the prepayment advance balance and used to offset future service invoices from
Fusion. Services rendered have been applied against the prepayment, and as of December 31, 2009,
the balance for prepaid services was approximately $1.0 million.
As of December 31, 2009, we updated the review for impairment of our minority equity
investment in Fusion. In preparing this update, future net cash flows prepared by Fusion based on
different business opportunities that Fusion is currently pursuing were updated for current
activities. These business opportunities were weighted with a probability of success. Based on
these cash flow projections and considering Fusions current liquidity, we concluded that the
potential business opportunities did not support Fusions on-going cash flow requirements; and
therefore, we recorded a $1.6 million charge to fully impair the carrying value of our equity
investment in Fusion at December 31, 2009.
Note 8 United States
During 2008, we initiated a domestic exploration program in two different basins. We are the
operator of both exploration programs and have complemented our existing personnel with the
addition of highly experienced management and technical personnel and with the acquisition of our
minority equity investment in Fusion.
S-23
Gulf Coast
In March 2008, we executed an AMI agreement with a private third party for an area in the
upper Gulf Coast Region of the United States. The AMI covers the coastal areas from Nueces County,
Texas to Cameron Parish, Louisiana, including state waters. We are the operator and have initial
working interests of 55 percent in Starks, the first prospect in the AMI, and 50 percent in West
Bay, the second prospect in the AMI. The private third party contributed these two prospects,
including the leases and proprietary 3-D seismic data sets, and numerous leads generated over the
last three decades of regional geological focus. We agreed to fund the first $20 million of new
lease acquisitions, geological and geophysical studies, seismic reprocessing and drilling costs.
At June 30, 2009, we had met the $20 million funding obligation under the terms of the AMI. All
costs incurred after June 30, 2009 are being shared by the parties in proportion to their working
interests as defined in the AMI. In August 2009, the AMI became a three party arrangement when the
private third party restructured and assigned a portion of its interest to one of its affiliates.
The private third party is obligated to evaluate and present additional opportunities at their
sole cost. As each prospect is accepted it will be covered by the AMI. Although several
additional potential prospects had been screened and evaluated within the AMI since its inception,
we had not pursued leasing or drilling on any new projects within the AMI as of December 31, 2009.
On January 29, 2010, we entered into an agreement with one of the private third parties in our AMI
for an option to participate in a new project (see Note 14 Subsequent Events).
Starks Project
We drilled an exploratory dry hole on the Starks prospect in 2008. In December 2009, we
wrote off the remaining carrying value of $0.7 million of the Starks prospect as we have no plans
for further activities relating to this prospect.
West Bay Project
During the year ended December 31, 2009, operational activities in the West Bay prospect
included the interpretation of 3-D seismic, site surveying, and preparation of engineering
documents. Interpretation of 3-D seismic data on the West Bay project was completed in 2009 and
resulted in the identification of a set of drilling leads and prospects for the project. On
July 14, 2009, we, along with our partner in the AMI, acquired 880 acres of shallow water offshore
bay leases representing two separate tracts from the State of Texas General Land Office at a state
lease sale for a total gross cost of $0.5 million. Acquisition of these two tracts completes the
planned land acquisition activities on the project.
The AMI participants are currently continuing to evaluate the leads and prospects to determine
priorities and drilling plans for the West Bay project and have identified the likely initial
drilling prospect. Land, regulatory, and surface access preparations are currently in progress
focused on taking the initial drilling prospect to drill-ready status. The West Bay project
represents $3.1 million and $2.9 million of unproved oil and gas properties on our December 31,
2009 and 2008 balance sheets, respectively.
Western United States Antelope
In October 2007, we entered into a JEDA with a private third party to pursue a lease
acquisition program and drilling program on the Antelope prospect in the Western United States. We
are the operator and had an initial working interest of 50 percent in the Antelope prospect. The
private third party is obligated to assemble the lease position on the Antelope prospect. The JEDA
provides that we would earn our initial 50 percent working interest in the Antelope prospect by
compensating the private third party for leases acquired in accordance with terms defined in the
JEDA, and by drilling and completing one deep natural gas test well (the Bar F) at our sole
expense. In November 2008, we entered into a Letter Agreement/Amendment of the JEDA (the Letter
Agreement) with the private third party. The Letter Agreement clarifies several open issues in
the JEDA, such as classification of $2.7 million of prepaid land costs for the Antelope prospect as
a note receivable, addition of a requirement for the private third party to partially assign leases
to us prior to meeting the lease earning obligation, and clarification of the private third partys
cost obligations for any shallow wells to be drilled on the Antelope prospect prior to the Bar F.
Per the Letter Agreement, payment of the $2.7 million note receivable was due from the private
third party on or by
S-24
spud date of the Bar F. Since payment was not received prior to the Bar F
spud date, our interest in the Antelope prospect was increased to 60 percent, with the incremental
10 percent working interest being earned by drilling and
completing the Bar F. The note receivable remains outstanding and will be collected through
sales revenues taken from a portion of the private third partys net revenue from the Bar F
provided the Bar F is commercial.
Activities are in progress on two separate projects on the Antelope prospect in Duchesne
County, Utah.
Mesaverde
The Mesaverde project is targeted to explore for and develop oil and natural gas from
multiple reservoir horizons in the Uintah Basin of northeastern Utah in Duchesne and Uintah
Counties. Leads and/or prospects were identified in three prospective reservoir horizons in
preparation for drilling.
Operational activities during 2009 on the Mesaverde project focused on continuing leasing
activities on private, Allottee, and tribal land, and surveying, preliminary engineering,
permitting preparations, and conducting drilling operations on a deep natural gas test well (the
Bar F) that commenced drilling on June 15, 2009. The Bar F was permitted to 18,000 feet. The Bar
F was drilled to a total depth of 17,566 feet and an extended production test of multiple potential
reservoir horizons is now in progress. To date, testing has been 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. Completion activities consisted of hydraulic fracturing of eight separate
reservoir intervals in the Mesaverde and multiple extended flow tests of the individual fractured
intervals, along with a flow test of the commingled eight intervals. While the results to date
have not definitively determined the commerciality of a stand-alone development of the Mesaverde,
we believe these results indicate progress toward that determination and that the Mesaverde
reservoir remains potentially prospective over a portion of our land position. The Mesaverde
project represents $36.4 million and $8.3 million of unproved oil and gas properties on our
December 31, 2009 and 2008 balance sheets, respectively.
Monument Butte
The Monument Butte project is an eight well appraisal and development drilling program to
produce oil and natural gas from the Green River formation on the southern portion of our Antelope
land position. The Monument Butte project is non-operated and we hold a 43 percent working
interest. The parties have formed a 320 acre AMI which contained the eight drilling locations.
Operational activities during 2009 on the Monument Butte project focused on resolution of
forced pooling issues with non-consenting interests, negotiations and finalization of an agreement
with the operator for the joint drilling operations. As of December 31, 2009, five wells had been
drilled: two of the five wells were on production, and three wells waiting on completion. These
three wells were placed on production in the first quarter 2010. The three additional wells were
drilled by the end of February 2010: two wells had been placed on production and the one remaining
well was waiting on completion operations. The Monument Butte project
represents $1.6 million of
proved oil and gas properties and $0.3 million of unproved oil and gas properties on our
December 31, 2009 and 2008 balance sheets, respectively.
Note 9 Indonesia
In 2008, we acquired a 47 percent interest in the Budong-Budong Production Sharing Contract
(Budong PSC) by committing to fund the first phase of the exploration program including the
acquisition of 2-D seismic and drilling of the first two exploration wells. This commitment is
capped at $17.2 million. The commitment is comprised of $6.5 million for the acquisition of
seismic and $10.7 million for the drilling of the first two exploratory wells. After the
commitment of each component is met, all subsequent costs will be shared by the parties in
proportion to their ownership interests. The $6.5 million carry obligation for the 2-D seismic
acquisition was met in December 2008. Prior to drilling the first exploration well, subject to the
estimated cost of that well, our partner will have a one-time option to increase the level of the
carried interest to a maximum of $20.0 million, and as compensation for the increase, we will
increase our participation to a maximum of 54.65 percent. This equates to a total carried cost for
the farm-in of $9.1 million. Our partner will be the operator through the exploration phase as
required by the terms of the Budong PSC. We will have control of major decisions and financing for
the project
S-25
with an option to become operator if approved by BP Migas, Indonesias oil and gas
regulatory authority, in the subsequent development and production phase.
The Budong PSC covers 1.35 million acres and includes the Lariang and Karama sub-basins which
are the eastern onshore extension of the West Sulawesi foldbelt (WSFB). Exploration to date in
the basin is immature due to previously difficult jungle terrain, which is now accessible with the
development of palm oil plantations and their related infrastructure. Field work performed over
the last 10 years, as outcrops have been more accessible, has given a new understanding to the
presence of Eocene source and reservoir potential that had not previously been recognized. Recent
seismic surveys have greatly improved the understanding of the geology and enhanced the
prospectivity of the offshore WSFB and, by analogy, the sparsely explored onshore area. The
Budong PSC includes a ten-year exploration period and a 20-year development phase. During the
initial three-year exploration phase, which began January 2007, operational activities during 2009
focused on the interpretation of 650 kilometers of 2-D seismic and well planning. Two drill sites
have been selected. Currently, the locations for the two test wells are being constructed and the
rig and ancillary equipment is being mobilized to the area. It is expected that the first of two
exploration wells will spud early in the second quarter of 2010. In accordance with the farm-in
agreement, we expect to fund 100 percent of the well expenditures to earn our 47 percent working
interest up to a cap of $10.7 million; thereafter, we will pay in proportion to our working
interest. The Budong PSC represents $2.0 million and $0.2 million, respectively, of unproved oil
and gas properties on our December 30, 2009 and 2008 balance sheets.
Note 10 Gabon
We are the operator of the Dussafu Marin Permit offshore Gabon in West Africa (Dussafu PSC)
with a 66.667 percent interest in the Dussafu PSC. Located offshore Gabon, adjacent to the border
with the Republic of Congo, the Dussafu PSC contains 680,000 acres with water depths up to 1,000
feet. The Dussafu PSC has two small oil discoveries in the Gamba and Dentale reservoirs and a
small natural gas discovery. Production and infrastructure exists in the blocks contiguous to the
Dussafu PSC.
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. The second
exploration phase comprises a three-year work commitment which includes the acquisition and
processing of 500 kilometers of 2-D seismic, geology and geophysical interpretation, engineering
studies and the drilling of a conditional well. Operational activities during 2009 focused on
completion of the processing and reprocessing of 1,330 kilometers of 2-D seismic and the pre-stack
depth reprocessing of 1,076 square kilometers of 3-D seismic data. The improved imaging from this
work has allowed the interpretation to mature the prospect inventory to provide the partnership a
number of prospective targets in the sub-salt section, in both the Gamba and Syn-rift plays that
are productive in the nearby Etame, Lucina and MBya fields. Subject to drilling rig availability,
we expect to drill an exploration well in the third quarter of 2010. The Dussafu PSC represents
$6.9 million and $5.9 million, respectively, of unproved oil and gas properties on our December 31,
2009 and 2008 balance sheets.
Note 11 Oman
On April 11, 2009, we signed an Exploration and Production Sharing Agreement (EPSA) with
Oman for the Al Ghubar / Qarn Alam license. 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.
Block 64 EPSA is a newly-created block designated for exploration and production of
non-associated gas and condensate which the Oman Ministry of Oil and Gas has carved out of the
Block 6 Concession operated by Petroleum Development of Oman (PDO). PDO will continue to produce
oil from several fields within Block 64 EPSA area. The 3,867 square kilometer (955,600 acres)
block is located in the gas and condensate rich Ghaba Salt Basin in close proximity to the Barik,
Saih Rawl and Saih Nihayda gas and condensate fields. We have an obligation to drill two wells
over a three year period with a funding commitment of $22.0 million. Current activities include
the compilation of existing data, over two prospect areas of approximately 1,000 square kilometers
and geological studies to determine drillable prospects. Well planning is expected to commence in
2010 for exploration
S-26
drilling in 2011. During the year ended December 31, 2009, we incurred $1.6
million for costs associated with negotiating Block 64 EPSA and $2.2 million for costs associated
with signing the license, including signature bonus and data compilation. The Block 64 EPSA
represents $3.8 million of unproved oil and gas properties on our December 31, 2009 balance sheet.
Note 12 China
In December 1996, we acquired a petroleum contract with China National Offshore Oil
Corporation (CNOOC) for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres
in the South China Sea, with an option for an additional 1.25 million acres under certain
circumstances, and lies within an area which is the subject of a border dispute between the
Peoples Republic of China (China) and Socialist Republic of Vietnam (Vietnam). Vietnam has
executed an agreement on a portion of the same offshore acreage with another company. The border
dispute has lasted for many years, and there has been limited exploration and no development
activity in the WAB-21 area due to the dispute. Due to the border dispute between China and
Vietnam, we have been unable to pursue an exploration program during Phase One of the contract. As
a result, we have obtained license extensions, with the current extension in effect until May 31,
2011. While no assurance can be given, we believe we will continue to receive contract extensions
so long as the border disputes persist. Recently, Vietnam, along with the company that is the
party to the agreement with Vietnam, announced plans for exploration drilling during 2010. While
no assurance can be given, we believe this announcement may provide some resolution with the border
disputes, although we do not know in what manner any resolution might appear. WAB-21 represents
$3.0 million of unproved oil and gas properties on our December 31, 2009 and 2008 balance sheets,
respectively.
Note 13 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. The
weighted average number of common shares outstanding for computing basic EPS was 33.1 million, 34.1
million and 36.5 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Diluted EPS reflects the potential dilution that could occur if securities or other contracts to
issue common stock were exercised or converted into common stock. The weighted average number of
common shares outstanding for computing diluted EPS, including dilutive stock options, was 33.1
million, 34.1 million and 37.9 million for the years ended December 31, 2009, 2008 and 2007,
respectively.
An aggregate of 3.7 million options were excluded from earnings per share calculations because
there exercise price exceeded the average price for the year ended December 31, 2009. An aggregate
of 4.0 million options were excluded from the earnings per share calculations because their
exercise price exceeded the average price for the year ended December 31, 2008. For the year ended
December 31, 2007, 1.1 million was excluded from the earnings per share calculations because their
exercise price exceeded the average price.
Note 14 Subsequent Events
We conducted our subsequent events review up through the date of the issuance of this Annual
Report on Form 10-K.
On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange
Agreement which establishes new exchange rates for the Bolivar/U.S. Dollar currencies that will
enter into force on January 11, 2010. Each exchange rate will be applied to foreign currency sales
and purchases conducted through the Foreign Currency Administration Commission (CADIVI), in the
cases expressly provided in the Exchange Agreement. In this regard, the exchange rates established
in the Agreement are: 2.60 Bolivars per U.S. Dollar and 4.30 Bolivars per U. S. Dollar. The 2.60
Bolivar exchange rate applies to the food, health, medical and technology sectors. The 4.30
Bolivar exchange rate applies to all other sectors not expressly established by the 2.60 Bolivar
exchange rate. The U.S. Dollar is the functional reporting currency
for both Petrodelta and Harvest Vinccler.
S-27
On January 28, 2010, we entered into an agreement with one of the private third parties in our
AMI for an option to participate in a new project. We paid $1.5 million for the option to acquire
up to a 50 percent interest in the new project. If we exercise our option to participate, we will
participate in this project with essentially the same terms as the other existing projects in the
AMI. The option to participate expires on June 1, 2010.
On February 17, 2010, we closed an offering of $32 million in aggregate principal amount of
our 8.25 percent senior convertible notes due 2013, which resulted in net proceeds to us, after
deducting underwriting discounts, commissions and estimated offering expenses, of approximately $30
million.
S-28
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Quarterly Financial Data (unaudited)
Summarized quarterly financial data is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended |
|
|
|
March 31 |
|
|
June 30 |
|
|
September 30 |
|
|
December 31 |
|
|
|
(amounts in thousands, except per share data) |
|
Year ended December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
181 |
|
Expenses |
|
|
(7,825 |
) |
|
|
(10,217 |
) |
|
|
(7,286 |
) |
|
|
(5,812 |
) |
Non-operating income |
|
|
331 |
|
|
|
296 |
|
|
|
224 |
|
|
|
229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from consolidated companies before income taxes |
|
|
(7,494 |
) |
|
|
(9,921 |
) |
|
|
(7,062 |
) |
|
|
(5,402 |
) |
Income tax expense |
|
|
889 |
|
|
|
147 |
|
|
|
109 |
|
|
|
37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from consolidated companies |
|
|
(8,383 |
) |
|
|
(10,068 |
) |
|
|
(7,171 |
) |
|
|
(5,439 |
) |
Net income from unconsolidated equity affiliates |
|
|
4,410 |
|
|
|
7,476 |
|
|
|
9,890 |
|
|
|
13,981 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
(3,973 |
) |
|
|
(2,592 |
) |
|
|
2,719 |
|
|
|
8,542 |
|
Less: Net income attributable to noncontrolling interest |
|
|
803 |
|
|
|
1,597 |
|
|
|
1,936 |
|
|
|
3,467 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Harvest |
|
$ |
(4,776 |
) |
|
$ |
(4,189 |
) |
|
$ |
783 |
|
|
$ |
5,075 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Harvest per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.15 |
) |
|
$ |
(0.13 |
) |
|
$ |
0.02 |
|
|
$ |
0.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(0.15 |
) |
|
$ |
(0.13 |
) |
|
$ |
0.02 |
|
|
$ |
0.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended |
|
|
|
March 31 |
|
|
June 30 |
|
|
September 30 |
|
|
December 31 |
|
|
|
(amounts in thousands, except per share data) |
|
Year ended December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
$ |
(7,869 |
) |
|
$ |
(9,530 |
) |
|
$ |
(10,621 |
) |
|
$ |
(26,420 |
) |
Non-operating income (expense) |
|
|
2,002 |
|
|
|
1,582 |
|
|
|
1,100 |
|
|
|
670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from consolidated companies before income taxes |
|
|
(5,867 |
) |
|
|
(7,948 |
) |
|
|
(9,521 |
) |
|
|
(25,750 |
) |
Income tax expense (benefit) |
|
|
64 |
|
|
|
37 |
|
|
|
(20 |
) |
|
|
(56 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from consolidated companies |
|
|
(5,931 |
) |
|
|
(7,985 |
) |
|
|
(9,501 |
) |
|
|
(25,694 |
) |
Net income from unconsolidated equity affiliates |
|
|
8,809 |
|
|
|
9,409 |
|
|
|
5,309 |
|
|
|
11,049 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
2,878 |
|
|
|
1,424 |
|
|
|
(4,192 |
) |
|
|
(14,645 |
) |
Less: Net income attributable to noncontrolling interest |
|
|
1,673 |
|
|
|
2,057 |
|
|
|
1,045 |
|
|
|
2,154 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Harvest |
|
$ |
1,205 |
|
|
$ |
(633 |
) |
|
$ |
(5,237 |
) |
|
$ |
(16,799 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Harvest per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.03 |
|
|
$ |
(0.02 |
) |
|
$ |
(0.16 |
) |
|
$ |
(0.51 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.03 |
|
|
$ |
(0.02 |
) |
|
$ |
(0.16 |
) |
|
$ |
(0.51 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)
The following tables summarize our proved reserves, drilling and production activity, and
financial operating data at the end of each year. Tables I through III provide historical cost
information pertaining to costs incurred in exploration, property acquisitions and development;
capitalized costs; and results of operations. Tables IV through VI present information on our
estimated proved reserve quantities, standardized measure of estimated discounted future net cash
flows related to proved reserves, and changes in estimated discounted future net cash flows.
