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, 2010
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
(State or other jurisdiction of incorporation or organization)
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77-0196707
(I.R.S. Employer Identification Number) |
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1177 Enclave Parkway, Suite 300
Houston, Texas
(Address of principal executive offices)
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77077
(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
(Do not check if a smaller reporting company)
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Smaller Reporting Company o |
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, 2010 was: $244,559,410.
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, 2011,
shares outstanding: 33,974,691.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrants Proxy Statement for the 2011 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, as
amended [the PSLRA]) contained in this report or made by management of the Company involve risks
and uncertainties and are subject to change based on various important factors. When used in this
report, the words budget, guidance, forecast, expect, believes, goals, projects,
plans, anticipates, estimates, should, could, assume and similar expressions are
intended to identify forward-looking statements. In accordance with the provisions of the PSLRA,
we caution you that important factors could cause actual results to differ materially from those in
the forward-looking statements. Such factors include our concentration of operations in Venezuela,
the political and economic risks associated with international operations (particularly those in
Venezuela), the anticipated future development costs for undeveloped reserves, drilling risks, the
risk that actual results may vary considerably from reserve estimates, the dependence upon the
abilities and continued participation of certain of our key employees, the risks normally incident
to the exploration, operation and development of oil and natural gas properties, risks incumbent to
being a noncontrolling interest shareholder in a corporation, the permitting and the drilling of
oil and natural gas wells, the availability of materials and supplies necessary to projects and
operations, the price for oil and natural gas and related financial derivatives, changes in
interest rates, the Companys ability to acquire oil and natural gas properties that meet its
objectives, availability and cost of drilling rigs, seismic crews, overall economic conditions,
political stability, civil unrest, acts of terrorism, currency and exchange risks, currency
controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in
governmental policy, availability of sufficient financing, changes in weather conditions, and
ability to hire, retain and train management and personnel. 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 a petroleum exploration and production company incorporated
under Delaware law in 1989. Our focus is on acquiring exploration, development and producing
properties in geological basins with proven active hydrocarbon systems. Our experienced technical,
business development and operating personnel have identified low entry cost exploration
opportunities in areas with large hydrocarbon resource potential. We operate from our Houston,
Texas headquarters. We also have regional/technical offices in the United Kingdom and Singapore,
and small field offices in Jakarta, Republic of Indonesia (Indonesia); Muscat, Sultanate of Oman
(Oman); and Roosevelt, Utah to support field operations in those areas.
We have acquired and developed significant interests in the Bolivarian Republic of Venezuela
(Venezuela). Our Venezuelan interests are owned through HNR Finance, B.V. (HNR Finance). Our
ownership of HNR Finance is through several corporations in all of which we have direct controlling
interests. Through these corporations, we indirectly own 80 percent of HNR Finance and our
partner, Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of
Venezolana de Inversiones y Construcciones Clerico, C.A. (Vinccler), indirectly owns the
remaining 20 percent interest of HNR Finance. HNR Finance owns 40 percent of Petrodelta, S.A.
(Petrodelta). As we indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent
interest in Petrodelta (80 percent of 40 percent), and Vinccler indirectly owns eight percent (20
percent of 40 percent). Corporación Venezolana del Petroleo S.A. (CVP) owns the remaining 60
percent of Petrodelta. Petrodelta is governed by its own charter and bylaws and operates a
portfolio of properties in eastern Venezuela including large proven oil fields as well as
properties with very substantial opportunities for both development and exploration. We have
seconded key technical and managerial personnel into Petrodelta and participate on Petrodeltas
board of directors. HNR Finance has a direct controlling interest in Harvest Vinccler S.C.A.
(Harvest Vinccler). Harvest Vincclers main business purposes are to assist us in the management
of Petrodelta and in negotiations with Petroleos de Venezuela S.A. (PDVSA). We do not have a
business relationship with Vinccler outside of Venezuela.
Through the pursuit of technically-based strategies guided by conservative investment
philosophies, we are building a portfolio of exploration prospects to complement the low-risk
production, development and exploration prospects we hold in Venezuela. In addition to our
interests in Venezuela, we hold exploration acreage in the Gulf Coast Region of the United States
through an Area of Mutual Interest (AMI) agreement with two private third
1
parties, mainly onshore West Sulawesi in the Indonesia, offshore of the Republic of Gabon
(Gabon), onshore in Oman and offshore of the Peoples Republic of China (China). We also have
developed acreage in the Antelope project in the Western United States through a Joint Exploration
and Development Agreement (JEDA) in the Monument Butte Extension Appraisal and Development
Project (Monument Butte Extension) and Lower Green River/Upper Wasatch Oil Delineation and
Development Project (Lower Green River/Upper Wasatch) where we have established production.
From time to time we learn of possible third party interests in acquiring ownership in certain
assets within our property portfolio. We evaluate these potential opportunities taking into
consideration our overall property mix, our operational and liquidity requirements, our strategic
focus and our commitment to long-term shareholder value. For example, we have received such
expressions of interest in acquiring some of our international and domestic producing and
exploration assets, and we are currently evaluating these potential opportunities. These
considerations are at a very preliminary stage, and there can be no assurances that our discussions
will continue or that any transaction may ultimately result from our discussions. In September
2010, we announced the retention of Bank of America Merrill Lynch to provide advisory services to
assist us in exploring a broad range of strategic alternatives for enhancing shareholder value.
These alternatives could include, but are not limited to, certain extraordinary transactions,
including, possibly, a sale of assets or a sale or merger of the Company.
As of December 31, 2010, we had total assets of $488.2 million, unrestricted cash of $58.7
million and $81.2 long-term debt. For the year ended December 31, 2010, we had revenues of $10.7
million and net cash used in operating activities of $5.3 million. 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.
In the United States during the year ended December 31, 2010, we completed the Bar F #1-20-3-2
(Bar F) in the Lower Green River/Upper Wasatch. We also drilled, completed, and placed on
production two delineation wells and had five additional wells in various stages of drilling and
completion in the Lower Green River/Upper Wasatch. In the Monument Butte Extension, we completed
the non-operated eight well appraisal and development drilling program and began an additional six
well non-operated expansion program. Also in the Monument Butte Extension, we commenced drilling
of one Harvest operated delineation well.
In Venezuela during the year ended December 31, 2010, Petrodelta drilled and completed 16
development wells. Petrodelta is currently utilizing two drilling rigs and one workover rig.
We received our first comprehensive reserve report covering the Uinta Basin reserves in Utah.
Proved and Probable Reserves (2P) net to Harvest in Utah increased to 15.3 million barrels of oil
equivalent (MMBOE) at December 31, 2010, compared to 0.4 MMBOE at year end 2009. Proved Reserves
in Utah net to Harvest increased to 4.6 MMBOE at December 31, 2010, compared to 0.4 MMBOE at year
end 2009. Proved, Probable and Possible (3P) reserves net to Harvest in Utah increased to 86.4
MMBOE at December 31, 2010, compared to 0.4 MMBOE at year end 2009. These reserve additions are
the result of our successful Antelope project delineation drilling programs conducted during 2010
and ongoing in 2011 in the Lower Green River/Upper Wasatch and Monument Butte Extension.
In addition, we are reporting a reserve increase attributed to Petrodelta. 2P reserves, net
to our 32 percent interest, have increased to 103.6 MMBOE at December 31, 2010, a 24 percent
increase over year end 2009. Proved reserves, net to our 32 percent interest, increased to 50.0
MMBOE at December 31, 2010, an eight percent increase over year end 2009. 3P reserves remain
virtually unchanged from last year. These reserve additions are the result of successful recent
drilling and the extension of Block 5, a previously unproven fault block in the El Salto field and
recent development drilling success in other fields.
In February 2010, we closed an offering of $32.0 million in aggregate principal amount of our
8.25 percent senior convertible notes due March 1, 2013, which resulted in net proceeds to us,
after deducting underwriting discounts, commissions and estimated offering expenses, of
approximately $30.0 million.
In May 2010, our shareholders approved the 2010 Long Term Incentive Plan (the 2010 Plan).
The Plan provides for the issuance of up to 1,700,000 shares of our common stock in satisfaction of
exercised stock options, stock appreciation rights (SARs), restricted stock, restricted stock
units (RSUs) and other stock-based awards to eligible participants including employees,
non-employee directors and consultants of our Company or subsidiaries.
2
See Item 15 Exhibits and Financial Statement Schedules, Notes to Consolidated Financial
Statements, Note 7 Stock Option and Stock Purchase Plans for a description of the terms of the
2010 Plan.
In July 2010, we executed a farm-out agreement with the private third party in the JEDA for
the acquisition of an incremental 10 percent interest in the Antelope Project with an effective
date of July 1, 2010. This acquisition includes all leases, the Mesaverde, the Lower Green
River/Upper Wasatch Oil Delineation and Development Project (Lower Green River/Upper Wasatch) and
the Monument Butte Extension Appraisal and Development Project (Monument Butte Extension). The
acquisition excludes the initial eight wells previously drilled in the Monument Butte Extension.
This acquisition increases our ownership in the Antelope project to 70 percent.
In August 2010, Petrodeltas board of directors declared a dividend of $30.5 million, $12.2
million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received
October 22, 2010. The dividend represents 50 percent of the cash withdrawal rights as shareholders
on Petrodeltas net income as reported under International Financial Reporting Standards (IFRS)
for the year ended December 31, 2009.
In September 2010, our partner in the Budong-Budong Production Sharing Contract (Budong PSC)
exercised their option to increase our acquisition commitment carry obligation by $2.7 million from
$17.2 million to a total of $19.9 million ($7.9 million for acquisition of seismic and $12.0
million for drilling). The additional carry increases our ownership by 7.4 percent to 54.4
percent. The change in ownership interest was approved on March 3, 2011 by the Government of
Indonesia and BPMIGAS, Indonesias oil and gas regulatory authority.
In October 2010, we announced the closing of a $60.0 million term loan facility with MSD
Energy Investments Private II, LLC (MSD Energy), an affiliate of MSD Capital, L.P., as the sole
lender under the term loan facility. Under the terms of the term loan facility, interest is paid
on a monthly basis at the initial rate of 10 percent and the term loan will mature on October 28,
2012. The net proceeds of the term loan facility were approximately $59.5 million, after deducting
fees related to the transaction.
In
November 2010, Petrodeltas board of directors declared a
dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8
million net to our 32 percent interest). The dividend represents the
remaining 50 percent of the cash withdrawal rights as shareholders on
Petrodeltas net income as reported under IFRS for the year
ended December 31, 2009. This dividend is subject to shareholder
approval, and will not be accrued on our consolidated balance sheet
until Petrodelta shareholder approval is received. Shareholder
approval was received on March 14, 2011.
On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by
the operator of the Budong PSC to a third party, which has allowed us to acquire an additional 10
percent equity in the Budong PSC. Closing of this acquisition, which is subject to the approval of
the Government of Indonesia and BPMIGAS, will increase our interest in the Budong PSC to 64.4
percent.
On January 28, 2011, our minority equity investment in Fusion Geophysical, L.L.C.s (Fusion)
69 percent owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an
Agreement and Plan of Merger. We received $1.3 million for our equity investment, subject to
post-closing adjustments, and $0.7 million for the repayment in full of the outstanding balance of
the prepaid service agreement, short term loan and accrued interest.
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 2010.
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 and the opening of our London and Singapore offices, 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.
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, in February 2010, we
incurred indebtedness of $32.0 million in aggregate principal amount of our 8.25 percent senior
convertible notes, and in October 2010, we announced the closing of a $60.0 million term loan
facility with MSD
3
Energy as the sole lender under the term loan facility. We intend to use the net proceeds from the
senior convertible notes and the term loan facility to fund capital expenditures, 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.
Reserves
In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting.
Under the SECs final rule, reserves reported prior to 2009 were not restated. The primary impact
of the SECs final rule on our reserve estimates is the disclosure of probable and possible
reserves. 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.
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.
4
In Venezuela during 2010, Petrodelta drilled 16 wells. Six of the wells were previously
identified Proved Undeveloped (PUD) locations and ten wells were previously classified Probable,
Possible or undefined. In 2010, an additional 24 PUD locations were identified through drilling
activity. At December 31, 2010, Petrodelta had a total of 182 PUD locations identified.
Petrodeltas 2010 business plan, as approved by PDVSA, contemplates sustained drilling activities
through the year 2024 to fully develop the El Salto and Temblador fields. In accordance with this
revised development plan for Petrodelta, HNR Finance has elected to report a portion of their PUDs
to be developed past a five year window. Most PUD locations are scheduled to be drilled within
five years of their first identification; however, there are some PUD locations that are scheduled
to be drilled more than five years
after the PUD locations were first identified. At December 2010,
the proportion of proved reserves expected to be drilled in the sixth
year after initial booking is
21 percent of Proved (BOE) reserves and the proportion drilled in the seventh year is two percent
of Proved (BOE) reserves. As a noncontrolling interest shareholder in Petrodelta, HNR Finance has
limited ability to control the development plans that are periodically prepared and/or approved by
the Venezuelan government. Since this constraint represents a hindrance to development not
experienced by typical operations, inclusion of a portion of the activities planned for year six
and seven represents a fair comparison to operators with assets covered by more flexible regulatory
conditions where increasing rig count can ameliorate a slow development plan.
In the United States, at December 31, 2009, we had three Proved Developed wells and five PUD
locations identified in the Monument Butte area. During 2010, we identified and approved the
development of 41 further locations. A total of 13 wells have been moved to Proved Developed
Producing (PDP) in 2010 including the five PUDs identified at December 31, 2009, and eight other
wells. This results in a total of 16 PDP wells and 43 identified PUD locations at December 31,
2010. We do not have PUDs to be developed past a five year window as this is a relatively new
geographic area for us. We have been developing the area since 2009.
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, 2010.
5
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Oil and |
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Natural |
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NGLs |
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Gas |
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Total |
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(MBls) |
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(MMcf) |
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(MBOE)(1) |
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Proved Developed Reserves: |
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Domestic Utah |
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658 |
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2,476 |
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1,071 |
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International Venezuela(2) |
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13,074 |
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18,281 |
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16,121 |
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Total Proved Developed |
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13,732 |
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20,757 |
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17,192 |
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Proved Undeveloped Reserves: |
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Domestic Utah |
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2,856 |
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4,016 |
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3,525 |
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International Venezuela(2) |
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28,610 |
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31,774 |
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33,906 |
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Total Proved Undeveloped |
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31,466 |
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35,790 |
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37,431 |
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Total Proved Reserves |
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45,198 |
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56,547 |
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54,623 |
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Probable Developed Reserves: |
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Domestic Utah |
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46 |
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95 |
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62 |
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International Venezuela(2) |
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132 |
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54 |
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141 |
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Total Probable Developed |
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178 |
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149 |
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203 |
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Probable Undeveloped Reserves: |
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Domestic Utah |
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8,496 |
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12,709 |
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10,614 |
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International Venezuela(2) |
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50,909 |
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15,339 |
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53,466 |
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Total Probable Undeveloped |
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59,405 |
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28,048 |
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64,080 |
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Total Probable Reserves |
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59,583 |
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28,197 |
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64,283 |
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Possible Developed Reserves: |
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Domestic Utah |
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91 |
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207 |
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126 |
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International Venezuela(2) |
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9 |
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9 |
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Total Possible Developed |
|
|
100 |
|
|
|
207 |
|
|
|
135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Possible Undeveloped Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
Domestic Utah |
|
|
52,526 |
|
|
|
110,616 |
|
|
|
70,962 |
|
International Venezuela(2) |
|
|
111,548 |
|
|
|
32,371 |
|
|
|
116,943 |
|
|
|
|
|
|
|
|
|
|
|
Total Possible Undeveloped |
|
|
164,074 |
|
|
|
142,987 |
|
|
|
187,905 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Possible Reserves |
|
|
164,174 |
|
|
|
143,194 |
|
|
|
188,040 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
MBOE (thousand barrels of oil equivalent) is determined using the approximate heat
content ratio of one barrel of crude oil or condensate to six Mcf of natural gas, which ratio
does not necessarily reflect price equivalency. |
|
(2) |
|
Information represents our net 32 percent ownership interest in Petrodelta. |
Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves as
of December 31, 2010, 2009 and 2008 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 Operation Critical Accounting Policies for additional information on our
reserves.
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 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 Vinccler. 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 to 70 percent interest in the Antelope
prospect in the
6
Western United States covered by a JEDA, a 54.4 percent interest in the 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. 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.
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. 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. As of March 7, 2011, the 2011 budget for Petrodeltas business plan had not yet been
approved by its shareholders. Since Petrodelta only executed approximately 50 percent its 2010
budget primarily due to lack of funding by PDVSA, we do not believe that PDVSA will be able to
provide the support required to execute Petrodeltas proposed 2011 budget.
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.
Petrodelta shareholders intend that the company be self-funding and rely on
internally-generated cash flow to fund operations. Petrodeltas focus in 2010 included utilizing
two rigs to drill both development and appraisal wells for both maintaining production capacity and
appraising the substantial resource base in the El Salto field. Petrodelta contracted a workover
rig in October 2010. Petrodelta began engineering work for expanded production facilities to
handle the expected production from the development and appraisal wells that were expected to be
drilled in 2010.
During 2010, Petrodelta drilled and completed 16 development wells, produced approximately 8.6
million barrels (MBbl) of oil and sold 2.2 billion cubic feet (BCF) of natural gas. Petrodelta
produced an average of 23,455 barrels of oil per day (BOPD) during 2010. Petrodelta also began
the pre-engineering work for production facilities required for the full development of the El
Salto field. Due to delays in rig availability, El Salto facilities project execution and lack of
funding by PDVSA, Petrodelta only spent $101.8 million of its 2010 capital budget of $205.0
million.
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 expected PDVSA to continue
requesting and receiving waivers, Petrodelta did not accrue a liability to LOCTI for the year ended
December 31, 2009. For filing years 2007 and 2008, PDVSA
7
provided Petrodelta with a copy of the
waiver acceptance letter from LOCTI. PDVSA has stated that a waiver was granted for filing year 2009; however, LOCTI has not yet issued the acceptance letter to PDVSA
for the 2009 filing year. The potential exposure to LOCTI for the year ended December 31, 2009
after devaluation is $4.8 million, $2.4 million net of tax ($0.8 million net to our 32 percent
interest). In January 2011, PDVSA informed its consolidating entities, including Petrodelta, that
effective with the 2010 reporting year it would no longer be requesting waivers to file the LOCTI
declaration on a consolidated basis. Based on this information, Petrodelta accrued the 2010
liability to LOCTI in the amount of $4.6 million, $2.3 million net of
tax ($0.7 million net to our
32 percent interest). In December 2010, LOCTI was modified to reduce the amount of contributions
beginning January 2011 to one percent of gross revenues for companies owned by individuals or
corporations and 0.5 percent for companies owned by Venezuela. Petrodeltas rate of contribution
starting in 2011 will be 0.5 percent.
In 2008, the Venezuelan government published in the Official Gazette the Law of Special
Contribution to Extraordinary Prices at the Hydrocarbons International Market (Windfall Profits
Tax). The Windfall Profits Tax is 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). As
instructed by CVP, Petrodelta has applied the Windfall Profits Tax to gross oil production
delivered to PDVSA. The Windfall Profits Tax established a special 50 percent tax to the
Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar
manner, the percentage is increased from 50 percent to 60 percent when the average price of the VEB
exceeds $100 per barrel. The Windfall Profits Tax is reported as expense on the income statement
and is deductible for Venezuelan tax purposes. Petrodelta recorded $14.1 million and $0.9 million
of expense for the Windfall Profits Tax for the years ended December 31, 2010 and 2009,
respectively.