S-29
|
|
|
TABLE I |
|
Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
Oman |
|
|
Gabon |
|
|
Indonesia |
|
|
and Other |
|
|
Total |
|
Year Ended December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs |
|
$ |
3,757 |
|
|
$ |
941 |
|
|
$ |
1,800 |
|
|
$ |
28,170 |
|
|
$ |
34,668 |
|
Exploration costs |
|
|
459 |
|
|
|
225 |
|
|
|
1,793 |
|
|
|
2,563 |
|
|
|
5,040 |
|
Development costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,547 |
|
|
|
1,547 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,216 |
|
|
$ |
1,166 |
|
|
$ |
3,593 |
|
|
$ |
32,280 |
|
|
$ |
41,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs |
|
$ |
|
|
|
$ |
5,792 |
|
|
$ |
71 |
|
|
$ |
13,302 |
|
|
$ |
19,165 |
|
Exploration costs |
|
|
|
|
|
|
3,016 |
|
|
|
7,647 |
|
|
|
14,020 |
|
|
|
24,683 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
$ |
8,808 |
|
|
$ |
7,718 |
|
|
$ |
27,322 |
|
|
$ |
43,848 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs |
|
$ |
|
|
|
$ |
136 |
|
|
$ |
168 |
|
|
$ |
160 |
|
|
$ |
464 |
|
Exploration costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
204 |
|
|
|
204 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
$ |
136 |
|
|
$ |
168 |
|
|
$ |
364 |
|
|
$ |
668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TABLE II |
|
Capitalized costs related to oil and natural gas producing activities (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
Oman |
|
|
Gabon |
|
|
Indonesia |
|
|
and Other |
|
|
Total |
|
Year Ended December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved property costs |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,646 |
|
|
$ |
1,646 |
|
Unproved property costs |
|
|
3,757 |
|
|
|
6,869 |
|
|
|
670 |
|
|
|
42,815 |
|
|
|
54,111 |
|
Oilfield Inventories |
|
|
|
|
|
|
|
|
|
|
1,369 |
|
|
|
1,417 |
|
|
|
2,786 |
|
Less accumulated depletion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29 |
) |
|
|
(29 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,757 |
|
|
$ |
6,869 |
|
|
$ |
2,039 |
|
|
$ |
45,849 |
|
|
$ |
58,514 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved property costs |
|
$ |
|
|
|
$ |
5,927 |
|
|
$ |
239 |
|
|
$ |
16,162 |
|
|
$ |
22,328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved property costs |
|
$ |
|
|
|
$ |
136 |
|
|
$ |
168 |
|
|
$ |
2,859 |
|
|
$ |
3,163 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We regularly evaluate our unproved properties to determine whether impairment has occurred.
We have excluded from amortization our interest in unproved properties and the cost of uncompleted
exploratory activities. The principal portion of such costs, excluding those related the
acquisition of WAB-21, are expected to be included in amortizable costs during the next two to
three years. The ultimate timing of when the costs related to the acquisition of WAB-21 will be
included in amortizable costs is uncertain.
Unproved property costs at December 31, 2009 consisted of the following by year incurred (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
Prior |
|
Property acquisition costs |
|
$ |
56,897 |
|
|
$ |
34,569 |
|
|
$ |
19,165 |
|
|
$ |
263 |
|
|
$ |
2,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S-30
|
|
|
TABLE III |
|
Results of operations for oil and natural gas producing activities (in thousands): |
|
|
|
|
|
|
|
United States |
|
Year Ended December 31, 2009 |
|
|
|
|
Revenues: |
|
|
|
|
Oil and natural gas revenues |
|
$ |
181 |
|
|
|
|
|
|
Expenses: |
|
|
|
|
Operating, selling, and distribution expenses and taxes
other than on income |
|
|
15 |
|
Depletion |
|
|
29 |
|
Income Tax expense |
|
|
|
|
|
|
|
|
Total expenses |
|
|
44 |
|
|
|
|
|
Results of operations from oil and natural gas producing activities |
|
$ |
137 |
|
|
|
|
|
|
|
|
TABLE IV |
|
Quantities of Oil and Natural Gas Reserves |
Estimating oil and gas reserves is a very complex process requiring significant subjective
decisions in the evaluation of all available geological, engineering and economic data for each
reservoir. This data may change substantially over time as a result of numerous factors such as
production history, additional development activity and continual reassessment of the viability of
production under various economic and political conditions. Consequently, material upward or
downward revisions to existing reserve estimates may occur from time to time; although, every
reasonable efforts is made to ensure that reported results are the most accurate assessment
available. We ensure that the data provided to our external independent experts, and their
interpretation of that data, corresponds with our development plans and managements assessment of
each reservoir. The significance of subjective decisions required and variances in available data
make estimates generally less precise than other estimates presented in connection with financial
statement disclosures.
In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which
is effective for reporting 2009 reserve information. In January 2010, the FASB issued its
authoritative guidance on extractive activities for oil and gas to align its requirements with the
SECs final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end
reserve report as a change in accounting principle that is inseparable from a change in accounting
estimate. Under the SECs final rule, prior period reserves were not restated. For the United
States, the primary impacts of the SECs final rule on our reserve estimates include:
|
|
|
The use of the unweighted 12-month average of the first-day-of-the-month reference price
of $48.21 per barrel for oil compared to year-end reference price of $61.73 per barrel, and |
|
|
|
|
The use of the unweighted 12-month average of the first-day-of-the-month reference price
of $3.31 per Mcf for gas compared to year-end reference price of $4.25 per Mcf. |
The impact of the adoption of the SECs final rule on our financial statements is not
practicable to estimate due to the operational and technical challenges associated with calculating
a cumulative effect of adoption by preparing reserve reports under both the old and new rules.
The process for preparation of our oil and gas reserves estimates is completed in accordance
with our prescribed internal control procedures, which include verification of data provided for,
management reviews and review of the independent third party reserves report. The technical
employee responsible for overseeing the process for preparation of the reserves estimates has a
Bachelor of Arts in Engineering Science, a Master of Science in Petroleum Engineering, has more
than 25 years of experience in reservoir engineering and is a member of the Society of Petroleum
Engineers.
All reserve information in this report is based on estimates prepared by Ryder Scott Company
L.P. (Ryder Scott), independent petroleum engineers. The technical personnel responsible for
preparing the reserve estimates at Ryder Scott meet the requirements regarding qualifications,
independence, objectivity and confidentiality set forth in the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserves Information promulgated
S-31
by the Society of Petroleum
Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not
employed on a contingent fee basis.
Reserves for Petrodelta are reflected in the following section Additional Supplemental
Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela Equity Affiliate
as of December 31, 2009, 2008 and 2007, TABLE IV Quantities of Oil and Natural Gas Reserves.
The table shown below represents our interests in the United States. All of our other
properties are unproved and have no associated reserves. There were no reserves prior to December
31, 2009 and all amounts are reflected as discoveries. During 2009, we identified and approved the
development of eight locations in the Monument Butte project in Utah. At year end 2009, we have
drilled and moved to the proved developed category three of these locations. At year end 2009, we
have five identified proved undeveloped (PUD) locations. All PUD locations have subsequently
been converted to proved developed (PDP) locations or are scheduled to be converted to PDP
locations by the end of the first quarter 2010. These reserves are in a new geographic area for
us.
|
|
|
|
|
|
|
|
|
|
|
As of |
|
|
|
December 31, 2009 |
|
|
|
Oil |
|
|
Gas |
|
|
|
(MBbls) |
|
|
(MMcf) |
|
|
|
(in thousands) |
|
Proved |
|
|
|
|
|
|
|
|
Developed |
|
|
|
|
|
|
|
|
United States |
|
|
131 |
|
|
|
653 |
|
|
|
|
|
|
|
|
|
|
Undeveloped |
|
|
|
|
|
|
|
|
United States |
|
|
95 |
|
|
|
473 |
|
|
|
|
|
|
|
|
Total Proved |
|
|
226 |
|
|
|
1,126 |
|
|
|
|
|
|
|
|
|
|
|
TABLE V |
|
Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve
Quantities |
The standardized measure of discounted future net cash flows is presented in accordance with
the provisions of the accounting standard on disclosures about oil and gas producing activities.
In preparing this data, assumptions and estimates have been used, and we caution against viewing
this information as a forecast of future economic conditions.
Future cash inflows were estimated by an applying the average price during the 12-month
period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each
month within such period, adjusted for fixed and determinable escalations provided by the contract,
to the estimated future production of year-end proved reserves. Our average prices used were
$48.21 per barrel for oil and $3.31 per Mcf for gas. Future cash inflows were reduced by estimated
future production and development costs to determine pre-tax cash inflows. Future income taxes
were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows,
less the tax basis of the properties involved, and adjusted for permanent differences and tax
credits and allowances. The resultant future net cash inflows are discounted using a ten percent
discount rate.
The table shown below represents our net interest at December 31, 2009. This is the first
year to report our reserves in the United States, based on the results of Ryder Scott Company L.P.
S-32
|
|
|
|
|
|
|
United States |
|
|
|
(in thousands) |
|
December 31, 2009 |
|
|
|
|
Future cash inflows from sales of oil and gas |
|
$ |
14,626 |
|
Future production costs |
|
|
(3,674 |
) |
Future development costs |
|
|
(1,171 |
) |
Future income tax expenses |
|
|
(3,147 |
) |
|
|
|
|
Future net cash flows |
|
|
6,634 |
|
Effect of discounting net cash flows at 10% |
|
|
(1,911 |
) |
|
|
|
|
Standardized measure of discounted future
net cash flows |
|
$ |
4,723 |
|
|
|
|
|
|
|
|
TABLE VI |
|
Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved
Reserves (in thousands): |
|
|
|
|
|
|
|
United States |
|
Standardized Measure at January 1 |
|
$ |
|
|
Sales of oil and natural gas, net of related costs |
|
|
(166 |
) |
Extensions, discoveries and improved recovery, net of future costs |
|
|
6,978 |
|
Net change in income taxes |
|
|
(2,089 |
) |
|
|
|
|
Standardized Measure at December 31 |
|
$ |
4,723 |
|
|
|
|
|
|
|
|
|
|
S-33
Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)
for Petrodelta S.A. as of December 31, 2009, 2008 and 2007
The following tables summarize our proved reserves, drilling and production activity, and
financial operating data at the end of each year. Tables I through III provide historical cost
information pertaining to costs incurred in exploration, property acquisitions and development;
capitalized costs; and results of operations. Tables IV through VI present information on our
estimated proved reserve quantities, standardized measure of estimated discounted future net cash
flows related to proved reserves, and changes in estimated discounted future net cash flows.
Petrodelta (32 percent ownership) is accounted for under the equity method, and has been
included at its ownership interest in the consolidated financial statements and the following
Tables based on a year ending December 31 and, accordingly, results of operations for oil and
natural gas producing activities in Venezuela reflect the year ended December 31, 2009, 2008 and
2007.
|
|
|
TABLE I |
|
Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Development costs |
|
$ |
26,605 |
|
|
$ |
17,144 |
|
|
$ |
972 |
|
Exploration costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,605 |
|
|
$ |
17,744 |
|
|
$ |
972 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TABLE II |
|
Capitalized costs related to oil and natural gas producing activities (in
thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Proved property costs |
|
$ |
108,696 |
|
|
$ |
79,807 |
|
|
$ |
64,415 |
|
Unproved property costs |
|
|
163 |
|
|
|
3,036 |
|
|
|
2,653 |
|
Oilfield inventories |
|
|
10,748 |
|
|
|
7,892 |
|
|
|
4,426 |
|
Less accumulated depletion and impairment |
|
|
(27,089 |
) |
|
|
(16,966 |
) |
|
|
(11,063 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
92,518 |
|
|
$ |
73,769 |
|
|
$ |
60,431 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TABLE III |
|
Results of operations for oil and natural gas producing activities (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
146,640 |
|
|
$ |
151,878 |
|
|
$ |
107,429 |
|
Royalty |
|
|
(50,176 |
) |
|
|
(54,013 |
) |
|
|
(36,751 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
96,464 |
|
|
|
97,865 |
|
|
|
70,678 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating, selling and distribution expenses and taxes
other than on income |
|
|
15,742 |
|
|
|
42,876 |
|
|
|
7,601 |
|
Depletion |
|
|
10,123 |
|
|
|
5,903 |
|
|
|
5,746 |
|
Income tax expense |
|
|
35,300 |
|
|
|
23,530 |
|
|
|
28,666 |
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
61,165 |
|
|
|
72,309 |
|
|
|
42,013 |
|
|
|
|
|
|
|
|
|
|
|
Results of operations from oil and natural gas
producing activities |
|
$ |
35,299 |
|
|
$ |
25,556 |
|
|
$ |
28,665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TABLE IV |
|
Quantities of Oil and Natural Gas Reserves |
In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which
is effective for reporting 2009 reserve information. In January 2010, the FASB issued its
authoritative guidance on extractive activities for oil and gas to align its requirements with the
SECs final rule. We adopted the guidance as
S-34
of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting
principle that is inseparable from a change in accounting estimate. Under the SECs final rule,
prior period reserves were not restated. For Petrodelta, the primary impact of the SECs final
rule on our reserve estimates include:
|
|
|
The use of the unweighted 12-month average of the first-day-of-the-month contracted
reference price of $56.83 per barrel for oil compared to the year-end contracted reference
price of $69.87 per barrel for oil. |
Petrodelta is producing from, and continuing to develop, the Petrodelta Fields. Petrodelta
has both developed and undeveloped oil and gas reserves identified in all six fields. Petrodelta
produces the fields in accordance with a business plan defined by its conversion contract executed
in late 2007. Proved Undeveloped (PUD) oil and gas reserves are drilled in accordance with
Petrodeltas business plan, but can be revised where drilling results indicate a change is
warranted. This was the case when two wells drilled in El Salto in 2009 justified a modification
to the El Salto PUD program.
As of year end 2009, Petrodelta has a total of 164 PUD (39,626 Boe) locations identified. Since the
implementation of its business plan, Petrodelta has drilled 24 gross wells (2008 nine wells [1,743 Boe] and
2009 15 wells [2,498 Boe]) which have moved to the proved developed producing (PDP) category. Of these 24
locations, 17 (3,511 Boe) represent the movements of PUD locations to PDP locations. The other seven new
producing wells (731 Boe) were previously classified Probable, Possible or un-defined. All above Boe represent HNR Finances interest, net of a 33.33 percent royalty.
All PUD locations are scheduled to be drilled by 2014; however, there are some PUD locations
that are scheduled to be drilled in the sixth year after the PUD locations were first identified.
Petrodelta has a track record of identifying, executing and converting its PUD locations to PDP
locations, and there are special circumstances to account for this drilling delay. Petrodelta
commenced drilling operations in the second quarter of 2008; however, shortly thereafter Petrodelta
was advised by the Venezuelan government that Petrodeltas 2009 production target was to be
approximately 16,000 barrels of oil per day following the December 17, 2008 Organization of the
Petroleum Exporting Countries (OPEC) meeting establishing new production quotas. Subsequently,
Petrodelta was allowed to produce at capacity to help fulfill other companies production
shortfalls. Also, PDVSA has failed to pay on a timely basis certain amounts owed to contractors
that PDVSA has contracted to do work for Petrodelta. As a result, Petrodelta has experienced
difficulty in retaining contractors who provide equipment and/or services for Petrodeltas
operations. Inability to retain contractors or to pay them on a timely basis is having an adverse
effect on Petrodeltas ability to carry out its business plan. These events have been outside of
the control of Petrodelta. Petrodelta has recently taken specific actions to improve its ability
to execute on its established business plan in a timely manner.
In summary, Petrodelta has a demonstrated track record of identifying, executing and
converting its PUD locations to PDP locations. PUD locations are expected to be drilled at a
similar pace with 27 wells drilled in 2010 and an average 36 wells per year in 2011 through 2014.
The tables shown below represent HNR Finances interest, net of a 33.33 percent royalty, in
Venezuela in each of the years.
S-35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority |
|
|
|
|
|
|
|
|
|
|
Interest in |
|
|
32% |
|
|
|
HNR Finance |
|
|
Venezuela |
|
|
Net Total |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Proved Reserves-Crude oil, condensate,
and natural gas liquids (MBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1, 2009 |
|
|
42,809 |
|
|
|
(8,561 |
) |
|
|
34,248 |
|
Revisions |
|
|
(875 |
) |
|
|
175 |
|
|
|
(700 |
) |
Extensions |
|
|
7,574 |
|
|
|
(1,515 |
) |
|
|
6,059 |
|
Production |
|
|
(2,089 |
) |
|
|
418 |
|
|
|
(1,671 |
) |
|
|
|
|
|
|
|
|
|
|
Proved Reserves at end of the year |
|
|
47,419 |
|
|
|
(9,483 |
) |
|
|
37,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009
Proved |
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
14,242 |
|
|
|
(2,848 |
) |
|
|
11,394 |
|
Undeveloped |
|
|
33,177 |
|
|
|
(6,635 |
) |
|
|
26,542 |
|
|
|
|
|
|
|
|
|
|
|
Total Proved |
|
|
47,419 |
|
|
|
(9,483 |
) |
|
|
37,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1, 2008 |
|
|
47,261 |
|
|
|
(9,452 |
) |
|
|
37,809 |
|
Revisions |
|
|
(2,984 |
) |
|
|
597 |
|
|
|
(2,387 |
) |
Production |
|
|
(1,468 |
) |
|
|
294 |
|
|
|
(1,174 |
) |
|
|
|
|
|
|
|
|
|
|
Proved Reserves at end of the year |
|
|
42,809 |
|
|
|
(8,561 |
) |
|
|
34,248 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves-Crude oil, condensate,
and natural gas liquids (MBbls) at: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
13,415 |
|
|
|
(2,683 |
) |
|
|
10,732 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
Additions(a) |
|
|
50,085 |
|
|
|
(10,017 |
) |
|
|
40,068 |
|
Production |
|
|
(2,824 |
) |
|
|
565 |
|
|
|
(2,259 |
) |
|
|
|
|
|
|
|
|
|
|
Proved Reserves at end of the year |
|
|
47,261 |
|
|
|
(9,452 |
) |
|
|
37,809 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Petrodelta was formed in 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves-Crude oil, condensate,
and natural gas liquids (MBbls) at: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
14,779 |
|
|
|
(2,956 |
) |
|
|
11,823 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves-Natural gas (MMcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1, 2009 |
|
|
67,804 |
|
|
|
(13,561 |
) |
|
|
54,243 |
|
Revisions |
|
|
(5,862 |
) |
|
|
1,172 |
|
|
|
(4,690 |
) |
Extensions |
|
|
1,941 |
|
|
|
(388 |
) |
|
|
1,553 |
|
Production |
|
|
(1,173 |
) |
|
|
235 |
|
|
|
(938 |
) |
|
|
|
|
|
|
|
|
|
|
Proved Reserves at end of the year |
|
|
62,710 |
|
|
|
(12,542 |
) |
|
|
50,168 |
|
|
|
|
|
|
|
|
|
|
|
S-36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority |
|
|
|
|
|
|
|
|
|
|
Interest in |
|
|
32% |
|
|
|
HNR Finance |
|
|
Venezuela |
|
|
Net Total |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
As of December 31, 2009
Proved |
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
24,015 |
|
|
|
(4,803 |
) |
|
|
19,212 |
|
Undeveloped |
|
|
38,695 |
|
|
|
(7,739 |
) |
|
|
30,956 |
|
|
|
|
|
|
|
|
|
|
|
Total Proved |
|
|
62,710 |
|
|
|
(12,542 |
) |
|
|
50,168 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1, 2008 |
|
|
43,084 |
|
|
|
(8,617 |
) |
|
|
34,467 |
|
Additions |
|
|
27,574 |
|
|
|
(5,515 |
) |
|
|
22,059 |
|
Production |
|
|
(2,854 |
) |
|
|
571 |
|
|
|
(2,283 |
) |
|
|
|
|
|
|
|
|
|
|
Proved Reserves at end of the year |
|
|
67,804 |
|
|
|
(13,561 |
) |
|
|
54,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves-Natural gas (MMcf) at: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
30,168 |
|
|
|
(6,034 |
) |
|
|
24,134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
Additions(a) |
|
|
50,019 |
|
|
|
(10,004 |
) |
|
|
40,015 |
|
Production |
|
|
(6,935 |
) |
|
|
1,387 |
|
|
|
(5,548 |
) |
|
|
|
|
|
|
|
|
|
|
Proved Reserves at end of the year |
|
|
43,084 |
|
|
|
(8,617 |
) |
|
|
34,467 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Petrodelta was formed in 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves-Natural gas (MMcf) at: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
7,755 |
|
|
|
(1,551 |
) |
|
|
6,204 |
|
|
|
|
TABLE V |
|
Standardized Measure of Discounted Future Net
Cash Flows Related to Proved Oil and Natural Gas
Reserve Quantities |
The standardized measure of discounted future net cash flows is presented in accordance with
the provisions of the accounting standard on disclosures about oil and gas producing activities.
In preparing this data, assumptions and estimates have been used, and we caution against viewing
this information as a forecast of future economic conditions.
Future cash inflows were estimated by an applying the average price during the 12-month
period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each
month within such period, adjusted for fixed and determinable escalations provided by the contract,
to the estimated future production of year-end proved reserves. Our average prices used were
$56.83 per barrel for oil and $1.54 per Mcf for gas. Future cash inflows were reduced by estimated
future production and development costs to determine pre-tax cash inflows. Future income taxes
were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows,
less the tax basis of the properties involved, and adjusted for permanent differences and tax
credits and allowances. The resultant future net cash inflows are discounted using a ten percent
discount rate.