In 2009, under instructions issued by CVP, Petrodelta set up a reserve within the equity
section of the balance sheet for deferred tax assets. 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. Dividends received prior to 2009
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.
On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange
Agreement, which established new exchange rates for the Venezuela Bolivar (Bolivar)/U.S. Dollar
currencies that went into effect on January 11, 2010. Per the Exchange Agreement, each exchange
rate is 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 4.30 Bolivar exchange rate applies to
the oil and gas sector. On January 4, 2011, the Venezuelan government published in the Official
Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate
with an effective date of January 1, 2011. See Item 7 Managements Discussion and Analysis of
Financial Condition and Results of Operations Operations, Venezuela for a description of the
effect the Exchange Agreements are having on our Venezuela operation.
In August 2010, Petrodeltas board of directors declared a dividend of $30.5 million, $12.2
million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received
October 22, 2010. The dividend represents 50 percent of the cash withdrawal rights as shareholders
on Petrodeltas net income as reported under IFRS for the year ended December 31, 2009.
In November 2010, Petrodeltas board of directors declared a dividend of $30.6 million, $12.2
million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents
the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodeltas net income
as reported under IFRS for the year ended December 31, 2009. This dividend is subject to
shareholder approval, and will not be accrued on our consolidated balance sheet until Petrodelta
shareholder approval is received. Shareholder approval was received on
March 14, 2011.
8
Location and Geology
Petrodelta Fields
Uracoa Field
There are currently 83 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.
Tucupita Field
There are currently 14 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.
Bombal Field
East Bombal was drilled in 1992, and currently remains underdeveloped. During 2010, three oil
producing wells were reactivated and are producing in the West Bombal field. The oil is
transported through Petrodeltas pipelines from the West Bombal field to the Uracoa plant
facilities. 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 25 oil producing wells in the field. The fluid produced from Temblador field flows
through two flow stations operated by Petrodelta. During 2010, Petrodelta completed the pipeline
network necessary to completely segregate all of Petrodeltas production out of PDVSAs system. As
of October 1, 2010, 100 percent of the Temblador fields production was flowing through Petrodelta
pipelines directly into PDVSAs sales delivery facilities. 3-D seismic is available over the
entire field.
El Salto Field
The El Salto field was discovered in 1936. Currently there are three oil producing wells 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.
During 2010, the ELS-33 well was drilled and completed in the Lower Jobo sand and began producing
on September 1, 2010. The ELS-33 also drilled a pilot hole which encountered a full column of oil
in a block that was previously unpenetrated and represented a significant expansion of Block 5 in
El Salto field not included in the 2009 reserve report. The ELS-34 well was drilled and completed
in the Lower Jobo sand of the newly identified Block 5 extension and began production in September
2010. The produced oil is transported through temporary facilities to Uracoa plant facilities.
The ELS-33 and ELS-34 wells were restricted in their production rate due to limitations in the
temporary facilities.
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.
9
Petrodelta has a 64-mile pipeline from Uracoa with a nominal 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.
Business Plan of Petrodelta
As of March 7, 2011, the 2011 budget for Petrodeltas business plan had not yet been approved
by its shareholders. Since Petrodelta only executed approximately 50 percent its 2010 budget
primarily due to lack of funding by PDVSA, we do not believe that PDVSA will be able to provide the
support required to execute Petrodeltas proposed 2011 budget. However, Petrodeltas 2011 proposed
business plan includes a planned drilling program to utilize two rigs to drill both development and
appraisal wells for maintaining production capacity, the continued appraisal of the substantial
resource base in the El Salto field and appraising the presently non-producing Isleño field. It
also includes engineering work for production facilities required for the full development of the
El Salto field.
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
In 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.
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. 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. We are the operator and have an initial working interest of 50 percent in West
Bay, the second prospect in the AMI. The first prospect in the AMI was abandoned in 2009 after a
dry hole was drilled. The private third party contributed these two prospects, including 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. The funding
obligation was met during 2009, and all costs are now being shared by the parties in proportion to
their working interests as defined in the AMI.
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.
Location and Geology
The AMI covers the coastal areas from Nueces County, Texas to Cameron Parish, Louisiana,
including state waters. In February 2011, the previously existing Alligator Point Unit (as
approved by the Texas General Land Office [GLO]) expired. We have obtained from the GLO an
extension until September 1, 2011 of a smaller version of the Alligator Point Unit defined more
specifically by the drilling prospects currently existing on the project. As a result of the GLO
approval of the smaller Alligator Point Unit and the anticipated expiry of five leases previously
held by the larger unit, we expect our lease position on the West Bay project to be reduced from
approximately 13,000 acres in February 2011 to approximately 10,050 acres in August 2011.
10
Drilling and Development Activity
During the year ended December 31, 2010, operational activities in the West Bay prospect
focused on firming up plans for drilling on the identified initial drilling prospect and continuing
to evaluate the other leads and prospects in the project. Land, regulatory and surface access
preparations currently in progress are focused on taking the initial drilling prospect to
drill-ready status. During 2010, we finalized a 3-D seismic data trade with a third party and
merged the data set with our existing seismic data. The acquisition and merging of the additional
3-D seismic data allows for more complete technical evaluation of the leads and prospects
identified in the project. Based on the merged seismic data set, we now have four identified
drilling prospects on our acreage. Preliminary work is underway on a drilling barge concept that
will be utilized to drill the first two exploration wells. Current plans are to drill the first
exploration well in 2011, pending required surface access agreements with a private landowner and
pending receipt of necessary permits from the U.S. Army Corps of Engineers.
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 was obligated to assemble the initial 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.
In July 2010, we executed a farm-out agreement with the private third party in the JEDA for
the acquisition of an incremental 10 percent interest in the Antelope Project with an effective
date of July 1, 2010. This acquisition includes all leases, the Mesaverde, the Lower Green
River/Upper Wasatch and the Monument Butte Extension. The acquisition excludes the initial eight
wells previously drilled in the Monument Butte Extension. Total consideration for the incremental
10 percent interest is $20.0 million, of which (1) $3.0 million was paid on August 2, 2010 (the
closing date of the acquisition); (2) $3.0 million to be used as a credit against future joint
interest billings or if joint interest billings do not accumulate to $3.0 million by October 1,
2010, at the sole election of the private third party, the balance is to be paid by us within 15
days of receipt of written request from the private third party; and (3) a capped $14.0 million
carry of a portion of our partners exploration and development cost obligations in the upcoming
Lower Green River/Upper Wasatch and Monument Butte Extension drilling programs in the Antelope
project. On October 1, 2010, the private third party elected to receive in cash the remaining
balance of the joint interest billing credit of $2.4 million. At December 31, 2010, the
outstanding balance on the $14.0 million exploration and development cost obligation carry is $8.4
million. Based on current plans, we anticipate the full carry obligation will be met in the first
half of 2011. This acquisition increases our ownership in the Antelope project to 70 percent.
General
The Antelope 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.
11
Mesaverde
Drilling and Development Activity
Operational activities during the year ended December 31, 2010 included completion of the
initial testing activities on the Mesaverde horizons in the deep natural gas test well (the Bar F)
that commenced drilling on June 15, 2009. The Bar F was drilled to a total depth of 17,566 feet
and an extended production test of the Mesaverde has been completed. Testing was 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. Gas was
tested at flow rates of 1.5-2 million cubic feet per day (MMCFD) from selected intervals. While
the results to date have not definitively determined the commerciality of a stand-alone development
of the Mesaverde in the current gas price environment, we believe that the test results confirm
that the Mesaverde formation exhibits sufficient quantities of hydrocarbons and reservoir
over-pressure to justify potential development, and we are actively pursuing efforts to assess
whether reserves can be attributed to this reservoir. The Mesaverde reservoir remains potentially
prospective over a portion of our land position. Exploratory drilling costs for the Mesaverde have
been suspended pending further evaluation.
Lower Green River/Upper Wasatch
General
The Lower Green River/Upper Wasatch is a second prospective horizon that is being pursued in
the Antelope project. After completion of the initial testing program on the Mesaverde deep gas in
the Bar F well as described above, we moved uphole in the same well to test multiple oil bearing
intervals at depths from 8,200 feet to 9,500 feet in the Lower Green River and Upper Wasatch
formations. Extended flow testing of the well conducted during the second quarter of 2010
indicated that a commercial oil discovery was made in the Lower Green River and Upper Wasatch. A
five-well Lower Green River/Upper Wasatch delineation and development drilling program was planned
to further delineate and appraise the extent of the Lower Green River/Upper Wasatch discovery made
in the Bar F, and to establish additional production from the Lower Green River/Upper Wasatch
reservoirs in at least some of the five appraisal wells. Based on results of the initial wells in
the five well delineation and development drilling program, an additional sixth well was added to
the program to be drilled in early 2011.
On December 21, 2010, we and our partner in the Antelope project entered into a contract with
El Paso Midstream Group, Inc. (EPMG) whereby EPMG will provide the capital to build and operate a
25-mile, low-pressure gas gathering pipeline which will provide capacity for our current and future
production from the Lower Green River/Upper Wasatch Development project. We will provide capital
to build flowlines to connect the produced gas from our wells into the EPMG header system. As part
of the contract arrangement, we and our partner have dedicated approximately 75 percent of our
Antelope leasehold to the El Paso contract for 10 years, with a Harvest option to extend the
dedication for up to an additional nine years without any change in contract terms. The area
dedication is limited stratigraphically to the top of the Mesaverde formation, resulting in the
Mesaverde deep gas not being included in the dedication.
Location and Geology
The Lower Green River/Upper Wasatch covers approximately 37,000 Harvest net acres located on
the northern portion of our Antelope land position and includes the Lower Green River/Upper Wasatch
formations. The Lower Green River/Upper Wasatch formations are productive in the Altamont/Bluebell
oil field approximately six miles north of the Bar F well.
Drilling and Development Activity
The five-well delineation and development drilling program was initiated in the third quarter
of 2010. The original five wells were in varying stages of completion and drilling and production
facilities installation as of December 31, 2010:
|
|
|
Two wells, the Kettle #1-10-3-1 and the ON Moon #1-27-3-2, are completed and currently
on production. |
12
|
|
|
One well, the Dart #1-12-3-2, is drilled and being hydraulically fractured. |
|
|
|
|
One well, the Giles #1-19-3-2, is drilled and waiting on fracturing. |
|
|
|
|
One well, the Yergensen #1-9-3-1, was spud using a spud rig and is waiting on the
drilling rig. |
Three additional wells have been incorporated into our planning for the next round of
development drilling in the Lower Green River/Upper Wasatch. Two of the additional wells, the Lamb
#1-19-3-1 and the Yergensen #1-18-3-1, were spud using a spud rig and have been drilled to surface
casing depth only and surface casing installed.
During the fourth quarter of 2010, we also initiated permitting activities on a planned 170
square mile 3-D seismic acquisition program which is expected to be acquired in late 2011 and which
will be targeted at imaging the Green River and Wasatch formations over the northern portion of our
acreage.
Monument Butte
General
The Monument Butte Extension was initiated in the fourth quarter of 2009 with an eight well
appraisal and development drilling program to produce oil and natural gas from the Green River
formation. The parties participating in the wells formed a 320 acre AMI, which contained the
initial eight drilling locations.
As a follow up to the successful completion of the initial eight well program that was drilled
in late 2009 and early 2010, a six well appraisal and development drilling program was approved
during 2010. The six well expansion is on acreage immediately adjacent to the initial eight well
program.
The first 14 wells in the Monument Butte Extension (as defined above) are non-operated. We
hold a 43 percent working interest in the initial eight wells and an approximate 37 percent working
interest in the follow-up six wells.
During 2010, an additional Harvest operated well, the K Moon #2-13-4-3, was added to the
project. We have an approximate 60 percent working interest in the well. As of December 31, 2010,
the K Moon #2-13-4-3 had been spud using a spud rig, drilled to casing depth only and surface
casing installed.
Location and Geology
The Monument Butte Extension covers approximately 12,000 Harvest net acres located on the
southern portion of our Antelope land position primarily in the Green River formation.
Drilling and Development Activity
Operational activities during 2010 for the Monument Butte Extension consisted of completion of
drilling and completion of wells followed by routine production operations from the initial eight
wells and implementation of the six well expansion program in third quarter 2010. Five of the six
wells were drilled and four were on production as of December 2010. The sixth and final well spud
on February 3, 2011. Also, in the fourth quarter of 2010, we spud the Harvest operated K Moon
#2-13-4-3 with a spud rig.
Budong-Budong, Onshore Indonesia
General
In December 2007, we entered into a Farmout Agreement to acquire a 47 percent interest in the
Budong PSC located mostly onshore West Sulawesi, Indonesia. In April 2008, the Government of
Indonesia approved the assignment to us of the 47 percent interest in the Budong PSC. Our partner
is the operator through the exploration phase as required by the terms of the Budong PSC, and we
have an option to become operator, if approved by Government of Indonesia and BPMIGAS in any
subsequent development and production phase.
13
We acquired our original 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, under a Farmout Agreement with the operator of the Budong PSC. Under the Farmout Agreement,
the initial commitment was to fund the first phase of the exploration program up to a cap of $17.2
million. The commitment cap was 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 cap of each
component was met, all subsequent costs are shared by the parties in proportion to their ownership
interests. Prior to drilling the first exploration well, our partner had a one-time option to
increase the level of the carried interest to a maximum of $20.0 million. On September 15, 2010,
our partner exercised their option to increase the carry obligation by $2.7 million to a total of
$19.9 million ($7.9 million for acquisition of seismic and $12.0 million for drilling). The
additional carry increased our ownership by 7.4 percent to 54.4 percent. The change in ownership
interest was approved on March 3, 2011 by the Government of Indonesia and BPMIGAS. As of February
28, 2011, we had fulfilled all funding obligations to earn our 54.4 percent interest in the Budong
PSC.
On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by
the operator to a third party, to acquire an additional ten percent equity in the Budong PSC for a
consideration of $3.7 million payable ten business days after completion of the first exploration
well. Closing of this acquisition will increase our interest in the Budong PSC to 64.4 percent.
The change in ownership interest is subject approval from the Government of Indonesia and BPMIGAS.
Location and Geology
During the initial exploration period, the Budong PSC covered 1.35 million acres. The term of
the Budong PSC is for 30 years and provides for an exploration period of up to ten years. Pursuant
to the Budong PSC, at the end of the first three-year exploration phase, 35 percent of the original
area was relinquished to BPMIGAS. The second three-year exploration phase began in January 2010
covering 0.88 million acres. The Budong PSC includes the Lariang and Karama sub-basins, which are
the eastern onshore extension of the West Sulawesi foldbelt (WSFB). Exploration activity to date
in the basins 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 ten 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 offshore 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.
Drilling and Development Activity
Operational activities during 2010 focused on well planning, construction for two exploratory
well sites, and mobilization of rig and ancillary equipment to the first drill site. After delays
in acquiring permits to mobilize the drilling rig from its port location to the drilling pad, the
first exploratory well, the Lariang-1 (LG-1), was spud on January 6, 2011.
Dussafu Marin, Offshore Gabon
General
We are the operator of the Dussafu PSC with a 66.667 percent ownership interest.
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.
14
Drilling and Development Activity
The Dussafu PSC partners and Gabon, represented by the Ministry of Mines, Energy, Petroleum
and Hydraulic Resources, entered into the second exploration phase of the Dussafu PSC with an
effective date of May 28, 2007. It was agreed that the second three-year exploration phase be
extended until May 27, 2011, at which time the partners can elect to enter a third exploration
phase. Operational activities during 2010 included the maturation of the prospect inventory and
well planning. We have issued purchase orders for long lead items required for
drilling. Other drilling contracts are being tendered in preparation to spud the exploration
well in the second quarter of 2011. The exploratory well to be drilled in the second quarter of
2011 will test stacked reservoir potential in the pre-salt section. A Letter of Intent has been
agreed for a semi-submersible rig to commence a contract in April 2011 to drill the Ruche Marin
prospect. In order to be able to complete the drilling activities, a six month extension to
November 27, 2011 of the second Exploration Period has been requested.
Oman
General
In 2009, we signed an EPSA with Oman for the Al Ghubar/Qarn Alam license (Block 64 EPSA).
We have a 100 percent working interest in Block 64 EPSA during the exploration phase. Oman Oil
Company has the option to back-in to up to a 20 percent interest in Block 64 EPSA after the
discovery of gas.
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 955,600 acre block is
located in the gas and condensate rich Ghaba Salt Basin in close proximity to the Barik, Saih Rawl
and Saih Nihayda gas and condensate fields.
Drilling and Development Activity
PDO will continue to produce oil from several shallow oil 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. Operational activities during 2010 included geological studies, baseline
environmental and social study, and 3-D pre-stack depth migration reprocessing of approximately
1,150 square kilometers of existing 3-D seismic data. During 2011, geological and geophysical
interpretation of the reprocessed 3-D seismic data will take place to mature drilling locations.
Well planning and procurement of long lead items is expected to commence in 2011 in anticipation of
drilling the first of the two exploratory wells.
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 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. Although 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, there has
been a small increase in exploration activity in the area starting in 2009.
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)
15
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 MBl 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. We are in the process of
obtaining a new license extension and believe that it will be granted. While no assurance can be
given, we believe we will continue to receive contract extensions so long as the border disputes
persist.
In 2009, Vietnam, along with the company that is the party to the agreement with Vietnam,
announced plans for exploration drilling during 2010. In the first quarter of 2010, the planned
2010 exploration drilling was postponed due to internal funding constraints. Vietnam has also
stated that seismic was shot during 2010 and additional seismic may be shot in 2011. While no
assurance can be given, we believe these activities 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, 2010, 2009 and 2008. The
presentation for Venezuela is presented at our net 32 percent ownership interest in Petrodelta.
The United States is presented at our ownership interest.
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Venezuela |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Production (MBbls)(b) |
|
|
1,826 |
|
|
|
1,671 |
|
|
|
1,174 |
|
Natural Gas Production (MMcf)(a)(c) |
|
|
470 |
|
|
|
938 |
|
|
|
2,283 |
|
Average Crude Oil Sales Price ($per Bbl) |
|
$ |
70.57 |
|
|
$ |
57.62 |
|
|
$ |
83.22 |
|
Average Natural Gas Sales Price ($per Mcf) |
|
$ |
1.54 |
|
|
$ |
1.54 |
|
|
$ |
1.54 |
|
Average Operating
Expenses ($per BOE)(d) |
|
$ |
6.01 |
|
|
$ |
5.64 |
|
|
$ |
10.65 |
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
Monument Butte |
|
|
|
|
|
|
|
|
|
|
|
|
Net Crude Oil Production (MBbls) |
|
|
106 |
|
|
|
3 |
|
|
|
|
|
Natural Gas Production (MMcf) |
|
|
417 |
|
|
|
6 |
|
|
|
|
|
Average Crude Oil Sales Price ($per Bbl) |
|
$ |
64.85 |
|
|
$ |
61.57 |
|
|
$ |
|
|
Average Natural Gas Sales Price ($ per Mcf) |
|
$ |
3.43 |
|
|
$ |
2.77 |
|
|
$ |
|
|
Average Operating
Expenses ($ per BOE)(e) |
|
$ |
4.26 |
|
|
$ |
|
|
|
$ |
|
|
Lower Green River/Upper Wasatch |
|
|
|
|
|
|
|
|
|
|
|
|
Net Crude Oil Production (MBbls) |
|
|
34 |
|
|
|
|
|
|
|
|
|
Natural Gas Production (MMcf) |
|
|
6 |
|
|
|
|
|
|
|
|
|
Average Crude Oil Sales Price ($per Bbl) |
|
$ |
69.63 |
|
|
$ |
|
|
|
$ |
|
|
Average Natural Gas Sales Price ($ per Mcf) |
|
$ |
3.97 |
|
|
$ |
|
|
|
$ |
|
|
Average Operating
Expenses ($ per BOE)(e) |
|
$ |
25.41 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
(a) |
|
Royalty-in-kind paid on gas used as fuel by Petrodelta net to our 32 percent
interest was 1,015 MMcf, 1,063 MMcf and 1,226 MMcf for
2010, 2009 and 2008, respectively. |
|
(b) |
|
Crude oil sales net to our 32 percent interest after deduction of
royalty. Crude oil sales for Petrodelta at 100 percent was 8,561 MBbls, 7,835 MBbls and
5,505 MBbls for 2010, 2009 and 2008, respectively. |
|
(c) |
|
Natural gas sales net to our 32 percent interest after deduction of royalty.