The table shown below represents HNR Finances net interest in Petrodelta.
S-37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority |
|
|
|
|
|
|
|
|
|
|
Interest in |
|
|
|
|
|
|
HNR Finance |
|
|
Venezuela |
|
|
Net Total |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows from sales of oil and gas |
|
$ |
2,772,840 |
|
|
$ |
(554,568 |
) |
|
$ |
2,218,272 |
|
Future production costs |
|
|
(630,225 |
) |
|
|
126,045 |
|
|
|
(504,180 |
) |
Future development costs |
|
|
(282,306 |
) |
|
|
56,461 |
|
|
|
(225,845 |
) |
Future income tax expenses |
|
|
(886,622 |
) |
|
|
177,324 |
|
|
|
(709,298 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
973,687 |
|
|
|
(194,738 |
) |
|
|
778,949 |
|
Effect of discounting net cash flows at 10% |
|
|
(473,317 |
) |
|
|
94,663 |
|
|
|
(378,654 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future
net cash flows |
|
$ |
500,370 |
|
|
$ |
(100,075 |
) |
|
$ |
400,295 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows from sales of oil and gas |
|
$ |
1,576,312 |
|
|
$ |
(315,262 |
) |
|
$ |
1,261,050 |
|
Future production costs |
|
|
(557,043 |
) |
|
|
111,409 |
|
|
|
(445,634 |
) |
Future development costs |
|
|
(306,500 |
) |
|
|
61,300 |
|
|
|
(245,200 |
) |
Future income tax expenses |
|
|
(355,746 |
) |
|
|
71,149 |
|
|
|
(284,597 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
357,023 |
|
|
|
(71,404 |
) |
|
|
285,619 |
|
Effect of discounting net cash flows at 10% |
|
|
(217,822 |
) |
|
|
43,564 |
|
|
|
(174,258 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future
net cash flows |
|
$ |
139,201 |
|
|
$ |
(27,840 |
) |
|
$ |
111,361 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows from sales of oil and gas |
|
$ |
3,650,110 |
|
|
$ |
(730,022 |
) |
|
$ |
2,920,088 |
|
Future production costs |
|
|
(685,368 |
) |
|
|
137,074 |
|
|
|
(548,294 |
) |
Future development costs |
|
|
(358,759 |
) |
|
|
71,752 |
|
|
|
(287,007 |
) |
Future income tax expenses |
|
|
(1,274,005 |
) |
|
|
254,801 |
|
|
|
(1,019,204 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
1,331,978 |
|
|
|
(266,395 |
) |
|
|
1,065,583 |
|
Effect of discounting net cash flows at 10% |
|
|
(677,756 |
) |
|
|
135,551 |
|
|
|
(542,205 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future
net cash flows |
|
$ |
654,222 |
|
|
$ |
(130,844 |
) |
|
$ |
523,378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
TABLE VI Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
Net Venezuela |
|
|
|
2009 |
|
|
2008 |
|
Standardized Measure at January 1 |
|
$ |
111,361 |
|
|
$ |
523,378 |
|
Sales of oil and natural gas, net of related costs |
|
|
(80,725 |
) |
|
|
(54,988 |
) |
Revisions to estimates of proved reserves |
|
|
|
|
|
|
|
|
Net changes in prices, development and production costs |
|
|
408,054 |
|
|
|
(673,320 |
) |
Quantities |
|
|
(25,424 |
) |
|
|
(119,678 |
) |
Extensions, discoveries and improved recovery, net of future costs |
|
|
187,636 |
|
|
|
50,515 |
|
Accretion of discount |
|
|
24,940 |
|
|
|
106,481 |
|
Net change in income taxes |
|
|
(262,214 |
) |
|
|
457,582 |
|
Development costs incurred |
|
|
26,756 |
|
|
|
7,791 |
|
Changes in estimated development costs |
|
|
(429 |
) |
|
|
13,128 |
|
Timing differences and other |
|
|
10,340 |
|
|
|
(199,528 |
) |
|
|
|
|
|
|
|
Standardized Measure at December 31 |
|
$ |
400,295 |
|
|
$ |
111,361 |
|
|
|
|
|
|
|
|
S-38
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
(Registrant)
|
|
Date: March 16, 2010 |
By: |
/s/ James A. Edmiston
|
|
|
|
James A. Edmiston |
|
|
|
Chief Executive Officer |
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has
been signed by the following persons on the 16th day of March, 2010, on behalf of
the registrant and in the capacities indicated:
|
|
|
|
|
Signature |
|
|
|
Title |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director, President and Chief
Executive Officer |
James A. Edmiston
|
|
|
|
(Principal Executive Officer) |
|
|
|
|
|
/s/ Stephen C. Haynes
Stephen C. Haynes
|
|
|
|
Vice President Finance,
Chief Financial Officer
and Treasurer (Principal Financial Officer and Principal Accounting Officer) |
|
|
|
|
|
/s/ Stephen D. Chesebro
Stephen D. Chesebro
|
|
|
|
Chairman of the Board and Director |
|
|
|
|
|
/s/ Igor Effimoff
Igor Effimoff
|
|
|
|
Director |
|
|
|
|
|
/s/ H. H. Hardee
H. H. Hardee
|
|
|
|
Director |
|
|
|
|
|
/s/ R. E. Irelan
R. E. Irelan
|
|
|
|
Director |
|
|
|
|
|
/s/ Patrick M. Murray
Patrick M. Murray
|
|
|
|
Director |
|
|
|
|
|
/s/ J. Michael Stinson
J. Michael Stinson
|
|
|
|
Director |
S-39
SCHEDULE II
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
|
Balance at |
|
|
|
|
|
|
Charged to Other |
|
|
Deductions From |
|
|
Balance at End of |
|
|
|
Beginning of Year |
|
|
Charged to Income |
|
|
Accounts |
|
|
Reserves |
|
|
Year |
|
At December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts deducted from applicable assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
$ |
2,757 |
|
|
$ |
|
|
|
$ |
2,757 |
|
|
$ |
|
|
|
$ |
|
|
Deferred tax valuation allowance |
|
|
7,841 |
|
|
|
9,184 |
|
|
|
|
|
|
|
|
|
|
|
17,025 |
|
Investment at cost |
|
|
1,350 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,350 |
|
At December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts deducted from applicable assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
$ |
2,757 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2,757 |
|
Deferred tax valuation allowance |
|
|
1,782 |
|
|
|
6,059 |
|
|
|
|
|
|
|
|
|
|
|
7,841 |
|
Investment at cost |
|
|
1,350 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,350 |
|
At December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts deducted from applicable assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
$ |
2,757 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2,757 |
|
Deferred tax valuation allowance |
|
|
33,704 |
|
|
|
(31,922 |
) |
|
|
|
|
|
|
|
|
|
|
1,782 |
|
Investment at cost |
|
|
1,350 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,350 |
|
S-40
SCHEDULE III
Financial Statements and Notes
for Petrodelta, S.A.
S-41
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Financial Statements at December 31, 2009 and 2008
and Independent Auditors Report
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Index
|
|
|
|
|
|
|
Pages |
|
|
|
|
1 - 2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
4 |
|
|
|
|
5 |
|
|
|
|
6 |
|
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8 |
|
|
|
|
10 |
|
|
|
|
12 |
|
|
|
|
22 |
|
|
|
|
22 |
|
|
|
|
23 |
|
|
|
|
24 |
|
|
|
|
29 |
|
|
|
|
32 |
|
|
|
|
33 |
|
|
|
|
33 |
|
|
|
|
33 |
|
|
|
|
34 |
|
|
|
|
34 |
|
|
|
|
36 |
|
|
|
|
37 |
|
|
|
|
38 |
|
|
|
|
41 |
|
|
|
|
42 |
|
|
|
|
44 |
|
|
|
|
46 |
|
|
|
|
47 |
|
|
|
|
47 |
|
INDEPENDENT AUDITORS REPORT
To the Stockholders and Board of Director of
Petrodelta, S.A.
We have audited the accompanying financial statements of PETRODELTA, S.A., which comprise the
statement of financial position as at December 31, 2009 and 2008, and the statements of
comprehensive income, statements of changes in equity and statements of cash flow for the years
then ended, and a summary of significant accounting policies and other explanatory notes.
Managements Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements
in accordance with International Financial Reporting Standards. This responsibility includes:
designing, implementing and maintaining internal control relevant to the preparation and fair
presentation of financial statements that are free from material misstatement, whether due to fraud
or error; selecting and applying appropriate accounting policies; and making accounting estimates
that are reasonable in the circumstances.
Auditors Responsibility
We conducted our audits in accordance with auditing standards generally accepted in the United
States of America. These standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures
in the financial statements. The procedures selected depend on the auditors judgment, including
the assessment of the risks of material misstatement of the financial statements, whether due to
fraud or error. In making those risk assessments, the auditor considers internal control relevant
to the entitys preparation and fair presentation of the financial statements in order to design
audit procedures that are appropriate in the circumstances, but not for the purpose of expressing
an opinion on the effectiveness of the entitys internal control. An audit also includes evaluating
the appropriateness of accounting policies used and the reasonableness of accounting estimates made
by management, as well as evaluating the overall presentation of the financial statements.
Urbanización Valles de Camoruco. Las 4 Avenidas. Reda Building. Torre B. Oficina 5-11. Valencia. Carabobo. Venezuela.
Telf.: 58-241 8253518 / 8255337 Fax: 8259828. RIF: J-30785734-0
PGFA Perales, Pistone & Asociados es firma miembro de
International
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a
basis for our audit opinion.
Opinion
In our opinion, the financial statements present fairly, in all material respects, the financial
position of Petrodelta, S.A. as of December 31, 2009 and 2008, and of its financial performance and
its cash flows for the year then ended in accordance with International Financial Reporting
Standards.
Emphasis of matter
Without qualifying our opinion as indicated in Note 19 to the financial statements, the Company
belongs to a group of related companies and conducts transactions and maintains balances for
significant amounts with other members of the group, with significant effects on the results of its
operations and financial position. Because of those relationships, these transactions may have
taken place on terms other than those that would characterize transactions between unrelated
companies.
Por PGFA PERALES, PISTONE & ASOCIADOS
José G. Perales S.
C.P.C. Nº 9.578
Valencia, January 22, 2010
Except for the matters indicated in Note 22, whose date is February 26, 2010
2
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of Financial Position
(Expressed In Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31st, |
|
|
|
Note |
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
U.S. dollars |
|
|
Bolivars |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
8 |
|
|
|
265,442 |
|
|
|
211,760 |
|
|
|
570,698 |
|
|
|
455,284 |
|
Deferred income tax |
|
|
7- |
(a) |
|
|
141,245 |
|
|
|
97,323 |
|
|
|
303,676 |
|
|
|
209,244 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current assets |
|
|
|
|
|
|
406,687 |
|
|
|
309,083 |
|
|
|
874,374 |
|
|
|
664,528 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid expenses and other assets |
|
|
10 |
|
|
|
559 |
|
|
|
21,477 |
|
|
|
1,202 |
|
|
|
46,176 |
|
Inventories |
|
|
11 |
|
|
|
21,472 |
|
|
|
14,391 |
|
|
|
46,167 |
|
|
|
30,941 |
|
Accounts receivable |
|
|
12 |
|
|
|
379,732 |
|
|
|
267,786 |
|
|
|
816,425 |
|
|
|
575,740 |
|
Cash and cash equivalents |
|
|
13 |
|
|
|
3,062 |
|
|
|
7,363 |
|
|
|
6,582 |
|
|
|
15,830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current asset |
|
|
|
|
|
|
404,825 |
|
|
|
311,017 |
|
|
|
870,376 |
|
|
|
668,687 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
|
|
|
|
|
811,512 |
|
|
|
620,100 |
|
|
|
1,744,750 |
|
|
|
1,333,215 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity, see statements of changes in equity |
|
|
14 |
|
|
|
432,100 |
|
|
|
340,692 |
|
|
|
929,013 |
|
|
|
732,487 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for abandonment cost |
|
|
9 y 16 |
|
|
|
24,416 |
|
|
|
19,174 |
|
|
|
52,492 |
|
|
|
41,224 |
|
Provision for retirement benefits |
|
|
16 |
|
|
|
9,184 |
|
|
|
1,306 |
|
|
|
19,746 |
|
|
|
2,808 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current liabilities |
|
|
|
|
|
|
33,600 |
|
|
|
20,480 |
|
|
|
72,238 |
|
|
|
44,032 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
|
15 |
|
|
|
105,332 |
|
|
|
89,104 |
|
|
|
226,465 |
|
|
|
191,574 |
|
Dividends payable |
|
|
14 |
|
|
|
31,126 |
|
|
|
|
|
|
|
66,921 |
|
|
|
|
|
Accruals and other liabilities |
|
|
16 |
|
|
|
154,863 |
|
|
|
169,824 |
|
|
|
332,956 |
|
|
|
365,122 |
|
Income tax payable |
|
|
7 |
|
|
|
54,491 |
|
|
|
|
|
|
|
117,157 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
|
|
|
|
345,812 |
|
|
|
258,928 |
|
|
|
743,499 |
|
|
|
556,696 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
|
|
|
|
379,412 |
|
|
|
279,408 |
|
|
|
815,737 |
|
|
|
600,728 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity and liabilities |
|
|
|
|
|
|
811,512 |
|
|
|
620,100 |
|
|
|
1,744,750 |
|
|
|
1,333,215 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes from 1 to 23 are an integral part of these financial statements
3
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of Comprehensive Income
(Expressed In Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31st, |
|
|
|
Note |
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
U.S. dollars |
|
|
Bolivars |
|
Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of crude oil |
|
|
|
|
|
|
451,473 |
|
|
|
458,113 |
|
|
|
970,667 |
|
|
|
984,943 |
|
Sales of gas |
|
|
|
|
|
|
6,778 |
|
|
|
16,506 |
|
|
|
14,572 |
|
|
|
35,488 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
458,251 |
|
|
|
474,619 |
|
|
|
985,239 |
|
|
|
1,020,431 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operational cost |
|
|
|
|
|
|
(48,311 |
) |
|
|
(77,609 |
) |
|
|
(103,869 |
) |
|
|
(166,859 |
) |
Depletion, depreciation and amortization |
|
|
8 |
|
|
|
(32,571 |
) |
|
|
(24,778 |
) |
|
|
(70,029 |
) |
|
|
(53,273 |
) |
Sales, general and administrative expenses |
|
|
|
|
|
|
(10,841 |
) |
|
|
(6,705 |
) |
|
|
(23,307 |
) |
|
|
(14,416 |
) |
Royalties |
|
|
7 |
(b) |
|
|
(157,681 |
) |
|
|
(225,167 |
) |
|
|
(339,014 |
) |
|
|
(484,109 |
) |
Financial expenses |
|
|
|
|
|
|
(3,617 |
) |
|
|
(2,329 |
) |
|
|
(7,777 |
) |
|
|
(5,007 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(253,021 |
) |
|
|
(336,588 |
) |
|
|
(543,996 |
) |
|
|
(723,664 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit before tax |
|
|
|
|
|
|
205,230 |
|
|
|
138,031 |
|
|
|
441,243 |
|
|
|
296,767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense |
|
|
7 |
(a) |
|
|
(61,946 |
) |
|
|
(16,814 |
) |
|
|
(133,184 |
) |
|
|
(36,150 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit and total comprehensive
income for the year |
|
|
|
|
|
|
143,284 |
|
|
|
121,217 |
|
|
|
308,059 |
|
|
|
260,617 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes from 1 to 23 are an integral part of these financial statements
4
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of changes in equity
Years ended December 31, 2009 and 2008
(Expressed In Thousands of US dollar)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholder |
|
|
|
|
|
|
Legal reserve and |
|
|
|
|
|
|
|
|
|
Note |
|
|
Capital stock |
|
|
contribution |
|
|
Share premium |
|
|
other reserves |
|
|
Distributable |
|
|
Total |
|
Balances at December 31, 2007 |
|
|
|
|
|
|
465 |
|
|
|
6,512 |
|
|
|
212,451 |
|
|
|
47 |
|
|
|
181,325 |
|
|
|
400,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit and total comprehensive income for the year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
121,217 |
|
|
|
121,217 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders contribution capitalization |
|
|
14 |
|
|
|
6,512 |
|
|
|
(6,512 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appropriation to legal reserve |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
651 |
|
|
|
(651 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(181,325 |
) |
|
|
(181,325 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008 |
|
|
|
|
|
|
6,977 |
|
|
|
|
|
|
|
212,451 |
|
|
|
698 |
|
|
|
120,566 |
|
|
|
340,692 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit and total comprehensive income for the year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
143,284 |
|
|
|
143,284 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appropriation to other reserves |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
141,245 |
|
|
|
(141,245 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(51,876 |
) |
|
|
(51,876 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009 |
|
|
|
|
|
|
6,977 |
|
|
|
|
|
|
|
212,451 |
|
|
|
141,943 |
|
|
|
70,729 |
|
|
|
432,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes from 1 to 23 are an integral part of these financial statements
5
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of changes in equity
Years ended December 31, 2009 and 2008
(Expressed in Thousands of bolivars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholder |
|
|
|
|
|
|
Legal reserve and |
|
|
|
|
|
|
|
|
|
Note |
|
|
Capital stock |
|
|
contribution |
|
|
Share premium |
|
|
other reserves |
|
|
Distributable |
|
|
Total |
|
Balances at December 31, 2007 |
|
|
|
|
|
|
1,000 |
|
|
|
14,000 |
|
|
|
456,770 |
|
|
|
100 |
|
|
|
389,846 |
|
|
|
861,716 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit and total comprehensive income for the year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
260,617 |
|
|
|
260,617 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders contribution capitalization |
|
|
14 |
|
|
|
14,000 |
|
|
|
(14,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appropriation to legal reserve |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,400 |
|
|
|
(1,400 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(389,846 |
) |
|
|
(389,846 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008 |
|
|
|
|
|
|
15,000 |
|
|
|
|
|
|
|
456,770 |
|
|
|
1,500 |
|
|
|
259,217 |
|
|
|
732,487 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit and total comprehensive income for the year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
308,059 |
|
|
|
308,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appropriation to other reserves |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
303,676 |
|
|
|
(303,676 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(111,533 |
) |
|
|
(111,533 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009 |
|
|
|
|
|
|
15,000 |
|
|
|
|
|
|
|
456,770 |
|
|
|
305,176 |
|
|
|
152,067 |
|
|
|
929,013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes from 1 to 23 are an integral part of these financial statements
6
PETRODELTA, S.A
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of Cash Flow
(Expressed In Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31st, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
U.S. dollars |
|
|
Bolivars |
|
Cash flow from operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit and total comprehensive income for
the year |
|
|
143,284 |
|
|
|
121,217 |
|
|
|
308,059 |
|
|
|
260,617 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to reconcile net income to net cash (used in) provided by operating activities - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
|
33,188 |
|
|
|
25,508 |
|
|
|
71,352 |
|
|
|
54,843 |
|
Provision for abandonment cost |
|
|
(3,603 |
) |
|
|
(10,866 |
) |
|
|
(7,745 |
) |
|
|
(23,362 |
) |
Deferred income tax |
|
|
(43,922 |
) |
|
|
(52,560 |
) |
|
|
(94,432 |
) |
|
|
(113,004 |
) |
Financial cost on provision for
abandonment cost |
|
|
1,639 |
|
|
|
2,344 |
|
|
|
3,523 |
|
|
|
5.039 |
|
Tax credit financial cost |
|
|
1,792 |
|
|
|
|
|
|
|
3,853 |
|
|
|
|
|
Net changes in operating assets - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(113,738 |
) |
|
|
(133,756 |
) |
|
|
(244,538 |
) |
|
|
(287,575 |
) |
Material and supplies Inventories |
|
|
(8,923 |
) |
|
|
(10,833 |
) |
|
|
(19,185 |
) |
|
|
(23,291 |
) |
Prepaid expenses and other assets |
|
|
20,918 |
|
|
|
(20,604 |
) |
|
|
44,974 |
|
|
|
(44,299 |
) |
Net changes in operating liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
|
16,228 |
|
|
|
321,555 |
|
|
|
34,891 |
|
|
|
691,343 |
|
Income taxes payable |
|
|
54,491 |
|
|
|
(153,037 |
) |
|
|
117,157 |
|
|
|
(329,030 |
) |
Accruals and other liabilities |
|
|
(3,480 |
) |
|
|
132,090 |
|
|
|
(7,483 |
) |
|
|
283,994 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total adjustments |
|
|
(45,410 |
) |
|
|
99,841 |
|
|
|
(97,633 |
) |
|
|
214,658 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities |
|
|
97,874 |
|
|
|
221,058 |
|
|
|
210,426 |
|
|
|
475,275 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of property, plant and equipment |
|
|
(81,425 |
) |
|
|
(39,347 |
) |
|
|
(175,062 |
) |
|
|
(84,596 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(81,425 |
) |
|
|
(39,347 |
) |
|
|
(175,062 |
) |
|
|
(84,596 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paid dividends |
|
|
(20,750 |
) |
|
|
(181,325 |
) |
|
|
(44,612 |
) |
|
|
(389,849 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(20,750 |
) |
|
|
(181,325 |
) |
|
|
(44,612 |
) |
|
|
(389,849 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash increase |
|
|
(4,301 |
) |
|
|
386 |
|
|
|
(9,248 |
) |
|
|
830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and equivalents at the beginning of the period |
|
|
7,363 |
|
|
|
6,977 |
|
|
|
15,830 |
|
|
|
15,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and equivalents at the end of the period |
|
|
3,062 |
|
|
|
7,363 |
|
|
|
6,582 |
|
|
|
15,830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes from 1 to 23 are an integral part of these financial statements
7
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
(1) |
|
Reporting Entity |
|
|
|
Petrodelta, S.A. (the Company) was incorporated in Venezuela in October 2007, as published in
Official Gazette No. 38,786. Its business objective is primary exploration to discover oil
reserves, extraction of oil in its natural state, and its subsequent collection,
transportation and storage pursuant to Article No. 9 of the Venezuelan Hydrocarbon Law (LOH).