Natural gas sales for Petrodelta at 100 percent was 2,204 MMcf, 4 397 MMcf and
10,700 MMcf for 2010, 2009 and 2008, respectively. |
|
(d) |
|
Before royalties and including workovers. Petrodelta is not subject to ad valorem or
severance taxes. Average operating expenses per BOE net of royalties and workovers was
$7.52, $8.46 and $10.90 for 2010, 2009 and 2008, respectively. |
|
(e) |
|
Excluding ad valorem and severance taxes. |
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) $59.6 million, $28.0
million and $26.3 million in 2010,
2009 and 2008, respectively. These numbers do not include any costs for the development of proved
undeveloped reserves in 2010, 2009 or 2008.
17
We have participated in the drilling of wells as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Wells Drilled: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Venezuela (Petrodelta) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development |
|
|
16 |
|
|
|
5.1 |
|
|
|
15 |
|
|
|
4.8 |
|
|
|
9 |
|
|
|
2.9 |
|
Appraisal |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
0.6 |
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development |
|
|
8 |
|
|
|
2.6 |
|
|
|
5 |
|
|
|
2.1 |
|
|
|
|
|
|
|
|
|
Exploration |
|
|
3 |
|
|
|
1.0 |
|
|
|
1 |
|
|
|
1.0 |
|
|
|
1 |
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Depth of Wells (Feet)
Venezuela (Petrodelta) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
|
6,839 |
|
|
|
|
|
|
|
6,500 |
|
|
|
|
|
|
|
6,500 |
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
|
7,938 |
|
|
|
|
|
|
|
6,751 |
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,566 |
|
|
|
|
|
|
|
12,290 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing Wells (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Venezuela (Petrodelta) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
127 |
|
|
|
40.6 |
|
|
|
114 |
|
|
|
36.5 |
|
|
|
118 |
|
|
|
37.8 |
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
16 |
|
|
|
8.3 |
|
|
|
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, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
Undeveloped |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Venezuela Petrodelta |
|
|
24,330 |
|
|
|
7,786 |
|
|
|
222,783 |
|
|
|
71,291 |
|
China |
|
|
|
|
|
|
|
|
|
|
7,470,080 |
|
|
|
7,470,080 |
|
United States: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Bay |
|
|
|
|
|
|
|
|
|
|
12,808 |
|
|
|
6,437 |
|
Antelope |
|
|
2,422 |
|
|
|
1,549 |
|
|
|
136,362 |
|
|
|
46,842 |
|
Indonesia |
|
|
|
|
|
|
|
|
|
|
883,636 |
|
|
|
480,698 |
|
Gabon |
|
|
|
|
|
|
|
|
|
|
685,470 |
|
|
|
456,982 |
|
Oman |
|
|
|
|
|
|
|
|
|
|
955,600 |
|
|
|
955,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
26,752 |
|
|
|
9,335 |
|
|
|
10,366,739 |
|
|
|
9,487,930 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our intention is to renew all leases that are due to expire in the next three years.
18
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:
|
|
|
change in governments; |
|
|
|
|
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.
Leases
A significant number of our domestic oil and gas leases cover tribal and allottee mineral
interests, with the leases being administered by the Bureau of Indian Affairs (the BIA). The
Bureau of Land Management (the BLM) oversees and approves certain activities/operations of the
leases. BIA leases contain relatively standardized terms and require compliance with detailed BLM
or BIA regulations. Many leases contain stipulations limiting activities that may be conducted on
the lease. Some stipulations are unique to particular geographic areas and may limit the time
during which activities on the lease may be conducted, the manner in which certain activities may
be conducted or, in some cases, may ban surface activity. Under certain circumstances, the BLM or
the BIA, as applicable, may require that our operations on leases be suspended or terminated. Any
such suspension or termination could materially and adversely affect our consolidated financial
condition, results of operations or cash flows.
State and Local Regulation of Drilling and Production
We own interests in properties located in Utah and Texas. These states regulate drilling and
operating activities by requiring, among other things, permits for the drilling of wells,
maintaining bonding requirements in order to drill or operate wells, and regulating the location of
wells, the method of drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled and the plugging and abandonment of wells. The laws of these states also
govern a number of environmental and conservation matters, including the handling and disposing or
discharge of waste materials, the size of drilling and spacing units or proration units and the
density of wells that may be drilled, unitization and pooling of oil and gas properties and
establishment of maximum rates of production from oil and gas wells.
19
Environmental Regulations
Our operations are subject to numerous laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental protection. The cost of
compliance could be significant. Failure to comply with these laws and regulations may result in
the assessment of administrative, civil and criminal penalties, the imposition of remedial and
damage payment obligations, or the issuance of injunctive relief (including orders to cease
operations). Environmental laws and regulations are complex, and have tended to become more
stringent over time. We also are subject to various environmental permit requirements. Onshore
drilling in certain areas has been opposed by environmental groups and, in certain areas, has been
restricted. Moreover, some environmental laws and regulations may impose strict liability, which
could subject us to liability for conduct that was lawful at the time it occurred or conduct or
conditions caused by prior operators or third parties. To the extent laws are enacted or other
governmental action is taken that prohibits or restricts onshore drilling or imposes environmental
protection requirements that result in increased costs to the oil and gas industry in general, our
business and financial results could be adversely affected.
The Resource Conservation and Recovery Act (RCRA), generally regulates the disposal of solid
and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA
specifically excludes from the definition of hazardous waste drilling fluids, produced waters and
other wastes associated with the exploration, development or production of crude oil, natural gas
or geothermal energy, the Environmental Protection Agency (EPA) and state agencies may regulate
these wastes as solid wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste
solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.
International Regulations
Our exploration and production operations outside the United States are subject to various
types of regulations similar to those described above imposed by the respective governments of the
countries in which we operate, and may affect our operations and costs within that country. We
currently have operations in Indonesia, Gabon, Oman and China.
Employees
At December 31, 2010, our Houston office had 25 full-time employees. Our Utah, Caracas,
London, Singapore, Jakarta and Muscat offices had 3, 14, 7, 2, 4 and 3 employees, respectively. We
augment our employees from time to time with independent consultants, as required.
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, 2010, we had $58.7 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 capital 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, success
with our exploration program, possible delay of discretionary capital spending to future periods,
or possible sale, farm-out or otherwise monetization of assets as necessary to maintain the
liquidity required to run our operations. While we believe that Petrodelta will reinvest any
excess cash which might be available for payment of dividends into Petrodelta in 2011 and 2012,
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.
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
20
senior convertible notes due 2013. On October 29, 2010, we closed a
$60.0 million term loan facility that will mature on October 28, 2012 and has an initial rate of
interest of 10 percent. The initial rate of interest increases to
15 percent on July 28, 2011. Prior to February 2010, we had no long-term debt obligations.
The degree to which we are leveraged could, among other things:
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make it difficult for us to make payments on the debt; |
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make it difficult for us to obtain financing for working capital, acquisitions or
other purposes on favorable terms, if at all; |
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make us more vulnerable to industry downturns and competitive pressures; |
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limit our flexibility in planning for, or reacting to, changes in our business; and |
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require the use of a substantial portion of working capital. |
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.
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 or the
work program may include minimum funding requirements to keep the contract. We may not have the
funds available to meet the minimum funding requirements when they come due and be required to
forfeit the contracts.
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 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
21
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.
There is limited refining capacity for our yellow and black wax crude oil, which may limit our
ability to sell our current production or to increase our production at Lower Green River/Upper
Wasatch and Monument Butte in the Uinta Basin. Most of the crude oil we produce in the Uinta Basin is
known as yellow wax or black wax because it has higher paraffin content than crude oil found in
most other major North American basins. Due to its wax content, most of the oil is transported by
truck to refiners in the Salt Lake City area. We currently have agreements in place that provide a
reasonable certainty of base load sales of substantially all of our expected production in the
Uinta Basin through the end of 2011. In the current economic environment, there is a risk that
they may fail to satisfy their obligations to us under those contracts. An extended loss of our
largest purchaser could have a material adverse effect on us because there are limited purchasers
of our black and yellow wax crudes. We continue to work with refiners to expand the market for our
existing yellow and black wax crude oil production and to secure additional capacity to allow for
production growth. However, without additional refining capacity, our ability to increase
production from the fields may be limited.
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
22
gas reservoirs will be found. The cost of drilling
and completing wells is often uncertain. Oil and natural gas 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:
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unexpected drilling conditions; |
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pressure or irregularities in formations; |
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equipment failures or accidents; |
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weather conditions; |
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shortages in experienced labor; |
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delays in receiving necessary governmental permits; |
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delays in receiving partner approvals; |
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shortages or delays in the delivery of equipment; |
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delays in receipt of permits or access to lands; and |
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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:
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the amounts and types of substances and materials that may be released into the
environment; |
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response to unexpected releases to the environment; |
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reports and permits concerning exploration, drilling, production and other operations; |
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the spacing of wells; |
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unitization and pooling of properties; |
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calculating royalties on oil and natural gas produced under federal and state leases;
and |
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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.
The oil and gas business involves many operating risks that can cause substantial losses, and
insurance may not protect us against all of these risks. We are not insured against all risks. Our
oil and gas
23
exploration and production activities are subject to all of the operating risks
associated with drilling for and producing oil and gas, including the risk of:
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fires and explosions; |
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blow-outs; |
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uncontrollable or unknown flows of oil, gas, formation water or drilling fluids; |
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adverse weather conditions or natural disasters; |
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pipe or cement failures and casing collapses; |
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pipeline ruptures; |
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discharges of toxic gases; |
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build up of naturally occurring radioactive materials; and |
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vandalism. |
If any of these events occur, we could incur substantial losses as a result of:
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injury or loss of life; |
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severe damage or destruction of property and equipment, and oil and gas reservoirs; |
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pollution and other environmental damage; |
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investigatory and clean-up responsibilities; |
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regulatory investigation and penalties; |
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suspension of our operations; and |
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repairs to resume operations. |
If we experience any of these problems, our ability to conduct operations could be adversely
affected.
We maintain insurance against some, but not all, of these potential risks and losses. We may
elect not to obtain insurance if we believe that the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental risks generally are not
insurable.
Potential regulations regarding climate change could alter the way we conduct our business.
Changes to existing regulations or the adoption of new regulations may unfavorably impact us, our
suppliers or our customers. For example, governments around the world have become increasingly
focused on climate change matters. In the United States, legislation that directly impacts our
industry has been proposed covering areas such as emission reporting and reductions, hydraulic
fracturing, the repeal of certain oil and gas tax incentives and tax deductions, and the regulation
of over-the-counter commodity hedging activities. These and other potential regulations could
increase our costs, reduce our liquidity, delay our operations or otherwise alter the way we
conduct our business, negatively impacting our financial condition, results of operations and cash
flows.
In response to the recent oil spill in the Gulf of Mexico, the United States Congress is
considering a number of legislative proposals relating to the upstream oil and gas industry both
onshore and offshore that could result in significant additional laws or regulations governing our
operations in the United States, including a proposal to raise or eliminate the cap on liability
for oil spill cleanups under the Oil Pollution Act of 1990.
Although it is not possible at this time to predict whether proposed legislation or
regulations will be adopted as initially written, if at all, or how legislation or new regulation
that may be adopted would impact our business, any such future laws and regulations could result in
increased compliance costs or additional operating restrictions. Additional costs or operating
restrictions associated with legislation or regulations could have a material adverse effect on our
operating results and cash flows, in addition to the demand for the natural gas and other
hydrocarbon products that we produce.
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
24
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 do not 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:
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relatively minor changes in the global supply and demand for oil; |
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export quotas; |
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market uncertainty; |
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the level of consumer product demand; |
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weather conditions; |
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domestic and foreign governmental regulations and policies; |
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the price and availability of alternative fuels; |
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political and economic conditions in oil-producing and oil consuming countries; and |
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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
25
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. Since
Petrodelta only executed approximately 50 percent of its 2010 budget primarily due to lack of
funding by PDVSA, we do not believe that PDVSA will be able to provide the support required to
execute Petrodeltas proposed 2011 budget.
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 effect 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 August 2010, we
relinquished a portion of our office space in Houston, Texas, for an approximate $1,600 per month
reduction of cost. In December 2010, Harvest Vinccler extended its lease for office space in
Caracas, Venezuela for one year for approximately $7,000 per month. In October 2010, we signed a
two-year lease in Roosevelt, Utah for approximately $6,000 per month. In October 2010, we signed a
two-year lease for office space in Singapore for approximately $7,000 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 September 2010, we signed a five-year lease for office space in London for approximately
$9,000 per month. See Item 1 Business for a description of our oil and gas properties.
26
Item 3. Legal Proceedings
Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc.,
Branta Exploration & Production, LLC, Ute Energy LLC, Cameron Cuch, Paula Black, Johnna Blackhair,
and Elton Blackhair in the
United States District Court for the District of Utah. This suit was served in April
2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the defendants, among other
things, intentionally interfered with Plaintiffs employment agreement with the Ute Indian Tribe
Energy & Minerals Department and intentionally interfered with Plaintiffs prospective economic
relationships. Plaintiffs seek actual damages, punitive damages, costs and attorneys fees. We
dispute Plaintiffs claims and plan to vigorously defend against them. We are unable to estimate
the amount or range of any possible loss.
Uracoa Municipality Tax Assessments. Our Venezuelan subsidiary, Harvest Vinccler has
received nine assessments from a tax inspector for the Uracoa municipality in which part of the
Uracoa, Tucupita and Bombal fields are located as follows:
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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. |
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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. |
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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. |
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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:
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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. |
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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. |
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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.
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, 2010, there
were 33,933,025 shares of common stock outstanding, with approximately 481 stockholders of record.
The following table sets forth the high and low sales prices for our Common Stock reported by the
NYSE.
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Year |
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Quarter |
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High |
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Low |
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2009 |
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First quarter |
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4.69 |
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2.70 |
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Second quarter |
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5.66 |
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3.25 |
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Third quarter |
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6.64 |
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4.24 |
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Fourth quarter |
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6.39 |
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4.90 |
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2010 |
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First quarter |
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7.80 |
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4.36 |
|
|
|
|
|
Second quarter |
|
|
9.00 |
|
|
|
7.10 |
|
|
|
|
|
Third quarter |
|
|
10.42 |
|
|
|
6.54 |
|
|
|
|
|
Fourth quarter |
|
|
14.02 |
|
|
|
10.44 |
|
On March 9, 2011,
the last sales price for the common stock as reported by the NYSE was $16.25
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, 2010, assuming an investment of $100 on December 31, 2005 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, 2005 and that all dividends were reinvested.
28
Stock Performance Graph
PLOT POINTS
(December 31 of each year)
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|
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|
|
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|
|
|
|
|
2005 |
|
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
Harvest Natural
Resources, Inc |
|
$ |
100 |
|
|
$ |
120 |
|
|
$ |
141 |
|
|
$ |
48 |
|
|
$ |
60 |
|
|
$ |
137 |
|
Dow Jones US E&P Index |
|
$ |
100 |
|
|
$ |
105 |
|
|
$ |
147 |
|
|
$ |
86 |
|
|
$ |
121 |
|
|
$ |
145 |
|
S&P 500 Index |
|
$ |
100 |
|
|
$ |
116 |
|
|
$ |
122 |
|
|
$ |
77 |
|
|
$ |
97 |
|
|
$ |
112 |
|
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, 2010. 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.
29
|
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|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
2007(1) |
|
|
2006(1) |
|
|
|
|
|
|
|
(in thousands, except per share data) |
|
|
|
|
|
Statement of Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
10,696 |
|
|
$ |
181 |
|
|
$ |
|
|
|
$ |
11,217 |
|
|
$ |
59,506 |
|
Operating income (loss) |
|
|
(30,691 |
) |
|
|
(30,959 |
) |
|
|
(54,440 |
) |
|
|
(19,536 |
) |
|
|
574 |
|
Net income from Unconsolidated
Equity Affiliates |
|
|
66,164 |
|
|
|
35,757 |
|
|
|
34,576 |
|
|
|
55,297 |
|
|
|
|
|
Net income (loss) attributable to Harvest |
|
|
15,340 |
|
|
|
(3,107 |
) |
|
|
(21,464 |
) |
|
|
60,118 |
|
|
|
(62,502 |
) |
Net income (loss) attributable to Harvest per
common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
|
$ |
(0.63 |
) |
|
$ |
1.65 |
|
|
$ |
(1.68 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.43 |
|
|
$ |
(0.09 |
) |
|
$ |
(0.63 |
) |
|
$ |
1.59 |
|
|
$ |
(1.68 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
33,541 |
|
|
|
33,084 |
|
|
|
34,073 |
|
|
|
36,550 |
|
|
|
37,225 |
|
Diluted |
|
|
39,331 |
|
|
|
33,084 |
|
|
|
34,073 |
|
|
|
37,950 |
|
|
|
37,225 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
2007(1) |
|
|
2006(1) |
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
488,244 |
|
|
$ |
348,779 |
|
|
$ |
362,266 |
|
|
$ |
417,071 |
|
|
$ |
468,365 |
|
Long-term debt, net of current maturities |
|
|
81,237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
66,977 |
|
Total Harvests Stockholders equity (2) |
|
|
306,804 |
|
|
|
274,593 |
|
|
|
273,242 |
|
|
|
316,647 |
|
|
|
281,409 |
|
|
|
|
(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. |
30
Item 7. Managements Discussion and Analysis of Financial Condition and Results of
Operations
Operations
We had net
income attributable to Harvest of $15.3 million, or $0.43 per diluted share, for
the year ended December 31, 2010 compared to a net loss attributable to Harvest of $3.1 million, or
$(0.09) per diluted share, for the year ended December 31, 2009. Net income attributable to
Harvest for the year ended December 31, 2010 includes $8.0 million of exploration expense and the
net equity income from Petrodeltas operations of $66.2 million. 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.
Venezuela
On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange
Agreement, which established new exchange rates for the Bolivar/U.S. Dollar currencies that went
into effect on January 11, 2010. Per the Exchange Agreement, each exchange rate is applied to
foreign currency sales and purchases conducted through 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 applied
to the food, health, medical and technology sectors. The 4.30 Bolivar exchange rate applied to all
other sectors not expressly established by the 2.60 Bolivar exchange rate. The 4.30 Bolivar
exchange rate applied to the oil and gas sector.
The January 8, 2010 Exchange Agreement
also established exchange rates for the
sale of foreign currency: 2.5935 Bolivars per U.S. Dollar and 4.2893 Bolivars per U.S. Dollar.