The Company operates within an area of approximately 1,000 square kilometers in the Uracoa,
Bombal and Tucupita fields (formerly the Monagas Sur Unit) and in the El Salto, El Isleño and
Temblador fields in the Monagas and Delta Amacuro states in Venezuela (the assigned operating
area). |
|
|
|
The Company was created as a result of the process for conversion into mixed-capital
companies of the Operating Agreement signed on July 31, 1992 between PDVSA Petróleo, S.A.
(PDVSA Petróleo) (formerly Lagoven, S.A.), Harvest Natural Resources, Inc. (Harvest)
(formerly Benton Oil and Gas Company) and Venezolana de Inversiones y Construcciones Clérico,
C.A. (Vinccler). As part of this process, on March 31, 2006, PDVSA Petróleo, S.A.,
Corporación Venezolana del Petróleo, S.A. (CVP) and Harvest Vinccler, S.C.A. (HVSCA), the
agreement operator and a related company of Harvest and Vinccler, signed a memorandum of
understanding for conversion into a mixed company. In June 2007, the National Assembly of
the Bolivarian Republic of Venezuela approved the incorporation of the mixed company
Petrodelta, S.A. In August 2006, the National Assembly approved the inclusion of the
Temblador, El Isleño and El Salto areas into the Monagas Sur Unit for further development of
the Companys primary activities. An agreement for conversion into a mixed company was
signed between CVP and HNR Finance B.V. (HNR Finance) in September 2007. The Company will
operate for 20 years as from October 2007 when the decree for transfer of field operations
was published in the Official Gazette. |
|
|
|
Petrodelta, S.A. is 60%-owned by CVP, a wholly owned subsidiary of Petróleos de Venezuela,
S.A. (PDVSA), and 40%-owned by HNR Finance. |
|
|
|
The Company was incorporated and is domiciled in Venezuela. Its legal address is: Avenida
Veracruz con Calle Cali, Urbanización Las Mercedes, Edificio Pawa, Piso 5, Caracas, Distrito
Capital. Its main offices are located at Avenida Alirio Ugarte Pelayo, Edificio Harvest
Vinccler, Ala Norte, Planta Baja in Maturín, Monagas State. |
|
|
|
On February 26, 2010, the Board of Directors of the Company approved the issuance of the
financial statements under International Financial Reporting Standards and submitted said
financial statements to the Shareholders of the Company for approval purposes. Once the
aforementioned financial statements are duly approved and issued, no amendment of which
applies. |
|
|
|
Company management considers that it operates in a single business segment (hydrocarbons) in
one country, the Bolivarian Republic of Venezuela, in conformity with its social statutes. |
|
|
|
During the transition period from April 1, 2006 to December 31, 2007, Harvest Vinccler,
S.C.A. (HVSCA) was in charge of managing and developing the Companys activities and provided
its financial and operational structure for this purpose. The Companys operating costs
during this period were paid by HVSCA and CVP and subsequently charged to PDVSA Petróleo,
which, in |
8
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
turn, will bill the Company. These costs were recognized in the income statements for the
respective periods and include, but are not limited to, general, administrative, operating
and capital expenses required to continue activities in the assigned operating area. At
December 31, 2009 the Company had not received all information regarding production during
the conversion period for the Temblador field in order to invoice all volumes produced in
that field during that period. As Temblador production was handled in PDVSA system, PDVSA had
allocated only partial, estimated production to Petrodelta. As a result, Petrodelta had not,
and still has not, received full credit for the Temblador field production. Discussions are
ongoing to settle figures. During the third quarter 2009, Petrodelta completed the facilities
and pipelines to segregate approximately 80 percent of the Temblador fields production out
of PDVSAs system. |
|
|
|
|
During the years ended December 31, 2009 and 2008, the Company has operated with employees
assigned by its shareholders or their related companies since it has no direct employees. At
December 31, 2009, the Company had 356 employees assigned by its shareholders or their
related companies. During the first quarter of 2008, 238 employees were transferred from
HVSCA to PDVSA. |
|
|
|
|
During 2009 the Company drilled 18 development wells, produced approximately 7.8 million
barrels of oil and sold 4.4 billion cubic feet of natural gas. Petrodeltas reserves
increased primarily by the drilling of two appraisal wells in the largely undeveloped El
Salto field. Production was initiated from El Salto field during the month of July 2009 with
the drilling and completion of one well which has produced 349,000 barrels of oil through the
end of 2009. |
|
|
|
|
Applicable regulations |
|
|
|
|
The Companys main activities are regulated by the Venezuelan Hydrocarbon Law (LOH),
effective from January 2002. Gas-related operations are regulated by the Venezuelan Gaseous
Hydrocarbon Law of September 1999 and its Regulations of June 2000. |
|
|
|
|
Below are the main regulations included in the LOH: |
|
a) |
|
A 30% royalty on volumes of hydrocarbon extracted. |
|
|
b) |
|
A Partial Reform of the Extraction Tax was enacted and published in Official
Gazette No. 38,443 of May 24, 2006, establishing a rate equivalent to one-third of the
value of all liquid hydrocarbons extracted from any reservoir, calculated on the same
basis as royalties. The taxpayer has the right to deduct from the extraction tax any
sum payable as royalties (30%), including the additional royalty paid for special
advantages (3.33%). |
|
|
c) |
|
A surface tax equivalent to 100 tax units for each square kilometer or fraction
thereof per year for licensed areas that are not under production. This tax will
increase by 2% during the first five years, and by 5% during all subsequent years.
Company management considers that there are no nonproductive areas. |
|
|
d) |
|
An internal consumption tax equivalent to 10% of the value of each cubic meter of
hydrocarbon derivatives produced and consumed as fuel in internal operations, calculated
on |
9
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
the final selling price. Company management considers that, other than associated gas,
no hydrocarbon derivatives are consumed. |
Hydrocarbon purchase sale agreement
|
|
|
The Company signed a hydrocarbon purchase sale agreement with PDVSA Petróleo, whereby the
Company undertakes to sell to the latter all hydrocarbons produced within the delimited
operating area that are not being used in its operations. The Company may assign or
transfer this agreement, or any rights and obligations thereunder, to another company in
accordance with Article No. 27 of the LOH. This agreement is for 20 years. |
|
(a) |
|
Statement of compliance |
|
|
|
|
The financial statements as of December 31, 2009 and 2008 are prepared in accordance with
International Financial Reporting Standards (IFRS) adopted by the International
Accounting Standards Board (IASB) and their interpretations, issued by the International
Financial Reporting Interpretations Committee (IFRIC) of the IASB. |
|
|
|
|
The financial statements for the year ended December 31, 2008 have been prepared and are
presented for purposes of comparison with the financial statements for the year ended December 31, 2009. |
|
|
(b) |
|
Basis of measurement |
|
|
|
|
The financial statements have been prepared on the historic cost basis, except for
certain assets and liabilities measured at fair value. Assets measured and stated at
fair value are: recoverable tax credits, accounts receivable and cash. |
|
|
|
|
The methods used for measuring fair value are discussed in Note 5. |
|
|
(c) |
|
Functional and presentation currency |
|
|
|
|
The financial statements are presented in U.S. dollars, the Companys functional
currency, since the main economic environment in which the Company operates is the
international market for crude oil and its products. In addition, a significant portion
of its revenues, as well as most costs, expenses and investments are denominated in this
currency. |
|
|
|
|
The financial statements in bolivars are presented for statutory purposes. The Companys
financial statements are translated into bolivars, a currency other than the functional
currency, in accordance with International Accounting Standard No. 21 The Effects of
Changes in Foreign Exchange Rates. This standard requires each entity to determine its
functional currency based on an analysis of the primary economic environment in which the
entity operates, which is normally the one in which it primarily generates and expends
cash. |
10
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
The financial statements are translated into bolivars based on the following criteria: |
|
- |
|
Assets and liabilities of each statement of financial position at the
exchange rates in effect at date. |
|
|
- |
|
Income and expenses at the average exchange rate for each year. |
|
|
- |
|
Exchange gains or losses resulting from translation are recognized as a
separate equity component under Cumulative translation adjustment. During the year
ended December 31, 2009 and 2008 the official exchange rate did not change.
Consequently, a cumulative translation adjustment was not originated. |
|
|
|
All financial information presented in U.S. dollars has been rounded in thousands. |
|
(d) |
|
Use of estimates, risks and uncertainty |
|
|
|
|
The preparation of financial statements in conformity with IFRS requires management to
make estimates, judgments and assumptions that affect the application of accounting policies and the amounts of assets, liabilities, income and expense. The Company applies
its best estimates and judgments; however, actual results may differ from initial
estimates. |
|
|
|
|
The related estimates and assumptions are based on experience and other factors which are
considered reasonable under current circumstances and form the basis for making judgments
on the carrying value of assets and liabilities not easily determined by other means.
Estimates and assumptions are reviewed periodically, and revisions to accounting
estimates are recognized in the period in which the estimate is revised and in any future
periods affected. |
|
|
|
|
Significant areas of uncertainty affecting managements estimates and judgment in the
application of accounting policies, which significantly affect financial statement
amounts are: |
|
- |
|
Note 8 Depletion, depreciation and amortization |
|
|
- |
|
Note 7 Deferred income tax |
|
|
- |
|
Note 9 Provision for abandonment costs |
|
|
- |
|
Note 17 Valuation of financial instruments |
|
|
- |
|
Note 3 -s- Measurement of contract-based retirement benefit obligations
and other post-retirement benefits other than pensions, which are being calculated
by PDVSA for subsequent billing to the Company. |
|
|
- |
|
Note 18 Liabilities, contingencies and accruals in respect of
environmental issues |
|
|
|
The Companys operations may be affected by the political, legislative, regulatory and
legal environment, both at the national and international level. In addition,
significant changes in |
11
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
prices or availability of crude oil and its products may have an impact on the Companys
results of operations in any given year. |
(3) |
|
Summary of Significant Accounting Policies |
|
|
|
The accounting policies used for the preparation of these financial statements have been
applied consistently for all periods presented. |
|
(a) |
|
Transactions in currencies other than the U.S dollar |
|
|
|
|
Transactions in currencies other than the U.S. dollar are translated into the Companys
functional currency using the exchange rate in effect at the transaction date. Monetary
assets and liabilities denominated in currencies other than the U.S. dollar are
translated into U.S. dollars using the exchange rate prevailing at the date of the
statement of financial position. Exchange gains or losses on monetary items in
currencies other than the U.S. dollar represent the difference between the net cost in
the functional currency at the beginning of the year, adjusted by the effective interest
rate and payments made during the year, and the net cost in currencies other than the
U.S. dollar translated using the year-end exchange rate. Nonmonetary assets and
liabilities in currencies other than the U.S. dollar stated at fair value are
retranslated to the functional currency using the exchange rate prevailing at the date
fair value was determined. Exchange gains or losses resulting from retranslation are
recognized in the statement of comprehensive income. |
|
|
(b) |
|
Financial instruments |
|
|
|
|
Non-derivative financial instruments consist of cash and cash equivalents, recoverable
tax credits, accounts receivable, accounts payable to suppliers and other liabilities. |
|
|
|
|
Non-derivate financial instruments classified as at fair value through profit or loss are
initially recognized at fair value, plus any direct transaction costs. |
|
|
|
|
A financial instrument is recorded when the Company engages or commits to the contractual
clauses thereof. Financial assets are reversed if the Companys contractual rights over
the assets cash flows expire or if the Company transfers the financial asset to another
entity without retaining control or a significant portion of the assets risks and
rewards. Regular purchases and sales of financial assets are accounted for at trade
date, which is generally the date on which the Company commits to purchase or sell the
asset. Financial liabilities are derecognized when the Companys specific contractual
obligation expires or is paid. |
|
|
|
|
During the years ended December 31, 2009 and 2008, the Company conducted no transactions
with derivative instruments. |
12
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
(c) |
|
Property, plant and equipment |
|
|
|
|
Property, plant and equipment are stated at cost, net of accumulated depreciation and
impairment losses (See Note 8). The successful efforts accounting method is used for
exploration and production activities of crude oil and natural gas. All costs for
development wells, related plant and equipment, and property used for oil recovery are
capitalized. Costs of exploratory wells are capitalized until it is determined whether
they are commercially feasible; otherwise, such costs are charged to operating expenses.
Other exploratory expenditures, including geological and geophysical costs, are expensed
as incurred. Costs for major maintenance or general repairs are capitalized when
identified as a separate component of the asset to which such maintenance and repair
corresponds and are depreciated between one maintenance period and the other.
Disbursements for minor maintenance, repairs and renewals incurred to maintain facilities
in operating conditions are expensed. Gains or losses arising from asset retirement or
disposal are included in the income statement. |
|
|
|
|
The cost of property, plant and equipment also includes, when relevant, the amounts
associated with asset retirement obligations (See Note 8). |
|
|
|
|
Finance costs of projects requiring major investments over long-term construction periods
and those incurred for specific projects are capitalized and amortized over the estimated
useful lives of the related assets. |
|
|
|
|
The cost of assets built by the Company includes materials and direct labor, as well as
any other direct cost attributable to bringing the asset to working condition. Costs for
dismantling and removal from the construction site are also included. All disbursements
relating to construction or purchase of property, plant and equipment in the stage prior
to implementation are stated at cost as work in progress. Once the assets are ready for
use, they are transferred to the respective component of property, plant and equipment
and depreciation or amortization commences. |
|
|
|
|
When parts of a property, plant and equipment asset have different useful lives, they are
recorded separately as a significant component of that asset. |
|
|
|
|
Gains or losses on disposal of a property, plant and equipment item are determined by the
difference between the proceeds from disposal, if any, and the net carrying amount of the
asset, and is recognized under other income (expense), net in the statement of
comprehensive income. |
|
|
|
|
Depreciation and amortization of capitalized costs related to wells and facilities for
the production of crude oil and gas are determined by the units of production method by
field, based on proved developed reserves. The rates used are reviewed annually based on
an analysis of reserves and are applied retroactively at the beginning of the year.
Capitalized costs of other plant and equipment are depreciated over their estimated
useful lives, mainly using the straight-line method with an average useful life of 15
years for administrative |
13
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
buildings and between 3 and 5 years for the remaining assets. Ordinary withdrawals are
eliminated against the respective accumulated depreciation; net gains or losses from
extraordinary withdrawals are included in the statement of comprehensive income. |
|
|
|
|
Depreciation methods and average useful lives of property, plant and equipment are
reviewed annually. |
|
|
|
|
Certain materials and supplies accounted for as inventory and considered strategic since
they will be used as spare parts for two years operation in the production facilities and
in specific investment projects are reported under property, plant and equipment. |
|
(d) |
|
Inventories |
|
|
|
|
Inventories are stated at the lower of cost and net realizable value. The cost of
inventories of crude oil and its products is determined using the average cost method.
Materials and supplies are valued mainly at average cost, less an allowance for possible
losses, and are classified into two groups: current assets and non-current assets. |
|
|
|
|
Net realizable value is the estimated selling price in the normal course of business,
less costs to complete and estimated selling costs. |
|
|
(e) |
|
Trade accounts receivable |
|
|
|
|
Trade accounts receivable are accounted for according to price formulas established in
the hydrocarbon purchase sale agreement between the mixed companies and PDVSA Petróleo,
whereby the former undertake to sell and PDVSA Petróleo undertakes to buy all
hydrocarbons produced that are not being used in their operations within the delimited
operating areas. At December 31, 2009 and 2008, the Company does not expect to incur
losses on uncollectible accounts and, therefore, has not set aside a provision in this
connection. |
|
|
(f) |
|
Cash and cash equivalent |
|
|
|
|
Petrodelta, S.A. considers as cash and cash equivalents placements and time deposits
maturing within three months that are readily convertible. |
|
|
(g) |
|
Impairment in the value of long-lived assets |
|
|
|
|
Financial assets |
|
|
|
|
The Company assesses possible impairment in the value of its financial assets at each
reporting date. A financial asset is impaired if there is objective evidence that one or
more events have had a negative effect on the estimated future cash flows of the asset. |
|
|
|
|
Significant financial assets are assessed individually to determine their impairment.
All other financial assets sharing similar credit risk characteristics are evaluated as a
group. |
14
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
Impairment losses are recognized in the statement of comprehensive income. An impairment
loss is reversed if it can be objectively associated with an event occurring after the
impairment loss was recognized. |
|
|
|
|
Non-financial assets |
|
|
|
|
The carrying value of non-financial assets, excluding inventories and deferred tax, is
reviewed for possible impairment at each reporting date. The recoverable amount of the
asset is estimated if evidence of impairment exists. |
|
|
|
|
An impairment loss is recognized for the amount by which the assets carrying amount or
its cash-generating unit exceeds its recoverable amount. A cash-generating unit is the
assets grouped at the lowest levels for which there are separately identifiable cash
flows. Recoverability of assets to be held and used is measured by comparing their
carrying amount to the net discounted future cash flows expected to be generated by these
assets. If the carrying amount of the assets exceeds the estimated value of discounted
future cash flows, an impairment loss is recognized in the income statement in the amount
of such excess. The asset cost is shown net of this impairment charge. Impairment is
determined by the Company based on cash-generating units, in accordance with its business
segments, geographical locations and the final use of the production generated by each
unit. Impairment losses may be reversed only if there has been a change in the estimates
used after the impairment loss was recognized. |
|
(h) |
|
Costs associated with asset retirement obligations |
|
|
|
|
The Company capitalizes estimated costs associated with obligations from retirement of
assets used for exploration and crude oil and natural gas production activities, based on
the future retirement plan for those assets. Cost is capitalized as part of the related
long-lived asset and is amortized over its useful life with a charge to operating costs. |
|
|
|
|
Obligations associated with the retirement of long-lived assets are recorded at fair
value as incurred, based on discounted future cash flows. Fair value is determined based
on current regulations and technologies. |
|
|
(i) |
|
Income tax |
|
|
|
|
Income tax expense comprises current and deferred tax. Income tax expense is recognized
in the results for each year, except for items that should be directly recognized in
other comprehensive income. |
|
|
|
|
Current tax is the estimated amount payable based on taxable income for the year, using
the tax rate and the methodology established in current regulations at the balance sheet
date and any adjustment to taxes payable from previous years. |
15
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
Deferred income tax is accounted for using the balance sheet method. Deferred assets and
liabilities are recognized for future tax consequences attributable to differences
between the carrying amounts of assets and liabilities and their respective tax bases,
and operating loss and tax credit carryforwards. The value of deferred assets and
liabilities is determined based on tax rates expected to be applicable to taxable income
for the year in which temporary differences will be recovered or settled pursuant to law.
The effect on deferred assets and liabilities of changes in tax rates is recorded in the
results for the year in which such changes become effective.