The 2.5935 Bolivars per U.S. Dollar rate applies to at least 30 percent of the currency. The
Central Bank is entitled to adjust the proportion of sales of foreign currency at each exchange
rate to attend market needs. Early in 2010, the Central Bank, in responding to needs of import
requirements of goods and services under each of the controlled exchange rates, adjusted the
percentage from 30 percent to 40 percent for the 2.5935 Bolivars per U.S. Dollar. The 40/60
percent split in sales of foreign currency between the two exchange rates creates a blended third
exchange rate of 3.61 Bolivars per U.S. Dollar. During 2010, PDVSA sold foreign currency to the
Central Bank in return for Bolivars. These foreign currency sales were for PDVSA and PDVSAs
subsidiaries. In December 2010, PDVSA invoiced Petrodelta $19.5 million
related to sales of foreign currency for Bolivars at the blended exchange rate of 3.61 Bolivars per
U.S. Dollar. The $19.5 million is calculated as the difference
between U.S. Dollar invoices remeasured at the official exchange rate
of 4.30 Bolivars per U.S. Dollar and the same invoices remeasured at
the blended exchange rate of 3.61 Bolivars per U.S. Dollar.
On January 4, 2011, the Venezuelan government published in the Official Gazette the Exchange
Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange rate with an effective date
of January 1, 2011. The January 2011 Exchange Agreement eliminated the Central Banks entitlement
to require the sale of foreign currency at specific rates. All sales of foreign currency will be
at the 4.2893 Bolivars per U.S. Dollar exchange rate.
As an alternative to the use of the official exchange rate, an exemption under the Venezuelan
Criminal Exchange Law for transactions in certain securities resulted in an indirect securities
transaction market of foreign currency exchange, through which companies could obtain foreign
currency legally without requesting it from CADIVI. Publicly available quotes did not exist for
the securities transaction exchange rate but such rates could be obtained from brokers. Securities
transaction markets were used to move financial securities into and out of Venezuela. In May 2010,
the government of Venezuela effectively eliminated this indirect market of foreign currency
exchange and established the Sistema de Transacciones con Títulos en Moneda Extranjera (SITME)
for exchanging Bolivars. SITMEs purpose is to assist companies and individuals requiring foreign
currency (U.S. Dollars) for the import of goods and services into Venezuela. SITME may also be
used for buying or selling of Venezuelas bonds. The elimination of the indirect market for
foreign currency exchange and the establishment of SITME have not had, nor is it expected to have,
an impact on our business in Venezuela.
Harvest Vincclers and Petrodeltas functional and reporting currency is the U.S. Dollar, and
they do not have currency exchange risk other than the official prevailing exchange rate that
applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar). However,
in October 2010, Harvest Vinccler exchanged
31
approximately $0.2 million through SITME and received
an exchange rate of 5.19 Bolivars per U.S. Dollar. The
monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable,
prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange
rate fluctuations are accounts payable, accruals and other current liabilities. All monetary
assets and liabilities incurred at the official Bolivar exchange rate are settled at the official
Bolivar exchange rate. Petrodelta does not have, and has not had, any Bolivars pending government
approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate.
Harvest Vinccler currently does not have any Bolivars pending government approval for settlement
for U.S. Dollars at the official exchange rate or the SITME exchange rate.
At December 31, 2009, Harvest Vinccler and Petrodelta remeasured the appropriate monetary
assets and liabilities at the official exchange rate of 2.15 Bolivars per U.S. Dollar that was in
effect at that time. On January 31, 2010, Harvest Vinccler and Petrodelta remeasured the
appropriate monetary assets and liabilities at the new official exchange rate of 4.30 Bolivars per
U.S. Dollar. During the year ended December 31, 2010, Harvest Vinccler recorded a $1.5 million
remeasurement loss and Petrodelta recorded an $84.4 million remeasurement gain on revaluation of
monetary assets and liabilities. The revaluation of Bolivars to U.S. Dollars was calculated as the
difference between the old official exchange rate of 2.15 Bolivars per U.S. Dollar and the new
official exchange rate of 4.30 Bolivars per U.S. dollar. The primary factor in Harvest Vincclers
loss on currency exchange rates is that Harvest Vinccler had substantially higher Bolivar
denominated monetary assets than Bolivar denominated monetary liabilities. The primary factor in
Petrodeltas gain on currency exchange rates is that Petrodelta had substantially higher Bolivar
denominated monetary liabilities than Bolivar denominated monetary assets. At December 31, 2010,
the balances in Harvest Vincclers Bolivar denominated monetary assets and liabilities accounts
that are exposed to exchange rate changes are BsF 2.9 million and BsF 3.2 million, respectively.
At December 31, 2010, the balances in Petrodeltas Bolivar denominated monetary assets and
liabilities accounts that are exposed to exchange rate changes are BsF 87.0 million and BsF 1,423.0
million, respectively.
In June 2010,
Petrodeltas board of directors approved the offsetting of accounts payable to PDVSA and its affiliates, including CVP, for 2010 royalties,
taxes and operation expenditures against the receivable from PDVSA and its affiliates, including CVP, for 2010 oil and gas deliveries at
the exchange rate prevailing as of that date.
During February 2011, per instructions received from CVP, Petrodelta proceeded to offset accounts receivable and payables between PDVSA
and its affiliates, including CVP, outstanding as of December 31, 2009 at the exchange rate prevailing as of that date. The revised
revaluation reduced Petrodeltas remeasurement gain $36.1 million from $120.5 million in January 2010 to $84.4 million in December 2010.
The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract
for Sale and Purchase of Hydrocarbons with PDVSA Petroleo S.A. (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.
Merey 16 published prices are quoted and sold in U.S. Dollars. Natural gas delivered from the
Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make
payment to Petrodelta in U.S. Dollars in the case of payment for crude oil and natural gas liquids
delivered. Natural gas deliveries are paid in Bolivars, but the pricing for natural gas is
referenced to the U.S. Dollar. Major contracts for capital expenditures and lease operating
expenditures are denominated in U.S. Dollars. Any dividend paid by Petrodelta will be made in U.S.
Dollars.
Since payment for crude oil is in U.S. Dollars under the contract, we do not expect the recent
currency exchange developments in Venezuela to have an impact on Petrodeltas operations or on the
reserves economic productability price of $70.43 per barrel of oil in relation to the Venezuelan
reserves. In addition, prices used to derive our reserves economic productability average prices
are quoted and sold in U.S. Dollars.
In Item 1A Risk Factors, we disclosed that PDVSAs failure to timely pay contractors,
including Petrodelta, was having an adverse effect on Petrodelta. During the year ended December
31, 2010, PDVSA began making regular payments to Petrodelta to enable Petrodelta to reduce the
outstanding debt to contractors. Some of the payments received from PDVSA were designated to be
used to repay Harvest Vinccler (Advances to Equity Affiliates). During the year ended December 31,
2010, Petrodelta repaid $4.8 million to Harvest Vinccler for costs related to contractors and
seconded employees. As a Petrodelta contractor, Harvest Vinccler assessed the possibility of
recording an allowance for doubtful accounts on its receivable from Petrodelta. After considering
many factors, including the slow but continuous payments received from Petrodelta, Harvest Vinccler
determined that an allowance for doubtful accounts is not required.
32
We are unable to provide an indication of when PDVSA will become and remain current in its
payment obligations. However, we believe that PDVSAs debt will not disappear completely in the
short term, but the risk of
contractor work stoppage is minimal due to PDVSA guaranteeing payments as publicly stated by
top officials. Increased costs due to PDVSAs debt financing are already imbedded in current
contractors rates.
Petrodelta
During 2010, Petrodelta drilled and completed 16 development wells, produced approximately 8.6
MBl of oil and sold 2.2 BCF of natural gas. Petrodelta produced an average of 23,455 BOPD during
the year ended December 31, 2010.
Petrodeltas focus in 2010 included utilizing two rigs to drill both development and appraisal
wells for both maintaining production capacity and appraising the substantial resource base in the
El Salto field. Petrodelta contracted a workover rig in October 2010. Petrodelta began
engineering work for expanded production facilities to handle the expected production from the
development and appraisal wells that were expected to be drilled in 2010. Due to delays in rig
availability, El Salto facilities project execution and lack of funding by PDVSA, Petrodelta only
spent $101.8 million of its 2010 capital budget of $205 million.
As discussed above, 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.
As of March 7, 2011, the 2011 budget for Petrodeltas business plan had not yet been approved
by its shareholders. Since Petrodelta only executed approximately 50 percent its 2010 budget
primarily due to lack of funding by PDVSA, we do not believe that PDVSA will be able to provide the
support required to execute Petrodeltas proposed 2011 budget. However, Petrodeltas 2011 proposed
business plan includes a planned drilling program to utilize two rigs to drill both development and
appraisal wells for maintaining production capacity, the continued appraisal of the substantial
resource base in the El Salto field and appraising the presently non-producing Isleño field. It
also includes engineering work for production facilities required for the full development of the
El Salto field.
The appraisal and development activity in the El Salto field exceeded expectations. During
2010, the ELS-33 well was drilled and completed in the Lower Jobo sand and began producing on
September 1, 2010. The ELS-33 tested at rates of 1,800 barrels of oil per day (BOPD). The
ELS-33 also drilled a pilot hole which encountered a full column of oil in a block that was
previously unpenetrated and represented a significant expansion of Block 5 in El Salto field not
included in the 2009 reserve report. The ELS-34 well was drilled and completed in the Lower Jobo
sand of the newly identified Block 5 extension and began production in September 2010. The ELS-34
has tested at rates of 2,150 BOPD with indicated potential of over 3,000 BOPD based on
bottom-hole-pressures. The ELS-33 and ELS-34 wells were restricted in their production rate until
additional oil transportation trucks are contracted by Petrodelta to service the expanded
production capacity from El Salto.
As of December 31, 2010, we are reporting a reserve increase attributed to Petrodelta. 2P
reserves, net to our 32 percent interest, have increased to 103.6 MMBOE at December 31, 2010, a 24
percent increase over year end 2009. Proved reserves, net to our 32 percent interest, increased to
50.0 MMBOE at December 31, 2010, an eight percent increase over year end 2009. 3P reserves remain
virtually unchanged from last year. These reserve additions are the result of successful recent
drilling and the extension of Block 5, a previously unproven fault block in the El Salto field and
recent development drilling success in other fields.