A deferred tax asset is recognized only to the extent that future taxable income will be
available for offsetting. Deferred tax assets are reviewed at each reporting date and
reduced to the extent that it is no longer probable that the related tax benefit will be
realized. |
|
(j) |
|
Provisions |
|
|
|
|
A provision is recorded if as a result of a past event the Company has a present legal or
constructive obligation that can be reliably estimated and it is probable that an outflow
of economic benefits will be required to settle the obligation. |
|
|
|
|
In conformity with the environmental policy established by PDVSA and current legislation,
the Company recognizes a liability when costs are likely and can be reasonably estimated.
Environmental expenditures that relate to income from current or future operations are
recorded as expenses or assets, as applicable. Expenditures that relate to past
operations that do not contribute to current or future revenue generation are expensed.
These provisions are created when an obligation related to environmental remediation is
identified, in respect of which the Company has the necessary information to determine a
reasonable estimate of the related cost. Subsequent adjustments, if required, are made
upon receipt of additional information. |
|
|
(k) |
|
Revenue recognition |
|
|
|
|
Income from sales of crude oil and gas is recorded in the statement of comprehensive
income when risks and significant rights of ownership are transferred to PDVSA Petróleo
and MPPEP as stipulated in the hydrocarbon purchase sale agreement. Income is recognized
when it can be reasonably measured and it is probable that future economic benefits will
flow to the Company. Income from activities other than the Companys main business is
recognized when realized. Income is not recognized when there is significant uncertainty
as to the recoverability of the obligation acquired by the buyer. All of the Company
results are from continuing operations. |
|
|
(l) |
|
Capital stock |
|
|
|
|
Common shares are classified as equity. For the years ended December 31, 2009 and 2008,
the Company has no preferred shares (See Note 14). |
16
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
(m) |
|
Share premium |
|
|
|
|
The Company recognizes as share premium any excess in the value of contributions made by
shareholders for Company incorporation over the par value at the incorporation date (See
Note 14). |
|
|
(n) |
|
Legal reserve |
|
|
|
|
The Venezuelan Code of Commerce requires companies to set aside 5% of their net income
each year to a legal reserve until it reaches an amount equivalent to at least 10% of
their capital stock in bolivars (See Note 14). |
|
|
(o) |
|
Other equity reserves |
|
|
|
|
The Company has the policy of transferring from retained earnings to other equity
reserves the balance of deferred tax account when the latter is an asset. This reserve is
recognized in retained earnings to the extent that such asset gets realized when the
temporary differences that gave rise to it are deducted for tax purposes and consequently
would be available for dividend payments. |
|
|
(p) |
|
Dividend distribution |
|
|
|
|
Dividend distribution to the Companys shareholders is recognized as a liability in the
financial statements in the period in which the dividends are approved by the
shareholders. |
|
|
(q) |
|
Accounting estimates requiring a high degree of judgment |
|
|
|
|
The Company continually evaluates judgments used to record its accounting estimates,
which are recorded based on historical experience and other factors, including
expectation of future events that are believed to be reasonable under the circumstances.
Significant future changes to assumptions established by management may significantly
affect the carrying value of assets and liabilities. |
|
|
|
|
Below is a summary of the most significant accounting estimates made by the Company: |
|
|
|
|
Estimates of oil reserves |
|
|
|
|
Oil and gas reserves are key elements in the Companys decision-making process. They are
also important in evaluating impairment in the carrying amount of long-lived assets.
Calculation of depreciation, amortization and depletion of property, plant and equipment
accounts related to hydrocarbon production requires quantification of proved developed
hydrocarbon reserves expected to be recovered by the Company in the future. Reserve
estimates are only approximate amounts due to the high degree of judgment and
specialization required to develop the information. Reserves are calculated by
specialized technical departments at Petróleos de Venezuela, S.A. (PDVSA) (related
company that owns the Companys main shareholder) and results are submitted for approval
by MPPEP |
17
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
in order to guarantee the reasonableness of the information. Additionally, reserve
studies are regularly updated to guarantee that any change in estimates is timely
recorded in the Companys financial statements. |
|
|
|
|
To date, reserves studies assigned to the Company are currently under revision, update
and certification. |
|
|
|
|
Assessment of impairment in the value of property, plant and equipment |
|
|
|
|
Management annually assesses impairment in the value of property, plant and equipment.
The main key assumptions considered by management to determine the recoverable amount of
property, plant and equipment were income projections, oil prices, royalties, operating and capital costs and the discount rate. Projections include proved developed
reserves to be produced during the development period of production activities in the
assigned fields. At December 31, 2009 and 2008, the Company has not identified
impairment in the carrying value of property, plant and equipment as a result of these
estimates. |
|
|
|
|
Abandonment cost calculation |
|
|
|
|
The Companys financial statements include an asset and a provision for property, plant
and equipment used in hydrocarbon production that is expected to be abandoned in the
future and in relation to which the Company will make future disbursements. Assumptions
considered for the calculation of this asset and the provision for abandonment (asset
abandonment costs, date of abandonment, and inflation and discount rates) may vary
depending on factors such as performance in the field, changes in technology and legal
requirements. Assumptions made by the Company are recorded based on technical studies
and managements experience and are regularly reviewed (See Note 9). |
|
(r) |
|
Related party transactions |
|
|
|
|
The Company does not disclose, as part of balances and transactions with related
companies (See Note 19), transactions with government entities conducted in the normal
course of business, the terms and conditions of which are consistently applied to other
public and private entities and for which there are no other suppliers, i.e.,
electricity, telecommunications, taxes, etc. |
|
|
(s) |
|
Accrual for employee benefits |
|
|
|
|
Following corporate instructions from PDVSA, the related company PDVSA, S.A. assumed the
employer role for employees who accepted the transfer, and are working as assigned
employees to Petrodelta, S.A. operations. According to this, PDVSA Petróleo, S.A.
administer and prepare those employees payroll and invoice direct payroll and benefits
of the Company, which recognize those costs against a liability to PDVSA Petróleo, S.A.
The direct payroll and benefits costs are determined by PDVSA according the following
policies: |
18
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
Termination benefits |
|
|
|
|
The Company accrues for its liability in respect of employee termination benefits based
on the provisions of the Venezuelan Labor Law and the prevailing oil-sector collective
labor agreement. Under certain circumstances, the Law provides for an additional indemnity for
unjustified dismissals. Most of this accrual for indemnification has been deposited in
trust accounts in the name of each employee. |
|
|
|
|
On October 11, 2007, PDVSA entered into a Collective Labor Agreement, effective through
2009, so improving salaries and labor benefits for staff in the contract payroll in
Venezuela. Those liabilities resulting of the application of said Collective Labor
Agreement are in full effect as from November 2007. At the end of 2009, the United
Federation of Workers for Oil, Gas and Similar (FUTPV) and PDVSA, are waiting for the
approval by the president of the Bolivarian Republic of Venezuela to sign the contract
for the period 2009 to 2011 (See Note 21). |
|
|
|
|
Profit sharing and bonuses |
|
|
|
|
Liabilities in respect of labor benefits and bonuses for staff, vacation leaves, and
other benefits are accounted for as incurred along with the staffs provision of
services. |
|
|
|
|
During the years ended December 31, 2009 and 2008, the Company has not had direct
employees and, therefore, has not recorded liabilities derived from these labor-related
benefits. |
|
|
|
|
Retirement Plan |
|
|
|
|
The amount to be provision for retirement benefits is received from PDVSA based on
actuary studies. Net liabilities in respect of the retirement plan as defined in the
contract are accounted for separately per each participant in said plan, by estimating
the amount of future benefits to be acquired by staff versus their length of service
during current and prior periods; said benefits are discounted in order to determine
their current value, then it is deducted the fair market value of those assets associated
to the plan. The discount rate reflects the yield rate that, as of the date of the
financial statements, is reported through financial instruments issued by credit
institutions with high ratings and maturity dates that are in line with those due dates
applicable to said liabilities. This calculation is made by an actuary by using the
projected unit credit method. |
|
|
|
|
Improvements made to the plans benefits, in connection with past service cost, are
expensed in the statement of profit and loss per the estimated period that, on average,
will last until the moment said benefits will be paid in full. As said benefits fall
under irrevocable acquired rights after approval, said expense is recorded, immediately,
in the statement of comprehensive income. |
|
|
|
|
It is accounted for as income or expense the share corresponding to the total of
unrecorded actuarial earnings or loss in excess of 10% of the greater of these sums: a)
the current |
19
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
value of liabilities in respect of those benefits defined as of that date; and b)
the reasonable value of the plans assets as of that date. Said caps are computed and
apply separately per each plans benefit so defined. |
|
|
|
|
Post-retirement benefits other than retirement |
|
|
|
|
Net liabilities in respect of post-retirement benefits other than retirement, as defined
in the contract, equal the total of future benefits earned by staff along with their
length of service during current and prior periods. Said benefits include mainly: health
and dental plans, burial and funeral insurance, and food electronic card. Said
liabilities are computed by using the projected unit credit method; then they are
deducted to reflect their current value and, if applicable, the fair market value of
related assets is deducted as well. The discount rate should reflect the yield rate that,
as of the date of the financial statements, is reported through financial instruments
issued by credit institutions with high ratings and maturity dates that are in line with
those due dates applicable to said liabilities. |
|
|
|
|
Past service cost and the actuarial income or loss are recorded by using the method set
out in the retirement plan per the contract. |
|
|
|
|
The provision for this concept is provided by PDVSA which is based on actuary studies. |
|
|
(t) |
|
New accounting standards not yet adopted |
|
|
|
|
Certain new standards, amendments and interpretations to existing standards were not
effective for the year ended December 31, 2009 and have not been applied in the
preparation of the Companys financial statements. The most important standards,
amendments and interpretations for the Company are as follows: |
|
- |
|
In November 2009, IASB issued revised IAS 24, Related Party Transactions.
This review applies for accounting periods beginning on or after January 1, 2011.
This version simplify the disclosure requirements for government-related entities
and clarifies the definition of related parties. |
|
|
- |
|
In July 2009, IASB issued amendments to IFRS 1 First-time Adoption of
International Financial Reporting Standards, effective for accounting periods
beginning on or after January 1, 2010 with earlier application permitted. IFRS 1
amendments address the retrospective application of IFRSs to particular situations
and are aimed at ensuring that entities applying IFRSs will not face undue cost or
effort in the transition process. The amendments 1) exempt entities using the full
cost method from retrospective application of IFRSs for oil and gas assets; 2)
exempt entities with existing leasing contracts from reassessing the classification
of those contracts in accordance with IFRIC 4 Determining whether an Arrangement
contains a Lease when the application of their national accounting requirements
produced the same result. |
|
|
- |
|
In April 2009, the IASB published the annual IFRS improvement project that
included amendments to certain existing standards and interpretations not effective
for the year |
20
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
ended December 31, 2009. The most important standards and interpretations for the
Company are: IFRS 2 Share-based Payment ; IFRS 5 Non-current Assets held for sale and
discounted operations; IFRS 8 Operating Segments; IAS 1 Presentation of Financial
Statements; IAS 7 Statement of Cash Flows; IAS17 Leases; IAS 18 Revenue; IAS 36
Impairment of Assets; IAS 38 Intangible Assets; IAS 39 Financial Instruments: recognition
and Measurement; IFRIC 9 Reassessment of Embedded Derivatives; and IFRIC 16 Hedges of a
Net Investment in a Foreign Operation. |
|
|
- |
|
In November 2009, the IASB issued IFRS 9 Financial Instruments on the
classification and measurement of financial assets. Publication of IFRS 9 represents
the completion of the first part of a three part project to replace IAS 39 -
Financial Instruments: Recognition and Measurement. IFRS 9 will be effective for
accounting periods beginning on or after January 1, 2013. This standard uses a
simple approach to determine whether a financial asset is measured at amortized cost
or fair value. The new approach is based on how an entity manages its financial
instruments (its business model) and the contractual cash flow characteristics of
the financial assets. The standard also requires a single impairment method to be
used. |
|
|
|
The Company completed the analysis of these standards and determined no significant
effects on its financial statements. |
|
|
(u) |
|
Recently adopted accounting pronouncements |
|
|
|
|
The following standards and interpretations became effective during 2009: |
|
- |
|
In March 2009, IASB published amendments to IFRIC 9 and IAS 39: Embedded
derivatives. The amendment clarifies the treatment of embedded derivatives for
entities that make use of the reclassification amendment issued by the IASB in
October 2008. The reclassification amendment allows entities to reclassify
particular financial instruments out of the at fair value through profit or loss
category in specific circumstances. The amendments to IFRIC 9 and IAS 39 issued
clarify that on reclassification of a financial asset out of the at fair value
through profit or loss category all embedded derivatives have to be assessed and,
if necessary, separately accounted for in financial statements. |
|
|
- |
|
In March 2009, IASB published amendments to IFRS 7 Financial Instruments:
Disclosures. The amendments provide enhanced disclosure about fair value
measurements and reinforce existing principles for disclosures about liquidity risk.
Disclosures introduce a three-level hierarchy for fair value measurement disclosures
and require entities to provide additional disclosures about the relative reliability
of fair value measurements. These disclosures will help to improve comparability
between entities about the effects of fair value measurements. |
|
|
- |
|
In January 2008, the IASB issued revised IAS 32, Financial Instruments:
Disclosure and Presentation, which requires certain financial instruments to be
classified as equity when |
21
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
they are available and impose an obligation on the Companys equity. This standard will
be effective for accounting periods beginning on or after January 1, 2009. |
|
|
- |
|
In September 2007 the IAS 1, Presentation of Financial Statements was revised
and introduced a statement of comprehensive income, which includes the profit or
loss for the period and other comprehensive income containing income and expense
items not recognized in the results for the period due to requirements of other
standards. In addition, according to this standard, the balance sheet will become
the statement of financial position since it better reflects the function of the
statement and is consistent with the terms used in the Concept Framework of
International Accounting Standards. |
|
|
- |
|
In March 2007 was revised IAS 23, Borrowing Costs eliminates the option to
expense borrowing costs and requires capitalization of borrowing costs directly
attributable to the acquisition, construction or production of a qualifying asset as
part of the cost of that asset. |
|
|
|
The Companys accounting policies have been revised and modified, when necessary, to adopt
the requirements established in these new standards or interpretations. Adoption of these
standards and interpretations did not significantly affect the Companys financial
statements. |
|
(4) |
|
Exchange Agreement with the Central Bank of Venezuela (BCV) |
|
|
|
|
On November 21, 2005, the Ministry of Finance and BCV published Exchange Agreement No. 9,
which establishes that foreign currency obtained from hydrocarbon exports, including gaseous
hydrocarbons, must be sold to BCV, except for foreign currency earmarked for activities
conducted by PDVSA in conformity with the BCV Law Reform. Under this agreement, PDVSA and
its subsidiaries may not maintain foreign currency funds in Venezuela for more than 48 hours,
and establishes how these funds will be used by PDVSA and monthly information to be presented
to BCV in respect of foreign currency flows generated by its activities, asset and liability
positions in foreign currency, and payments made by PDVSA abroad. |
|
|
|
|
Exchange Agreement No. 2 of February 6, 2004 was amended on March 2, 2005 to establish
exchange rates of Bs. 2,144.60/US$1 (Bs.F. 2.14) (purchase) and Bs. 2,150/US$1 (Bs.F. 2.15)
(sale) (See Note 21). |
|
(5) |
|
Determination of Fair Values |
|
|
|
|
Certain of the Companys accounting policies and disclosures require the determination of
fair values for financial and non-financial assets and liabilities. Fair values have been
estimated for purposes of valuation and disclosure using available market information and
appropriate |
22
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
valuation methods. Additional information on fair value estimates is disclosed in the
specific notes to the assets and liabilities. |
|
|
|
|
The fair value of property, plant and equipment recognized as a result of a business
acquisition is essentially based on market values and other suitable valuation methods. The
market value of assets is the estimated amount at which these assets could be exchanged on
the valuation date between a willing buyer and seller in an arms length transaction wherein
the parties had each acted knowledgeably, prudently and without compulsion. |
|
|
|
|
The fair value of recoverable tax credits and other liabilities has been determined by
discounting net cash flows expected to be generated by the asset, using interest rates
applicable in the monetary market. |
|
|
|
|
The carrying value of cash and cash equivalents, accounts receivable, prepaid expenses and
other assets, and accounts payable to suppliers approximates their estimated fair value due
to the short-term maturities of these instruments. |
|
|
|
|
The net carrying value of the account payable to PDVSA approximates the estimated fair value
since its payment depends on the volume and nature of transactions conducted by the Company
with the Parent Company and its subsidiaries. |
|
(6) |
|
Financial Risk Management |
|
|
|
|
Local and international conditions, i.e., recession periods, inflation, interest rates,
devaluation, and hydrocarbon price volatility may have a significant effect on the Companys
financial position. The Company is exposed to a variety of financial risks: market risk
(including exchange rate fluctuation risk, interest rate risk and price risk), liquidity risk
and capital risk. Financial
instruments exposed to concentration of credit risk consist primarily of cash and trade
accounts receivable. |
|
|
|
|
At December 31, 2009 and 2008, the Companys cash is placed with a local and foreign
financial institution. In addition, there is some concentration of credit risk in trade
accounts receivable since all crude oil and gas produced is sold to PDVSA Petróleo. |
|
|
|
|
Market risk |
|
|
|
|
The Companys general risk management focuses on the uncertainty surrounding financial
markets and seeks to minimize the potential adverse effects on the Companys performance. At
December 31, 2009 and 2008, the Company is exposed to the following market risks: |
|
|
|
|
Exchange rate fluctuation risk |
|
|
|
|
The Company operates in Venezuela and is exposed to foreign exchange risk from variations in
the exchange rate of the Venezuelan Bolívar relative to the U.S. dollar. Foreign exchange
risk is mainly derived from future commercial operations and assets and liabilities shown in
bolivars. |
23
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
Price risk |
|
|
|
|
The Company is exposed to risks stemming from changes in the sale price of hydrocarbons,
which depend on external market factors. At December 31, 2009 and 2008, hydrocarbon sales
prices are calculated based on predetermined formulas that consider the price of hydrocarbons
in different international markets. Price fluctuations may have a significant impact on the
Companys income. At December 31, 2009 and 2008, the Company has no mechanisms in place to
protect against exposure to hydrocarbon sales price fluctuations. |
|
|
|
|
Interest rate fluctuation risk |
|
|
|
|
The Company has accounts receivable from PDVSA which earn interest on arrears 45 days after
bills are due and are, therefore, exposed to interest rate fluctuation. |
|
|
|
|
Capital risk management |
|
|
|
|
The Company is focused on safeguarding its ability to continue as a going concern in order to
provide returns for the shareholders and maintain an optimal capital structure to reduce
capital costs. In order to maintain or adjust the capital structure, the Company may adjust
the amount of dividends paid to shareholders, return capital to shareholders or issue new
shares. |
|
|
|
|
Liquidity risk |
|
|
|
|
Handling prudently liquidity risk implies maintaining sufficient funds in cash and short term
marketable securities, as well as having working capital credit facility available. The
Company permanently evaluates its future cash flows through short and long term projections
from estimated sales and cash requirements which correspond mainly to operation and
maintenance of production facilities, payment of payroll, payment of fiscal and financial
obligations, etc. |
|
(7) |
|
Taxes |
|
|
|
|
Below is a summary of taxes affecting the Companys operations, stated in thousands: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|
U.S. Dollars |
|
Bolivars |
Income tax |
|
|
61,946 |
|
|
|
16,814 |
|
|
|
133,184 |
|
|
|
36,150 |
|
Royalties (See Note 7-b) |
|
|
157,681 |
|
|
|
225,167 |
|
|
|
339,014 |
|
|
|
484,109 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
219,627 |
|
|
|
241,981 |
|
|
|
472,198 |
|
|
|
520,259 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
(a) |
|
Income tax |
|
|
|
|
Net income tax expense is summarized below, stated in thousands: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|
U.S. Dollars |
|
Bolivars |
Estimated income tax expense |
|
|
(105,868 |
) |
|
|
(69,374 |
) |
|
|
(227,616 |
) |
|
|
(149,154 |
) |
Deferred income tax |
|
|
43,922 |
|
|
|
52,560 |
|
|
|
94,432 |
|
|
|
113,004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
(61,946 |
) |
|
|
(16,814 |
) |
|
|
(133,184 |
) |
|
|
(36,150 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation between the nominal and the effective income tax rates for each year
is shown below: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
2009 |
|
2008 |
|
|
|
|
|
|
Thousands |
|
|
|
|
|
Thousands |
|
|
% |
|
U.S. Dollars |
|
Bolivars |
|
% |
|
U.S. Dollars |
|
Bolivars |
Income tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
143,284 |
|
|
|
308,059 |
|
|
|
|
|
|
|
121,217 |
|
|
|
260,617 |
|
Income tax |
|
|
|
|
|
|
61,946 |
|
|
|
133,184 |
|
|
|
|
|
|
|
16,814 |
|
|
|
36,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before income tax |
|
|
|
|
|
|
205,230 |
|
|
|
441,243 |
|
|
|
|
|
|
|
138,031 |
|
|
|
296,767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil-sector nominal income tax rate |
|
|
50 |
|
|
|
102,615 |
|
|
|
220,621 |
|
|
|
50 |
|
|
|
69,016 |
|
|
|
148,383 |
|
Tax inflation adjustment and effect
from translation into U.S. dollars |
|
|
(11 |
) |
|
|
(23,096 |
) |
|
|
(49,655 |
) |
|
|
(28 |
) |
|
|
(38,697 |
) |
|
|
(83,199 |
) |
Deferred income tax |
|
|
(21 |
) |
|
|
(43,922 |
) |
|
|
(94,432 |
) |
|
|
(38 |
) |
|
|
(52,560 |
) |
|
|
(113,004 |
) |
Non-deductible provisions and other |
|
|
13 |
|
|
|
26,349 |
|
|
|
56,650 |
|
|
|
28 |
|
|
|
39,055 |
|
|
|
83,970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective rate |
|
|
30 |
|
|
|
61,946 |
|
|
|
133,184 |
|
|
|
12 |
|
|
|
16,814 |
|
|
|
36,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The partial reform of the Income Tax Law, published in Official Gazette No. 38,529 on
September 25, 2006, repealed investment tax credits applicable to companies engaged in
hydrocarbon production and related activities, and prohibits application of tax credits
available for activities other than those related to hydrocarbons. |
|
|
|
|
Prevailing and former Venezuelan Income Tax Law allows tax losses to be carried forward
for three years to offset taxable income, except losses arising from the annual inflation
adjustment, which may be carried forward for only one year. |
25
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
Venezuelan Income Tax Law requires an initial inflation adjustment to compute taxable
income. The Law provides that the initially adjusted values of property, plant and
equipment should be depreciated or amortized for tax purposes over the remaining useful
lives of such assets. The Law also requires that an annual inflation adjustment be
included in income tax reconciliation as a taxable or deductible item. |
|
|
|
|
According to the Income Tax Law, taxpayers subject to this tax that conduct import, export
and loan transactions with related parties abroad are required to calculate income, costs
and deductions applying the methodology set out in the Law. The Company conducts no
transactions with related parties abroad. |
|
|
|
|
Official Gazette No. 38,529 of the Bolivarian Republic of Venezuela, published on
September 25, 2006, modifies Article No. 11 of the Law regarding the rate applicable to
companies engaged in hydrocarbon production and related activities, establishing a 50%
general rate. However, only companies that conduct integrated or non-integrated
activities related to exploration and production of non-associated gas, and processing,
transportation, distribution, storage, marketing and export of gas and its components, or
those exclusively engaged in refining of hydrocarbons or enhancement of heavy and
extra-heavy crude oil are subject to a 34% tax rate. Therefore, application of the 34%
rate for companies incorporated under the joint venture agreements executed under the
superseded Law Reserving Hydrocarbon Trade and Industry to the State is eliminated. |
|
|
|
|
The components of deferred income tax expense at December 31, 2008 and 2009 shown in the
results of each year are as follows (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit |
|
|
|
|
2008 |
|
Recognized in |
|
|
|
|
Assets |
|
results |
|
2009 Assets |
In U.S. dollars- |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
|
|
|
|
(2,653 |
) |
|
|
(2,653 |
) |
Property, plant and equipment |
|
|
66,004 |
|
|
|
38,552 |
|
|
|
104,556 |
|
Inventories |
|
|
5,184 |
|
|
|
(664 |
) |
|
|
4,520 |
|
Accruals and other payables |
|
|
26,135 |
|
|
|
8,687 |
|
|
|
34,822 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
97,323 |
|
|
|
43,922 |
|
|
|
141,245 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In bolivars- |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
|
|
|
|
(5,704 |
) |
|
|
(5,704 |
) |
Property, plant and equipment |
|
|
141,909 |
|
|
|
82,887 |
|
|
|
224,796 |
|
Inventories |
|
|
11,145 |
|
|
|
(1,428 |
) |
|
|
9,717 |
|
Accruals and other payables |
|
|
56,190 |
|
|
|
18,677 |
|
|
|
74,867 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
209,244 |
|
|
|
94,432 |
|
|
|
303,676 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
(b) |
|
Royalties |
|
|
|
|
Royalties are paid based on crude oil produced and associated natural gas processed in
Venezuela. Volumes of hydrocarbons produced in traditional areas are taxed with a 30%
rate. |
|
|
|
|
The partial reform of the Hydrocarbon Law was approved in May 2006, whereby operators
should pay 33.33% of the wellhead value of each barrel to the Venezuelan government by
means of royalties and additional taxes. |
|
|
|
|
On November 14, 2006, a new calculation of royalties was established for companies that
conduct primary oil activities in the country requiring that contents of sulphur and API
gravity of liquid hydrocarbons extracted be measured on a monthly basis and be reported
together with taxed production. This information will be part of the royalty payment
price and will be used for calculation of any special advantage. This information will
result in adjustments for gravity and sulphur, which will be published by Ministry for
Energy and Oil (MPPEP). |
|
|
|
|
The Company pays MPPEP a 30% royalty in kind for crude oil produced and associated natural
gas transferred to PDVSA Petróleo, S.A. Royalty expenses for 2009 and 2008 amounted to
US$137,925 thousands and US$149,605 thousands (Bs 296,538 thousands and Bs 321,651
thousands), respectively, included in the income statement under Royalties. |
|
|
|
|
The Company is subject to special advantage taxes, which are determined based on: a) an
interest as additional royalty of 3.33% on volumes of hydrocarbons extracted in the
delimited areas and delivered to Petróleos de Venezuela, S.A. and b) an amount equivalent
to the difference, if any, between (i) 50% of the value of the hydrocarbons extracted in
the delimited areas and delivered to Petróleos de Venezuela, S.A. in each calendar year
and (ii) the sum of payments made by the mixed companies to the Bolivarian Republic of
Venezuela, for activities developed during the calendar year, for royalties on
hydrocarbons and investments in endogenous development projects, equivalent to 1% of
pre-tax income. Taxes for special advantages must be paid before April 20 of each year,
pursuant to Exhibit F of the Agreement for Conversion into a Mixed Company. In relation
to a) above, Petrodelta, S.A. incurred in this tax during 2009 and 2008 for US$15,548
thousands and US$16,030 thousands (Bs 33,428 thousands and Bs 34,464 thousands),
respectively, included in the statements of comprehensive income under royalties. In
relation to b) above, at December 31, 2009 and 2008, this special advantage tax was lower
than what the Company paid and accrued for royalties and special advantages tax. |
|
|
|
|
Official Gazette No. 39.273 of the Bolivarian Republic of Venezuela, published on
September 28, 2009, approved the modification of article regulating special advantages tax
levied on mix companies to redistribute the use of funds by the additional royalty of
3.33% that mix
companies have to pay on hydrocarbons volumes extracted from delimited areas. The modified
article establish deliver 1.11% to municipalities where oil activities in the country take
place and 2.22% for a special fund to be administered by the Executive branch to finance
endogenous development projects. |
27
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
Following a detail of the caused royalties is shown: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|
Dollars |
|
Bolivars |
Royalty on oil production |
|
|
135,442 |
|
|
|
138,311 |
|
|
|
291,200 |
|
|
|
297,369 |
|
Royalty on gas production |
|
|
2,483 |
|
|
|
11,294 |
|
|
|
5,338 |
|
|
|
24,282 |
|
Royalty for the municipalities |
|
|
8,613 |
|
|
|
10,687 |
|
|
|
18,518 |
|
|
|
22,977 |
|
Royalty for endogenous development
projects |
|
|
6,935 |
|
|
|
5,343 |
|
|
|
14,910 |
|
|
|
11,487 |
|
Surface tax |
|
|
1,946 |
|
|
|
1,596 |
|
|
|
4,184 |
|
|
|
3,431 |
|
Windfall tax |
|
|
882 |
|
|
|
56,377 |
|
|
|
1,896 |
|
|
|
121,211 |
|
Accrual for investments in social project |
|
|
1,380 |
|
|
|
1,559 |
|
|
|
2,968 |
|
|
|
3,352 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
157,681 |
|
|
|
225,167 |
|
|
|
339,014 |
|
|
|
484,109 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) |
|
Extraction tax |
|
|
|
|
The Venezuelan Hydrocarbon Law Reform establishes a rate equivalent to 33.33% of the value
of all liquid hydrocarbons extracted from any reservoir, calculated on the same basis as
for royalties. The taxpayer may deduct from the extraction tax any sum payable as
royalties, including the additional royalty paid as special advantage. This tax is
effective since 2006. The Company incurred no tax in this connection for 2009 and 2008. |
|
|
(d) |
|
Value added tax (VAT) |
|
|
|
|
A Partial Reform of the Value Added Tax Law was published in Official Gazette No. 38,632
on February 26, 2007 changing the applicable tax rate from 14% to 11% as from March 1
until June 30, 2007 and to 9% as from July 1, 2007. On March 26, 2009, under Official
Gazette No. 39,147 modification of applicable tax rate to 12% was published, having effect
from April 1, 2009. |
|
|
|
|
The VAT Law establishes an exemption on trading of certain hydrocarbon-derived fuels.
Recoverable amounts bear no interest. |
|
|
|
|
Below is a summary of the movement of recoverable tax credits (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|
U.S. dollars |
|
Bolivars |
Recoverable amounts at the beginning of the year |
|
|
9,604 |
|
|
|
|
|
|
|
20,649 |
|
|
|
|
|
Generate during the year |
|
|
10,110 |
|
|
|
9,604 |
|
|
|
21,736 |
|
|
|
20,649 |
|
Adjustment to net realizable value |
|
|
(1,792 |
) |
|
|
|
|
|
|
(3,853 |
) |
|
|
|
|
Recoverable amounts at end of the year |
|
|
17,922 |
|
|
|
9,604 |
|
|
|
38,532 |
|
|
|
20,649 |
|
28
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
At the end of 2009, the Company adjusted the amount of recoverable tax credits to the net
realizable value applying a discount rate for assets deterioration of 13%. This rate is
calculated by its main shareholder annually with the financial statements of the prior
year and using outside parameters updated each year. At December 31, 2009, the adjustment
for US$1,792 thousands (Bs. 3,853 thousands) is included in the statement of comprehensive
income under the category of financial expenses. |
|
|
(e) |
|
Law on Special Contributions over Extraordinary Prices of the International
Hydrocarbons Market |
|
|
|
|
In April 2008, the Venezuelan government, by means of a decree-law, established a special
contribution over extraordinary prices of the international hydrocarbons market, amended
in July 2008, which levies the sale of crude oil whenever the average price for the month
in question of the Venezuelan oil production exceeds the price of US$70/barrel. The amount
of said contribution equals 50% of the difference resulting of the average price per month
and the aforementioned cap of US$70/barrel. In addition, this decree-law sets forth that
whenever the average price per month exceeds the price of US$100/barrel, the total amount
of said special contribution will be equivalent to 60% of the above defined difference. |
|
(8) |
|
Property, Plant and Equipment, Net |
|
|
|
|
Property, plant and equipment, net at December 31 comprises the following (in
thousands): |
29
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells and |
|
|
|
|
|
|
|
|
production |
|
Furniture and |
|
Construction in |
|
|
|
|
facilities |
|
equipment |
|
progress |
|
Total |
Cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2007 |
|
|
215,581 |
|
|
|
2,821 |
|
|
|
|
|
|
|
218,402 |
|
Additions |
|
|
|
|
|
|
916 |
|
|
|
38,431 |
|
|
|
39,347 |
|
Transfers |
|
|
7,485 |
|
|
|
|
|
|
|
(7,485 |
) |
|
|
|
|
Strategic Inventories |
|
|
4,279 |
|
|
|
|
|
|
|
|
|
|
|
4,279 |
|
Assets retirement obligations |
|
|
10,866 |
|
|
|
|
|
|
|
|
|
|
|
10,866 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008 |
|
|
238,211 |
|
|
|
3,737 |
|
|
|
30,946 |
|
|
|
272,894 |
|
Additions |
|
|
|
|
|
|
3,729 |
|
|
|
77,696 |
|
|
|
81,425 |
|
Transfers |
|
|
75,730 |
|
|
|
|
|
|
|
(75,730 |
) |
|
|
|
|
Strategic inventories |
|
|
1,842 |
|
|
|
|
|
|
|
|
|
|
|
1,842 |
|
Asset retirement obligations |
|
|
3,603 |
|
|
|
|
|
|
|
|
|
|
|
3,603 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009 |
|
|
319,386 |
|
|
|
7,466 |
|
|
|
32,912 |
|
|
|
359,764 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2007 |
|
|
34,572 |
|
|
|
1,054 |
|
|
|
|
|
|
|
35,626 |
|
Depreciation and amortization |
|
|
21,677 |
|
|
|
730 |
|
|
|
|
|
|
|
22,407 |
|
Assets retirement obligations |
|
|
3,101 |
|
|
|
|
|
|
|
|
|
|
|
3,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008 |
|
|
59,350 |
|
|
|
1,784 |
|
|
|
|
|
|
|
61,134 |
|
Depreciation and amortization |
|
|
30,198 |
|
|
|
1,095 |
|
|
|
|
|
|
|
31,293 |
|
Assets retirement obligations |
|
|
1,895 |
|
|
|
|
|
|
|
|
|
|
|
1,895 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009 |
|
|
91,443 |
|
|
|
2,879 |
|
|
|
|
|
|
|
94,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net cost at December 31, 2009 |
|
|
227,943 |
|
|
|
4,587 |
|
|
|
32,912 |
|
|
|
265,442 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net cost at December 31, 2008 |
|
|
178,861 |
|
|
|
1,953 |
|
|
|
30,946 |
|
|
|
211,760 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells and |
|
|
|
|
|
|
|
|
production |
|
Furniture and |
|
Construction in |
|
|
|
|
facilities |
|
equipment |
|
progress |
|
Total |
Cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2007 |
|
|
463,500 |
|
|
|
6,065 |
|
|
|
|
|
|
|
469,565 |
|
Additions |
|
|
|
|
|
|
1,969 |
|
|
|
82,627 |
|
|
|
84,596 |
|
Transfers |
|
|
16,093 |
|
|
|
|
|
|
|
(16,093 |
) |
|
|
|
|
Strategic Inventories |
|
|
9,200 |
|
|
|
|
|
|
|
|
|
|
|
9,200 |
|
Assets retirement obligations |
|
|
23,362 |
|
|
|
|
|
|
|
|
|
|
|
23,362 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008 |
|
|
512,155 |
|
|
|
8,034 |
|
|
|
66,534 |
|
|
|
586,723 |
|
Additions |
|
|
|
|
|
|
8,017 |
|
|
|
167,045 |
|
|
|
175,062 |
|
Transfers |
|
|
162,819 |
|
|
|
|
|
|
|
(162,819 |
) |
|
|
|
|
Strategic inventories |
|
|
3,959 |
|
|
|
|
|
|
|
|
|
|
|
3,959 |
|
Asset retirement obligations |
|
|
7,745 |
|
|
|
|
|
|
|
|
|
|
|
7,745 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009 |
|
|
686,678 |
|
|
|
16,051 |
|
|
|
70,760 |
|
|
|
773,489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2007 |
|
|
74,329 |
|
|
|
2,267 |
|
|
|
|
|
|
|
76,596 |
|
Depreciation and amortization |
|
|
46,606 |
|
|
|
1,570 |
|
|
|
|
|
|
|
48,176 |
|
Assets retirement obligations |
|
|
6,667 |
|
|
|
|
|
|
|
|
|
|
|
6,667 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008 |
|
|
127,602 |
|
|
|
3,837 |
|
|
|
|
|
|
|
131,439 |
|
Depreciation and amortization |
|
|
64,926 |
|
|
|
2,352 |
|
|
|
|
|
|
|
67,278 |
|
Assets retirement obligations |
|
|
4,074 |
|
|
|
|
|
|
|
|
|
|
|
4,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009 |
|
|
196,602 |
|
|
|
6,189 |
|
|
|
|
|
|
|
202,791 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net cost at December 31, 2009 |
|
|
490,076 |
|
|
|
9,862 |
|
|
|
70,760 |
|
|
|
570,698 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net cost at December 31, 2008 |
|
|
384,553 |
|
|
|
4,197 |
|
|
|
66,534 |
|
|
|
455,284 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the years ended December 31, 2009 and 2008, the Company made additions to
production assets and construction in progress for approximately US$81,425 thousands and
US$39,347 thousands (Bs 175,062 thousands and Bs 84,596 thousands), respectively. |
|
|
|
During 2009 and 2008, the Company assessed asset impairment, taking into account new market
and business conditions, and determined that there was no evidence of impairment of production
assets. |
31
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
At December 31, 2009 and 2008, accruals and other payables include US$3,603 thousands and
US$10,866 thousands (Bs 7,745 thousands and Bs 23,362 thousands), respectively, in respect of
the accrual for asset retirement obligations (See Note 9). |
|
|
|
The balance of construction in progress mainly comprises investment projects for exploration
and production activities related to drilling, maintenance, electrical systems, pipelines,
well reconditioning and adaptation, expansion and infrastructure aimed at maintaining
production capacity and adapting the infrastructure to production levels set out in the
Corporations business plan. At December 31, 2009 and 2008, the balance of construction in
progress for investments related to the aforementioned activities amounts to approximately
US$32,912 thousands and US$30,946 (Bs 70,760 thousands and Bs 66,534 thousands). |
(9) Accrual for Asset Retirement Obligations
|
|
The movement of the accrual for asset retirement obligations at December 31 is shown below
(in thousands): |
|
|
|
|
|
|
|
|
|
|
|
U.S. dollars |
|
Bolivars |
Balance at December 31, 2007 |
|
|
5,964 |
|
|
|
12,823 |
|
|
|
|
|
|
|
|
|
|
Change on estimation |
|
|
10,866 |
|
|
|
23,362 |
|
Financial cost |
|
|
2,344 |
|
|
|
5,039 |
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008 |
|
|
19,174 |
|
|
|
41,224 |
|
|
|
|
|
|
|
|
|
|
Change on estimation |
|
|
3,603 |
|
|
|
7,745 |
|
Financial cost |
|
|
1,639 |
|
|
|
3,523 |
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009 |
|
|
24,416 |
|
|
|
52,492 |
|
|
|
|
|
|
|
|
|
|
|
|
During 2009, Company management reviewed, based on new information, estimates on
assumptions used for calculating the provision for abandonment costs. |
|
|
|
At December 31, 2009 and 2008, the variation of the estimation in of the provision for well
abandonment cost of US$3,603 thousands and US$10,866 thousands (Bs 7,745 thousands and Bs
23,362 thousands) is includes the balance of Property, plant and equipment (See Note 8). The
Petrodelta, S.A. business plan as of December 31, 2009, contemplates the realization of
hydrocarbons drilling and production activities until the year 2025; therefore, the accrual
for asset retirement obligations was calculated based on the disbursements for this concept
during this period. |
32
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
(10) Prepaid Expenses and Other Assets
Prepaid expenses and other assets comprise the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|
U.S. dollars |
|
Bolivars |
Prepaid income tax |
|
|
|
|
|
|
20,876 |
|
|
|
|
|
|
|
44,883 |
|
Prepaid insurance |
|
|
458 |
|
|
|
472 |
|
|
|
984 |
|
|
|
1,016 |
|
Prepaid services |
|
|
62 |
|
|
|
88 |
|
|
|
134 |
|
|
|
189 |
|
Prepaid rent |
|
|
39 |
|
|
|
41 |
|
|
|
84 |
|
|
|
88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
559 |
|
|
|
21,477 |
|
|
|
1,202 |
|
|
|
46,176 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated tax paid during 2008 exceeded the final tax liability by US$20,876 thousands
(Bs 44,883 thousands), and was used to offset part of 2009 tax liability. |
(11) Inventories
|
|
A summary of inventories is shown below (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|
U.S. dollars |
|
Bolivars |
Materials and supplies, net |
|
|
33,586 |
|
|
|
24,663 |
|
|
|
72,211 |
|
|
|
53,026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33,586 |
|
|
|
24,663 |
|
|
|
72,211 |
|
|
|
53,026 |
|
Less: Materials and supplies
classified under other non-current assets (See Note 8) |
|
|
12,114 |
|
|
|
10,272 |
|
|
|
26,044 |
|
|
|
22,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,472 |
|
|
|
14,391 |
|
|
|
46,167 |
|
|
|
30,941 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12) Accounts Receivable
|
|
Accounts receivable comprise the following (in thousands): |
33
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
U.S. Dollars |
|
|
Bolivars |
|
Related parties (See Note 19) |
|
|
361,137 |
|
|
|
257,292 |
|
|
|
776,445 |
|
|
|
553,178 |
|
Recoverable tax credits (See Note 7 and 17) |
|
|
17,922 |
|
|
|
9,604 |
|
|
|
38,532 |
|
|
|
20,649 |
|
Other |
|
|
673 |
|
|
|
890 |
|
|
|
1,448 |
|
|
|
1,913 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
379,732 |
|
|
|
267,786 |
|
|
|
816,425 |
|
|
|
575,740 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13) Cash and cash equivalents
|
|
Cash and cash equivalent comprises the following (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
U.S. Dollars |
|
|
Bolivars |
|
Cash on hand |
|
|
3 |
|
|
|
2 |
|
|
|
7 |
|
|
|
4 |
|
Cash at banks |
|
|
3,059 |
|
|
|
7,361 |
|
|
|
6,575 |
|
|
|
15,826 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,062 |
|
|
|
7,363 |
|
|
|
6,582 |
|
|
|
15,830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14) Equity
|
|
Capital stock |
|
|
|
At December 31, 2009 and 2008, the Companys nominal capital stock is represented by
1,500,000 common shares, fully authorized and paid in, with a par value of US$4.65 each (Bs
10 each). |
|
|
|
The Companys capital stock is divided into two types of shares: Class A and Class B
shares. Only the Venezuelan government or Venezuelan state-owned companies can own Class A
shares. In October 2007, when the Company was incorporated, shareholders made an initial
capital contribution of approximately Bs 1,000 thousands (US$465,000). Capital stock has
been fully subscribed and paid in as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders |
|
Type of shares |
|
|
Number of shares |
|
|
US$ |
|
|
Bs. |
|
|
Share of equity |
|
Corporación Venezolana del Petróleo, S.A. (CVP) |
|
|
A |
|
|
|
900,000 |
|
|
|
4,186,047 |
|
|
|
9,000,000 |
|
|
|
60 |
% |
HNR Finance, B.V. (HNR Finance) |
|
|
B |
|
|
|
600,000 |
|
|
|
2,790,698 |
|
|
|
6,000,000 |
|
|
|
40 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000 |
|
|
|
6,976,745 |
|
|
|
15,000,000 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
Contributions for future capital increases |
|
|
|
In November 2007, the shareholders made contributions for future capital increases of
approximately US$6,512 thousands, equivalent to approximately Bs 14,000 thousands. In August
2008, this contribution was capitalized in compliance with Article No. 1, Paragraph 1.4 of
the Agreement for Conversion into a Mixed Company. |
|
|
|
Legal reserve |
|
|
|
Venezuelan companies are required to set aside a legal reserve. According to Venezuelan Law,
the legal reserve is not available for dividend distribution. |
|
|
|
At December 31, 2008, the Company has set aside a legal reserve of approximately US$651
thousands, equivalent to Bs 1,400 thousands, equivalent to 10% of capital stock. |
|
|
|
Deferred tax asset equity reserve |
|
|
|
In June 2009, CVP issued instructions to all mixed companies regarding the accounting for
deferred tax assets. The mixed companies have been instructed to set up a reserve within the
equity section of the balance sheet for deferred tax assets. The setting up of the reserve
had no effect on the Company financial position, results of operations or cash flows.
However, the new reserve reduces the amount of dividends received in the future. |
|
|
|
On August 2009, the Board of Directors of the Company approved the creation of the deferred
tax asset equity reserve with retained earnings accumulated to end of June 2009 for
US$116,273 thousands (Bs.249.987 thousands). At December 31, 2009 management has recorded as
equity reserve and amount equal to the balance of deferred tax asset at that date equivalent
to US$141,245 thousands (Bs.303,676 thousands) and which has been approved by the Board of
Directors of the Company. |
|
|
|
Share premium |
|
|
|
The share premium is in respect of contributions of fixed assets and inventories made by
shareholders in conformity with the Agreement for Conversion into a Mixed Company, whose
value exceeds the par value of common shares issued. At December 31, 2009 and 2008, the
share premium amounts to approximately US$212,451 thousands, equivalent to approximately Bs
456,770 thousands, included in equity. |
|
|
|
Class A share premiums are in respect of fixed assets contributed by CVP. The value of
this share premium amounts to approximately US$191,206 thousands, equivalent to
approximately Bs 411,093 thousands, pursuant to Exhibit H of the Agreement for Conversion
into a Mixed Company. |
|
|
|
Class B share premiums are in respect of fixed assets and inventories contributed by HNR
Finance. The value of this share premium amounts to approximately US$21,245 thousands, |
35
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
equivalent to approximately Bs 45,677 thousands, pursuant to Exhibit G of the Agreement for
Conversion into a Mixed Company. |
|
|
|
In conformity with the Companys bylaws, in case of Company liquidation, all assets will be
transferred only to the Class A shareholder. |
|
|
|
Dividends |
|
|
|
On May 2008, the shareholders resolved to pay dividends of US$181,325 thousands, equivalent
to Bs 389,846 thousands, out of unappropriated retained earnings for December 2007. |
|
|
|
On August 2008, the shareholders resolved to pay dividends in advance based on retained
earnings as the end of June 2008 of US$51,876 thousands, equivalent to Bs 111,533 thousands.
The dividend in advance approved was paid to HNR Finance for its share in the Company in the
amount of US$20,750 thousands, equivalent to Bs 44,612 thousands. At December 31, 2009 the
Company decided to record the dividend in advance against unappropriated retained earnings at
the end of 2009, recording as dividends payable the unpaid portion to CVP for an amount of
US$31,126 thousands equivalent to Bs 66,921 thousands. |
|
|
Accounts payable comprise the following (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
U.S. dollars |
|
|
Bolivars |
|
Trade |
|
|
35,021 |
|
|
|
8,536 |
|
|
|
75,295 |
|
|
|
18,353 |
|
Related parties (See Note 19) |
|
|
70,311 |
|
|
|
80,568 |
|
|
|
151,170 |
|
|
|
173,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
105,332 |
|
|
|
89,104 |
|
|
|
226,465 |
|
|
|
191,574 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency and liquidity risk exposure in respect of accounts payable to suppliers
is shown in Note 17. |
36
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
(16) |
|
Accruals and Other Payables |
|
|
Accruals and other payables at December 31 comprise the following: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
U.S. dollars |
|
|
Bolivars |
|
Royalties |
|
|
49,277 |
|
|
|
44,017 |
|
|
|
105,946 |
|
|
|
94,637 |
|
Provision for abandonment cost (See Note 9) |
|
|
24,416 |
|
|
|
19,174 |
|
|
|
52,492 |
|
|
|
41,224 |
|
Provision for retirement benefits |
|
|
9,184 |
|
|
|
1,306 |
|
|
|
19,746 |
|
|
|
2,808 |
|
Endogenous and social development |
|
|
5,728 |
|
|
|
4,347 |
|
|
|
12,315 |
|
|
|
9,346 |
|
LOCTISEP |
|
|
6,392 |
|
|
|
3,056 |
|
|
|
13,743 |
|
|
|
6,570 |
|
Other |
|
|
93,466 |
|
|
|
118,404 |
|
|
|
200,952 |
|
|
|
254,569 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
188,463 |
|
|
|
190,304 |
|
|
|
405,194 |
|
|
|
409,154 |
|
Less: Non current portion of accruals and other payables |
|
|
33,600 |
|
|
|
20,480 |
|
|
|
72,238 |
|
|
|
44,032 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term portion |
|
|
154,863 |
|
|
|
169,824 |
|
|
|
332,956 |
|
|
|
365,122 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2009 and 2008, included as non-current liabilities: a) US$24,416 thousands
and US$19,174 thousands, (Bs 52,492 thousands and Bs 41,224 thousands), in respect of the
provision for abandonment cost for retirement obligations for exploration and production
assets. Asset retirement costs and obligations related to the main structures used in drilling
activities were not estimated because these assets have an indefinite useful life as a result
of maintenance and mayor repairs and no information is available to reasonably determine their
retirement date; and b) US$9,184 thousands and US$1,306 thousands, (Bs.19,746 thousands and Bs.
2,808 thousands), as provision for retirement benefits for personnel assigned to the Company.
During 2009, PDVSA completed an actuarial study for their pension and retirement plan. This
pension and retirement plan covers all PDVSA employees and mixed companies payroll. In
May 2009, PDVSA sent a statement to the Company for its respective costs associated with the
pension and retirement plan. The pension adjustment was for past service costs covering the
period from January 2008, when HVSCA employees were migrated to PDVSA payroll. It is a
non-recurring adjustment. Pension costs at the end of 2009 recorded in the books reasonably
reflect the Companys employee demographic and plan conditions. Pension cost is not tax
deductible until future periods when the pension is settled in cash. The Company is not
required to reimburse the pension costs to PDVSA until PDVSA pays. |
|
|
|
Additionally, at December 31, 2009 and 2008, under other, it is included the accruals in
respect of drilling services and infrastructure totaling US$47,892 thousands and US$50,845
thousands (Bs 102,968 thousands and Bs 109,317 thousands), approximately, and a special contribution over
the extraordinary prices of the international hydrocarbons market totaling US$882 thousands and
US$56,377 thousands (Bs 1,896 thousands and Bs 121,211 thousands). |
37
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
Below are the movements of accruals and other payables during 2009 (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at |
|
|
|
|
|
|
|
|
|
|
Balance at |
|
|
|
|
|
|
Long- |
|
|
|
December 31, |
|
|
|
|
|
|
|
|
|
|
December |
|
|
Current |
|
|
term |
|
|
|
2008 |
|
|
Increase |
|
|
Decrease |
|
|
31, 2009 |
|
|
portion |
|
|
portion |
|
U.S. dollars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties |
|
|
44,017 |
|
|
|
5,260 |
|
|
|
|
|
|
|
49,277 |
|
|
|
49,277 |
|
|
|
|
|
Provision for abandonment cost
(See Note 9) |
|
|
19,174 |
|
|
|
5,242 |
|
|
|
|
|
|
|
24,416 |
|
|
|
|
|
|
|
24,416 |
|
Provision for retirement benefits |
|
|
1,306 |
|
|
|
7,878 |
|
|
|
|
|
|
|
9,184 |
|
|
|
|
|
|
|
9,184 |
|
Endogenous and social development |
|
|
4,347 |
|
|
|
1,381 |
|
|
|
|
|
|
|
5,728 |
|
|
|
5,728 |
|
|
|
|
|
LOCTISEP |
|
|
3,056 |
|
|
|
3,336 |
|
|
|
|
|
|
|
6,392 |
|
|
|
6,392 |
|
|
|
|
|
Other |
|
|
118,404 |
|
|
|
|
|
|
|
(24,938 |
) |
|
|
93,466 |
|
|
|
93,466 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total accruals and other payables |
|
|
190,304 |
|
|
|
23,097 |
|
|
|
(24,938 |
) |
|
|
188,463 |
|
|
|
154,863 |
|
|
|
33,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bolivars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties |
|
|
94,637 |
|
|
|
11,309 |
|
|
|
|
|
|
|
105,946 |
|
|
|
105,946 |
|
|
|
|
|
Provision for abandonment cost
(See Note 9) |
|
|
41,224 |
|
|
|
11,268 |
|
|
|
|
|
|
|
52,492 |
|
|
|
|
|
|
|
52.492 |
|
Provision for retirement benefits |
|
|
2,808 |
|
|
|
16,938 |
|
|
|
|
|
|
|
19,746 |
|
|
|
|
|
|
|
19,746 |
|
Endogenous and social development |
|
|
9.346 |
|
|
|
2,969 |
|
|
|
|
|
|
|
12,315 |
|
|
|
12,315 |
|
|
|
|
|
LOCTISEP |
|
|
6,570 |
|
|
|
7,173 |
|
|
|
|
|
|
|
13,743 |
|
|
|
13,743 |
|
|
|
|
|
Other |
|
|
254,569 |
|
|
|
|
|
|
|
(53,617 |
) |
|
|
200,952 |
|
|
|
200,952 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total accruals and other payables |
|
|
409,154 |
|
|
|
49,657 |
|
|
|
(53,617 |
) |
|
|
405,194 |
|
|
|
332,956 |
|
|
|
72,238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17) |
|
Financial Instruments |
|
|
Credit Risk |
|
|
|
Exposure to Credit Risk |
|
|
|
The book value of financial assets represents the highest level of credit risk exposure. A
breakdown is shown below (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
U.S. dollars |
|
|
Bolivars |
|
Accounts receivable (Note 12) |
|
|
361,137 |
|
|
|
257,292 |
|
|
|
776,445 |
|
|
|
553,178 |
|
Recoverable tax credits (See Note 7 and 12) |
|
|
17,922 |
|
|
|
9,604 |
|
|
|
38,532 |
|
|
|
20,649 |
|
Accounts receivable other (See Note 12) |
|
|
673 |
|
|
|
890 |
|
|
|
1,448 |
|
|
|
1,913 |
|
Cash and cash equivalents |
|
|
3,062 |
|
|
|
7,363 |
|
|
|
6,582 |
|
|
|
15,830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
382,794 |
|
|
|
275,149 |
|
|
|
823,007 |
|
|
|
591,570 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
Aging of the account receivables are shown below (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
U.S. dollars |
|
|
Bolivars |
|
Under 30 days |
|
|
136,755 |
|
|
|
232,822 |
|
|
|
294,022 |
|
|
|
500,568 |
|
Between 31 and 180 days |
|
|
113,666 |
|
|
|
24,470 |
|
|
|
244,383 |
|
|
|
52,610 |
|
Between 180 days and one year |
|
|
109,186 |
|
|
|
|
|
|
|
234,751 |
|
|
|
|
|
More than one year |
|
|
1,530 |
|
|
|
|
|
|
|
3,289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
361,137 |
|
|
|
257,292 |
|
|
|
776,445 |
|
|
|
553,178 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquidity risk |
|
|
|
Maturity of financial liabilities, including estimated interest payments and excluding the
impact of offset agreements, is shown below (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Book value |
|
|
Contractual cash flows |
|
|
|
|
|
|
6 months or less |
|
|
|
|
|
|
|
|
|
|
Non-derivative financial liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
U.S. dollars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable to suppliers (See Note 15) |
|
|
35,021 |
|
|
|
8,536 |
|
|
|
35,021 |
|
|
|
8,536 |
|
|
|
35,021 |
|
|
|
8,536 |
|
|
Bolivars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable to suppliers (See Note 15) |
|
|
75,295 |
|
|
|
18,353 |
|
|
|
75,295 |
|
|
|
18,353 |
|
|
|
75,295 |
|
|
|
18,353 |
|
|
|
Foreign Currency Risk |
|
|
|
Petrodelta, S.A. has the following monetary assets and liabilities denominated in currencies
other than the U.S. dollar, which were converted into U.S. dollars at the exchange rate in
effect at the balance sheet date (in thousands): |
39
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Monetary assets: |
|
|
|
|
|
|
|
|
Bolivars |
|
|
391,383 |
|
|
|
254,740 |
|
|
|
|
|
|
|
|
|
|
|
391,383 |
|
|
|
254,740 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Monetary liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bolivars |
|
|
691,588 |
|
|
|
342,635 |
|
|
|
|
|
|
|
|
|
|
|
691,588 |
|
|
|
342,635 |
|
|
|
|
|
|
|
|
Net monetary liability position |
|
|
(300,205 |
) |
|
|
(87,895 |
) |
|
|
|
|
|
|
|
|
|
The year-end exchange rate, the average exchange rate for the year and the interannual
increases in the exchange rate and the Consumer Price Index (CPI), as published by BCV, were
as follows: |
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Exchange rate at year end (Bs./US$1) |
|
|
2.15 |
|
|
|
2.15 |
|
|
|
|
|
|
|
|
Average exchange rate for the year (Bs./US$1) |
|
|
2.15 |
|
|
|
2.15 |
|
|
|
|
|
|
|
|
Interannual increase in the CPI (%) |
|
|
25,06 |
|
|
|
30.90 |
|
|
|
|
|
|
|
|
|
|
Fair Value of Financial Instruments |
|
|
|
The following estimated amounts do not necessarily reflect the amounts at which the
instruments could be exchanged in the current market. The use of different market
assumptions and valuation methods can significantly affect the estimated fair values. The
bases for determining the fair value are disclosed in Note 5 (in thousands): |
40
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
Book |
|
|
Fair |
|
|
Book |
|
|
Fair |
|
|
Book |
|
|
Fair |
|
|
Book |
|
|
Fair |
|
|
|
value |
|
|
value |
|
|
value |
|
|
value |
|
|
value |
|
|
value |
|
|
value |
|
|
value |
|
|
|
|
U.S. dollars |
|
|
|
|
Bolivars |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
361,137 |
|
|
|
361,137 |
|
|
|
257,292 |
|
|
|
257,292 |
|
|
|
776,445 |
|
|
|
776,445 |
|
|
|
553,178 |
|
|
|
553,178 |
|
Recoverable tax credits |
|
|
19,714 |
|
|
|
17,922 |
|
|
|
9,604 |
|
|
|
9,604 |
|
|
|
42,385 |
|
|
|
38,532 |
|
|
|
20,649 |
|
|
|
20,649 |
|
Accounts receivable other |
|
|
673 |
|
|
|
673 |
|
|
|
890 |
|
|
|
890 |
|
|
|
1,448 |
|
|
|
1,448 |
|
|
|
1,913 |
|
|
|
1,913 |
|
Cash and cash equivalents |
|
|
3,062 |
|
|
|
3,062 |
|
|
|
7,363 |
|
|
|
7,363 |
|
|
|
6,582 |
|
|
|
6,582 |
|
|
|
15,830 |
|
|
|
15,830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable to suppliers |
|
|
35,021 |
|
|
|
35,021 |
|
|
|
8,536 |
|
|
|
8,536 |
|
|
|
75,295 |
|
|
|
75,295 |
|
|
|
18,353 |
|
|
|
18,353 |
|
Other liabilities (included in
accruals and other payables) |
|
|
154,863 |
|
|
|
154,863 |
|
|
|
169,824 |
|
|
|
169,824 |
|
|
|
332,956 |
|
|
|
332,956 |
|
|
|
365,122 |
|
|
|
365,122 |
|
Accounts and dividends
payables to shareholders and
related companies |
|
|
101,437 |
|
|
|
101,437 |
|
|
|
80,568 |
|
|
|
80,568 |
|
|
|
218,091 |
|
|
|
218,091 |
|
|
|
173,221 |
|
|
|
173,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(18) |
|
Commitments, Contingencies and Claims |
|
|
At December 31, 2009 and 2008, the Company has not set aside a provision for litigations and
other claims. Should the outcome of existing lawsuits and claims be unfavorable to the
Company, it could have a material adverse effect on its results of operations. Although it is
not possible to predict the outcome, Company management, based in part on the opinion of its
legal advisors, does not believe it is likely that losses related to the aforementioned legal
procedures will exceed recognized estimated amounts or generate significant amounts that
could affect the Companys financial position or results of operations. |
|
|
|
Environmental Protection |
|
|
|
The subsidiaries of CVP are subject to different environmental laws and regulations which may
require significant expenditures to modify facilities and prevent or remedy the environmental
effects from waste disposal and spills of pollutants. |
|
|
|
Petrodelta, S.A. and its parent company CVP are taking steps to prevent environmental risks,
protect employee health and preserve the integrity of their facilities. |
|
|
|
Conditions that require additional expenditures may exist at various sites including, but not
limited to, CVPs operating complexes and crude oil storage terminals. Company management
believes that these matters, in the normal course of operations, will not significantly
affect the Companys financial position or liquidity in the results of its operations. |
41
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
Agreements with the Organization of Petroleum Exporting Countries (OPEC) |
|
|
|
The Bolivarian Republic of Venezuela is a member of OPEC, an organization mainly dedicated to
establishing agreements to maintain stable crude oil prices by setting production quotas. To
date, the reduction in crude oil production resulting from changes in the production quotas
set by OPEC and price fluctuations has not significantly affected the Companys results of
operations, cash flows or financial results. |
(19) |
|
Related Party Transactions |
|
|
Petrodelta, S.A. considers its shareholders and related subsidiaries and affiliates, Company
directors and executives, as well as other governmental institutions, as related parties. |
|
|
|
A summary of transactions and balances with related parties is shown below (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
U.S. dollars |
|
|
Bolivars |
|
Activities for the year: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas sales |
|
|
458,251 |
|
|
|
474,619 |
|
|
|
985,239 |
|
|
|
1,020,431 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
35,442 |
|
|
|
21,298 |
|
|
|
76,200 |
|
|
|
45,791 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General, administrative and selling
expenses |
|
|
6,589 |
|
|
|
3,506 |
|
|
|
14,167 |
|
|
|
7,538 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties (See Note 7) |
|
|
137,925 |
|
|
|
149,605 |
|
|
|
296,538 |
|
|
|
321,651 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reimbursement of expenses |
|
|
149,058 |
|
|
|
272,852 |
|
|
|
320,475 |
|
|
|
586,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at the end of the year: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable (See Note 12) |
|
|
361,137 |
|
|
|
257,292 |
|
|
|
776,445 |
|
|
|
553.178 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid dividends-B Partners (See Note 14) |
|
|
|
|
|
|
20,750 |
|
|
|
|
|
|
|
44,612 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable to Shareholders (See Note 15) |
|
|
4,060 |
|
|
|
2,327 |
|
|
|
8,729 |
|
|
|
5,003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends payable-A Partners (See Note 14) |
|
|
31,126 |
|
|
|
|
|
|
|
66,921 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable to PDVSA (See Note 15) |
|
|
66,251 |
|
|
|
78,241 |
|
|
|
142,441 |
|
|
|
168,218 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of April 2006, due to the migration of operating agreements to mixed companies, PDVSA
Petróleo signed purchase and sale agreements with these companies, which set out that mixed
companies will notify PDVSA Petróleo of the estimated volume of hydrocarbons expected to be
delivered the following month. PDVSA Petróleo must pay the mixed companies for delivered
volumes, net of volumes for royalties in kind and paid to the Venezuelan government. |
|
|
|
In conformity with the terms and conditions of the agreements, CVP mixed companies agree
to sell and deliver to PDVSA Petróleo, and the latter agrees to purchase and receive from
these mixed companies, crude oil and natural gas produced in the delimited areas that are not
used for primary activities or for payment of royalties in kind to the Venezuelan government. |
42
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
Crude oil delivered from the Petrodelta fields to PDVSA is priced with reference to Merey 16
published prices, weighted for different markets and adjusted for variations in gravity and
sulphur content, commercialization costs and distortions that may occur given the reference
price and prevailing market conditions. Market prices for crude oil of the type produced in
the fields operated by Petrodelta averaged approximately $57.62 and $84.52 per barrel for the
year ended December 31, 2009 and 2008, respectively. |
|
|
|
During the years ended December 31, 2009 and 2008, the Company sold crude oil and natural gas
to PDVSA Petróleo for US$458,251 thousands and US$474,619 thousands (Bs 985,239 thousands and
Bs 1,020,431 thousands), respectively, included in the income statement under Income. At
December 31, 2009 and 2008, the statement of financial position includes US$361,137 thousands
and US$257.292 thousands (Bs 776,445 thousands and Bs 553.178 thousands) of accounts
receivable in this connection. |
|
|
|
During 2009 and 2008, PDVSA Petróleo charged Petrodelta, S.A. US$261 million and US$370
million (Bs 561 million and Bs 798 million), respectively, for labor and other costs,
included in general, administrative and selling expenses. |
|
|
|
Certain Company directors hold key positions in other related entities; some of their
attributions include influencing the operational and financial policies of these entities. |
|
|
|
At December 31, 2009 and 2008, transactions with related parties do not necessarily reflect
the results that would have been obtained had these transactions been held with third
parties. |
|
|
|
At a Board of Directors Meeting in December 2008, it was resolved to offset receivables and
payables with PDVSA and its affiliates. In this regard, it was established that 75% of
accounts receivable and 100% of accounts payable and billed to PDVSA would be recorded with
no interest charges. Subsequently, in December 2008, CVP agreed to offset the remaining
unbilled accounts payable. During 2009, in February, July and November it was resolved to
offset receivables and payables between PDVSA and the Company. As a result, accounts payable
in respect of reimbursement of capital costs and operating expenses were offset against
accounts receivable in respect of estimated hydrocarbons extracted and transferred to PDVSA
in accordance with the purchase sale agreement. |
(20) |
|
Laws, Resolutions and Legal Contributions |
|
a) |
|
Laws Decreed within the Framework of the Enabling Law |
|
|
|
|
On July 31, 2008, 26 laws were decreed within the framework of the Enabling Law concerning
economic, social, legal, and military matters. The following are among the most important
laws approved in the social, administrative and financial areas: |
|
- |
|
Decree No. 6,071 for the Agro-Food Security and Sovereignty Law published
in Official Gazette No. 5,889. |
43
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
- |
|
Decree No. 6,128 for the Law for the Creation of the Social Fund Aimed at
Gathering and Disposing of Excess Resources of Government Entities published in
Official Gazette No. 5,890. |
|
|
- |
|
Decree No. 6,215 for the Law for Fostering and Developing Small and
Medium-sized Industries and Units of Social Property published in Official Gazette
No. 5,890. |
|
|
- |
|
Decree No. 6,217 for the Public Administration Law published in Official
Gazette No. 5,890. |
|
|
- |
|
Decree No. 6,233 for the Reform of the Public Sector Financial
Administration Law published in Official Gazette No. 5,891. |
|
|
- |
|
Decree No. 6,265 for the Law for the Simplification of Administrative
Formalities published in Official Gazette No. 5,891. |
|
|
|
|
Company management and its legal advisors are assessing the possible impact of these laws
on PDVSA. |
|
b) |
|
Law for Special Contributions on Extraordinary International Hydrocarbon Market
Prices |
|
|
|
|
On April 15, 2008, the Law for Special Contributions on Extraordinary International
Hydrocarbon Market Prices was published in Official Gazette No. 38,910. Subsequently,
Resolutions No. 151 and No. 195 of MPPEP were published in Official Gazette No. 38,939 of
May 27, 2008 and Official Gazette No. 38,970 of July 10, 2008. This Law and its
resolutions require entities that export or transport liquid hydrocarbons and hydrocarbon
derivatives abroad to pay a special monthly contribution. The contribution will be
equivalent to: a) 50% of the difference between the average monthly price of the
Venezuelan crude oil basket and the threshold price of US$70 per barrel and b) 60% of the
difference between the average monthly price of the Venezuelan crude oil basket and the
threshold price over US$100 per barrel. This contribution shall be paid on every barrel of
oil exported or transported abroad and shall be collected and paid monthly by MPPEP to
FONDEN for execution of infrastructure development projects, production and social
development projects aimed at strengthening Communal Power. This Law became effective on
April 15, 2008. |
|
|
c) |
|
Law on Narcotic and Psychotropic Substances |
|
|
|
|
The Law on Narcotic and Psychotropic Substances was published in Official Gazette No.
38,287 on December 16, 2005. This Law repeals the previous Law of September 30, 1993 and
requires all companies, public or private, with 50 or more employees to earmark 1% of
their annual net income for social programs for the prevention of illegal drug consumption
and traffic, one-half of which is to be set aside for child welfare protection programs. |
44
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
In December 29, 2009 providence 007-2009 was published in Official Gazette No. 39,336
whereas the National Anti-Drug Agency (ONA) establishes norms and procedures to collect,
control and fiscalize contributions by public and private companies. The providence among
other things lay out the amount subject to the calculation set as taxable income and not
net income applied in prior years. During the years ended December 31, 2009 and 2008, the
Company recorded an expense of approximately US$3,336 thousands and US$1,224 thousands (Bs
7,173 thousands and Bs 2.633 thousands), respectively, in this connection, included in the
income statement for each year under General and administrative expenses, net. As a result
of the change in the methodology used to calculate the contribution from applying the
providence No. 007-2009, for the amount recorded during the year ended December 31, 2009
approximately US$1.082 thousands and US$168 thousands (Bs.2.327 thousands y Bs.362
thousands), correspond to 2008 and 2007, respectively. |
|
|
d) |
|
Financial Transaction Tax Law |
|
|
|
|
On October 5, 2007, the Venezuelan government enacted by Decree the Tax on Financial
Transactions for Incorporated and Unincorporated Entities. This tax is levied upon all
financial transactions performed by incorporated and unincorporated entities. The tax
rate was set at 1.5% as from November 1, 2007 until December 31, 2008. |
|
|
e) |
|
Enabling Law |
|
|
|
|
On February 1, 2007, the National Assembly approved the Enabling Law granting the
Venezuelan president special powers for 18 months to pass decrees governing different
areas of national interest, including transformation of state institutions, popular,
economic and social participation, as well as financial, tax and energy-related matters. |
|
|
f) |
|
Law for the Advancement of Science, Technology and Innovation |
|
|
|
|
The Law for the Advancement of Science, Technology and Innovation was enacted in August
2005. This Law establishes that, beginning January 1, 2006, the countrys major
corporations will annually earmark 0.5% of gross income generated in Venezuela to support
activities which, according to the Law, relate to investments in science, technology and
innovation. This Law defines major corporations as those whose annual gross income exceeds
100,000 tax units. In addition, Article No. 35 of the aforementioned Law requires major
corporations in the country engaged in activities covered by the Hydrocarbon and Gaseous
Hydrocarbon Law to contribute 2% a year of their gross income generated in Venezuela from
any of the activities specified in Article No. 42 of this Law. This Laws Regulations will
establish the mechanisms, methods and procedures for mandatory contributions from major
corporations, as well as the timeframe and procedures that must be complied with for the
purpose of determining which activities will be considered by the Ministry of Science and
Technology in connection with these contributions. At December 31, 2009 and 2008 following
instructions |
45
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
from its shareholder CVP, the Company Management did not record any provision
related to the contribution establish in the Law for the Advancement of Science,
Technology and Innovation. According with these instructions, PDVSA will file on
consolidated basis the contribution established in this Law. |
|
a) |
|
Exchange Agreement No. 14 |
|
|
|
|
On January 8, 2010, the Ministry of Finance and BCV published Exchange Agreement No. 14,
which establishes a dual exchange rate of Bs.2.60/1US$ for essentials imports and
Bs.4.30/1US$ for other concepts. This agreement allows for the purchase and sale of
currency for the following concepts at the Bs 2,60/1US$: |
|
I. |
|
Imports for food, health, education, machinery and equipment, science
and technology, according to commercial policy set by the Executive branch. |
|
|
II. |
|
Remittance of funds to famillies living abroad. |
|
|
III. |
|
Payments to students undergoing academic activities outside the
country. |
|
|
IV. |
|
Payments of expenses for health recovery, sport, culture, scientific
investigations and other cases of urgent matter authorized by CADIVI. |
|
|
V. |
|
Payments to retired individuals living abroad. |
|
|
VI. |
|
Purchase of currency by diplomatic representations, consulates,
embassies and public individuals assigned to International organizations
accredited by the goverment. |
|
|
VII. |
|
The Exchange Agreement establishes that the parchase and sale of
currency for operations different than those mentioned above are to be at Bs 4,30
/U$1. |
|
|
|
This agreement did not have an effect on the Companys right to maintain foreign currency
funds at financial institutions outside the country on revenues proceeds from sale of
crude in order to make payments and disbursements outside the country. |
|
|
b) |
|
Labor Collective Contract |
|
|
|
|
On January 12, 2010 a pre-agreement was reached among PDVSA and oil labor union (FUTPV)
regarding the approval of the new labor contract and the impact on labor cost affecting
mix companies. The pre-agreement establish a salary raise and payroll and retirement
benefits which has a significant impact on the Companys payroll cost. The most
significant impacts are: |
|
I. |
|
A salary raise of Bs.35 daily which represents an increase of
80% of current salary. The increase shall be pay in two portions, the first of
Bs.25 at the signing of the contract and the second of Bs.10 from January
1st, 2011. |
|
|
II. |
|
An increase in the monthly amount for electronic food from
Bs.1.300 to Bs. 1.700. |
|
|
III. |
|
An increase in the retirement benefit from Bs. 1.000 to Bs.
1.600. |
|
|
IV. |
|
The increase will be retroactively from October 1, 2009 and not
from January 21, 2009, date which expired the prior contract, in compensation
it was agreed a one- |
46
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
|
time bonus of Bs. 8.000 which has no effect in the
severance benefits of employees. |
|
|
|
The impact of the new collective contract, according to the changes mentioned above, has
been estimated and is reflected in the statement of comprehensive income of the Company. |
(22) |
|
Subsequent events after Independents Accountant Opinion |
|
|
|
On February 4, 2010, providence No. 0002344 from the National Integrated Service on Tributes
and Customs Administration (SENIAT) was published in Official Gazette No. 39,361 in which the
current tax unit value was adjusted from Bs. 55 to Bs. 65. |
|
|
|
On February 26, 2010, the Board of Directors of the Company approved the issuance of the
financial statements under International Financial Reporting Standards and submitted said
financial statements to the Shareholders of the Company for approval purposes. |
(23) |
|
Supplementary Information on Oil and Gas Exploration and Production Activities (unaudited) |
|
|
|
The following tables provide supplementary information on oil and gas exploration,
development and production activities. All exploration and production activities are
conducted mainly by CVP and Mixed Companies in Venezuela. |
|
|
|
Table I Crude Oil and Natural Gas Reserves |
|
|
|
All crude oil and natural gas reserves located in Venezuela are owned by the Bolivarian
Republic of Venezuela. Crude oil and natural gas reserves are estimated by PDVSA and
reviewed by the Peoples Power Ministry for Energy and Oil using reserve criteria that are
consistent with those prescribed by the American Petroleum Institute (API) of the United
States of America. |
|
|
|
Proved reserves are the estimated quantities of crude oil and gas which, with reasonable
certainty, are recoverable in future years from known deposits under existing economic and
operating conditions. Due to the inherent uncertainties and limited nature of reservoir data,
reserve estimates are subject to changes over time, as additional information becomes
available. Proved reserves do not include additional volumes which may result from the
extension of currently explored areas or from the application of secondary recovery processes
not yet tested and determined to be economically feasible. |
|
|
|
Proved developed oil and gas reserves are the quantities that can be recovered from existing
wells with existing equipment and methods. Proved undeveloped reserves are those volumes
that are expected to be recovered from new wells on undrilled acreage or from existing wells. |
47
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
A summary of annual changes in proved crude oil and natural gas reserves is shown below: |
|
(a) |
|
Conventional Crude Oil (in thousands of barrels) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31 |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Proved developed and undeveloped
reserves of conventional crude oil
at January 1 |
|
|
214,658 |
|
|
|
220,163 |
|
|
|
225,537 |
|
Revisions |
|
|
|
|
|
|
|
|
|
|
|
|
Expansions and discoveries |
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(7,835 |
) |
|
|
(5,505 |
) |
|
|
(5,374 |
) |
|
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped
reserves of conventional crude oil
at December 31 |
|
|
206,823 |
|
|
|
214,658 |
|
|
|
220,163 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves of
conventional crude oil at December
31 (included on the previous
amount) |
|
|
54,110 |
|
|
|
47,298 |
|
|
|
52,803 |
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2009, 2008 and 2007, certified reserves assigned to the Company amounted
to 206,823 thousands, 214,658 thousands and 220,163 thousands barrels, respectively.
Production for the year ended December 31, 2009, 2008 and 2007 was 7,835 thousands, 5,505
thousands and 5,374 thousands barrels. |
|
(b) |
|
Natural Gas Reserves (in millions of cubic feet) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31 |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Proved developed and undeveloped reserves of natural
gas at January 1 |
|
|
273,281 |
|
|
|
283,981 |
|
|
|
297,437 |
|
Revisions |
|
|
(2,592 |
) |
|
|
|
|
|
|
|
|
Expansions and discoveries |
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(4,397 |
) |
|
|
(10,700 |
) |
|
|
(13,456 |
) |
|
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves of natural
gas at December 31 |
|
|
266,292 |
|
|
|
273,281 |
|
|
|
283,981 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves of natural
gas at December 31 (included on the previous amount) |
|
|
25,641 |
|
|
|
32,630 |
|
|
|
43,330 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas production is shown on the basis of actual volumes before the extraction of
liquefiable hydrocarbons. |
48
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
Table II Costs Incurred in Exploration and Development Activities |
|
|
|
Exploration costs include costs incurred from geological and geophysical activities, and
drilling and equipping exploratory wells. The Company did not conduct exploration activities
in 2009. Development costs include those for drilling and equipping development wells,
enhanced recovery projects and facilities to extract, treat and store crude oil and natural
gas. Annual costs, summarized below, include amounts both expensed and capitalized for the
Companys conventional crude oil reserves (In thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional Crude |
|
|
|
U.S. dollars |
|
|
Bolivars |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Development costs |
|
|
83,141 |
|
|
|
53,576 |
|
|
|
178,753 |
|
|
|
115,188 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred from development activities |
|
|
83,141 |
|
|
|
53,576 |
|
|
|
178,753 |
|
|
|
115,188 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Table III Costs Recorded as Assets in Oil and Gas Production Activities |
|
|
|
Costs recorded as assets for oil and gas exploration and production activities, as well as
the related accumulated depreciation and amortization at December 31 for PDVSAs conventional
and extra-heavy crude oil reserves are summarized below (In thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional Crude |
|
|
|
U.S. dollars |
|
|
Bolivars |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Assets used in production |
|
|
319,386 |
|
|
|
238,211 |
|
|
|
686,678 |
|
|
|
512,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equipment and facilities |
|
|
7,466 |
|
|
|
3,737 |
|
|
|
16,051 |
|
|
|
8,034 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
326,852 |
|
|
|
241,948 |
|
|
|
702,729 |
|
|
|
520,189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Depletion, depreciation
and amortization |
|
|
(94,322 |
) |
|
|
(61,134 |
) |
|
|
(202,791 |
) |
|
|
(131,439 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Construction in progress |
|
|
32,912 |
|
|
|
30,946 |
|
|
|
70,760 |
|
|
|
66,534 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net costs capitalized as assets |
|
|
265,442 |
|
|
|
211,760 |
|
|
|
570,698 |
|
|
|
455,284 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2009 and 2008
|
|
Table IV Results of Operations for Oil and Gas Production Activities for Each Year (In
thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional Crude |
|
|
|
Years ended December 31 |
|
|
|
U.S. Dollar |
|
|
Bolivars |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Net production income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
458,251 |
|
|
|
474,619 |
|
|
|
985,239 |
|
|
|
1,020,431 |
|
Production costs |
|
|
(59,152 |
) |
|
|
(84,314 |
) |
|
|
(127,176 |
) |
|
|
(181,275 |
) |
Royalties |
|
|
(157,681 |
) |
|
|
(225,167 |
) |
|
|
(339,014 |
) |
|
|
(484,109 |
) |
Depletion, depreciation and amortization |
|
|
(32,571 |
) |
|
|
(24,778 |
) |
|
|
(70,029 |
) |
|
|
(53,273 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operation before income Tax |
|
|
208,847 |
|
|
|
140,360 |
|
|
|
449,020 |
|
|
|
301,774 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax |
|
|
(105,868 |
) |
|
|
(69,374 |
) |
|
|
(227,616 |
) |
|
|
(149,154 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results production operation |
|
|
102,979 |
|
|
|
70,986 |
|
|
|
221,404 |
|
|
|
152,620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from oil production is calculated at international market price as if all
production were sold. |
|
|
|
Production costs are lifting costs incurred to operate and maintain productive wells and
related facilities and equipment, including operating labor costs, materials, supplies, fuel
consumed in operations and operating costs of natural liquid gas plants. |
|
|
|
Depreciation and amortization expenses relate to assets used in exploration and production
activities. Income tax expense is computed using the statutory rate for the year. For these
purposes, the results of production operations do not include finance costs and corporate
overhead nor their associated tax effects. |
|
|
|
A summary of average per unit sale prices and production costs is shown below: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31 |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
U.S. dollar |
|
|
Bolivars |
|
Average sale price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil per barrel |
|
|
57.62 |
|
|
|
84.52 |
|
|
|
123.88 |
|
|
|
181.72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas per barrel |
|
|
1.54 |
|
|
|
1.54 |
|
|
|
3.31 |
|
|
|
3.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average production cost per BOE |
|
|
6.90 |
|
|
|
11.57 |
|
|
|
14.84 |
|
|
|
24.88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50