In 2005, Venezuela modified LOCTI 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
33
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 expected PDVSA to continue requesting and receiving waivers, Petrodelta did not
accrue a liability to LOCTI for the year ended December 31, 2009. For filing years 2007 and 2008,
PDVSA provided Petrodelta with a copy of the waiver acceptance letter from LOCTI. PDVSA has stated
that a waiver was granted for filing year 2009; however, LOCTI has not yet issued the acceptance
letter to PDVSA for the 2009 filing year. The potential exposure to LOCTI for the year ended
December 31, 2009 after devaluation is $4.8 million, $2.4 million net of tax ($0.8 million net to
our 32 percent interest). In January 2011, PDVSA informed its consolidating entities, including
Petrodelta, that effective with the 2010 reporting year it would no longer be requesting waivers to
file the LOCTI declaration on a consolidated basis. Based on this information, Petrodelta accrued
the 2010 liability to LOCTI in the amount of $4.6 million, $2.3 million
net of tax ($0.7 million
net to our 32 percent interest). In December 2010, LOCTI was modified to reduce the amount of
contributions beginning January 2011 to one percent of gross revenues for companies owned by
individuals or corporations and 0.5 percent for companies owned by Venezuela. Petrodeltas rate of
contribution starting in 2011 will be 0.5 percent.
In 2008, the Venezuelan government published in the Official Gazette the Windfall Profits Tax.
The Windfall Profits Tax is to be calculated on the VEB of prices as published by MENPET. As
instructed by CVP, Petrodelta has applied the Windfall Profits Tax to gross oil production
delivered to PDVSA. The Windfall Profits Tax established a special 50 percent tax to the
Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar
manner, the percentage is increased from 50 percent to 60 percent when the average price of the VEB
exceeds $100 per barrel. The Windfall Profits Tax is reported as expense on the income statement
and is deductible for Venezuelan tax purposes. Petrodelta recorded $14.1 million and $0.9 million
of expense for the Windfall Profits Tax for the years ended December 31, 2010 and 2009,
respectively.
In 2009, under instructions issued by CVP, Petrodelta set up a reserve within the equity
section of the balance sheet for deferred tax assets. 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. Dividends received prior to 2009
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 August 2010, Petrodelta board of directors declared a dividend of $30.5 million, $12.2
million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received
October 22, 2010. The dividend represents 50 percent of the cash withdrawal rights as shareholders
on Petrodeltas net income as reported under IFRS for the year ended December 31, 2009.
In November 2010, Petrodeltas board of directors declared a dividend of $30.6 million, $12.2
million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents
the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodeltas net income
as reported under IFRS for the year ended December 31, 2009. This dividend is subject to
shareholder approval, and will not be accrued on our consolidated balance sheet until Petrodelta
shareholder approval is received. Shareholder approval was received on
March 14, 2011. Petrodeltas results and operating information is more fully
described in Part IV, Item 15, Notes to the Consolidated Financial Statements, Note 9 Investment
in Equity Affiliates Petrodelta, S.A.
34
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 and the opening of our London and
Singapore offices, 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 resource potential that provides sustainable growth.
United States
Gulf Coast West Bay
During the year ended December 31, 2010, operational activities in the West Bay prospect
focused on firming up plans for drilling on the identified initial drilling prospect and continuing
to evaluate the other leads and prospects in the project. Land, regulatory and surface access
preparations currently in progress are focused on taking the initial drilling prospect to
drill-ready status. During 2010, we finalized a 3-D seismic data trade with a third party and
merged the data set with our existing seismic data. The acquisition and merging of the additional
3-D seismic data allows for more complete technical evaluation of the leads and prospects
identified in the project. Based on the merged seismic data set, we now have four identified
drilling prospects on our acreage. Preliminary work is underway on a drilling barge concept that
will be utilized to drill the first two exploration wells. Current plans are to drill the first
exploration well in 2011, pending required surface access agreements with a private landowner and
pending receipt of necessary permits from the U.S. Army Corps of Engineers. During the year ended
December 31, 2010, we had cash capital expenditures of $0.2 million for leasing activities and $0.2
million for seismic data processing on the West Bay project. The 2011 budget for West Bay is
minimal consisting of costs required to maintain the leases.
In February 2011, the previously existing Alligator Point Unit (as approved by the GLO)
expired. We have obtained from the GLO an extension until September 1, 2011 of a smaller version
of the Alligator Point Unit defined more specifically by the drilling prospects currently existing
on the project. As a result of the GLO approval of the smaller Alligator Point Unit and the
anticipated expiry of five leases previously held by the larger unit, we expect our lease position
on the West Bay project to be reduced from approximately 13,000 acres in February 2011 to
approximately 10,050 acres in August 2011.
Western United States Antelope
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. In
November 2008, we entered into 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, among other things. 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.
In July 2010, we executed a farm-out agreement with the private third party in the JEDA for
the acquisition of an incremental 10 percent interest in the Antelope Project with an effective
date of July 1, 2010. This acquisition includes all leases, the Mesaverde, the Lower Green
River/Upper Wasatch and the Monument Butte Extension. The acquisition excludes the initial eight
wells previously drilled in the Monument Butte Extension. Total consideration for the incremental
10 percent interest is $20.0 million. This acquisition increases our ownership in the Antelope
project to 70 percent.
35
During year ended December 31, 2010, we had cash capital expenditure of $12.9 million for
leasing activities on the Antelope prospect. The 2011 budget for leasing activity in the Antelope
prospect is $0.9 million.
Drilling, completion and testing activities were conducted during 2010 on three separate
projects on the Antelope prospect in Duchesne and Uintah Counties, Utah.
Mesaverde
The Mesaverde Gas Exploration and Appraisal Project (Mesaverde) is targeted to explore for
and develop natural gas in the Mesaverde formation in the Uintah Basin of northeastern Utah in
Duchesne and Uintah Counties. Operational activities during the year ended December 31, 2010
included completion of the initial testing activities on the Mesaverde horizons in the deep natural
gas test well, the Bar F, that commenced drilling on June 15, 2009. The Bar F was drilled to a
total depth of 17,566 feet and an extended production test of the Mesaverde has been completed.
Testing was 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. Gas was tested at flow rates of 1.5-2 million cubic feet per day (MMCFD) from
selected intervals. While the results to date have not definitively determined the commerciality
of a stand-alone development of the Mesaverde in the current gas price environment, we believe that
the test results confirm that the Mesaverde formation exhibits sufficient quantities of
hydrocarbons and reservoir over-pressure to justify potential development, and we are actively
pursuing efforts to assess whether reserves can be attributed to this reservoir. The Mesaverde
reservoir remains potentially prospective over a portion of our land position. Exploratory
drilling costs for the Mesaverde have been suspended pending further evaluation. See Note 2
Summary of Significant Accounting Policies, Property and Equipment. During the year ended December
31, 2010, we incurred $5.1 million for drilling, completion and testing activities of the
Mesaverde. Our 2011 budget currently does not include costs to further delineate the Mesaverde.
Lower Green River/Upper Wasatch
The Lower Green River/Upper Wasatch is a second prospective horizon that is being pursued in
the Antelope project. After completion of the initial testing program on the Mesaverde deep gas in
the Bar F well as described above, we moved uphole in the same well to test multiple oil bearing
intervals at depths from 8,200 feet to 9,500 feet in the Lower Green River and Upper Wasatch.
Extended flow testing of the well conducted during the second quarter of 2010 indicated that a
commercial oil discovery was made in the Lower Green River and Upper Wasatch. A five-well Lower
Green River/Upper Wasatch delineation and development drilling program was planned to further
delineate and appraise the extent of the Lower Green River/Upper Wasatch discovery made in the Bar
F, and to establish additional production from the Lower Green River/Upper Wasatch reservoirs in at
least some of the five appraisal wells. Based on results of the initial wells in the five well
delineation and development drilling program, an additional sixth well was added to the program to
be drilled in early 2011.
Operational activities during the year ended December 31, 2010 included completion of testing
of the Bar F, completion of the Bar F, including installation of an electric submersible pump,
completion of production facilities for the Bar F and routine production operations of the Bar F.
During the year ended December 31, 2010, we had cash capital expenditure of $6.8 million in
drilling, completion and testing activities for the Bar F in the Lower Green River/Upper Wasatch
formation.
The five-well delineation and development drilling program was initiated in the third quarter
of 2010, and as of December 31, 2010, five wells were in varying stages of completion, drilling,
and production facilities installation. Three additional wells have been incorporated into our
planning for the next round of development drilling in the Lower Green River/Upper Wasatch. As of
March 4, 2011, we had eight wells in the delineation and development drilling program in varying
stages of completion, drilling and production facilities installation:
|
|
|
Three wells, the Kettle #1-10-3-1, the ON Moon #1-27-3-2 and the Dart #1-12-3-2, were
completed and on production. |
|
|
|
|
One well, the Giles #1-19-3-2, has been hydraulically fractured and completed and will
be placed on production soon. |
36
|
|
|
One well, the Yergensen #1-9-3-1, has been drilled and being hydraulically fractured. |
|
|
|
|
One well, the Evans #1-4-3-3, is currently drilling. |
|
|
|
|
Two wells, the Lamb #1-19-3-1 and the Yergensen #1-18-3-1, were spud using a spud rig
and have been drilled to surface casing depth only and surface casing installed. |
During the year ended December 31, 2010, we had cash capital expenditure of $17.3 million in
well planning, drilling and completion costs and $0.1 million for engineering costs. The 2011
budget for the Lower Green River/Upper Wasatch is $11.2 million.
During the fourth quarter of 2010, we also initiated permitting activities on a planned 170
square mile 3-D seismic acquisition program which is expected to be acquired in late 2011 and which
will be targeted at imaging the Green River and Wasatch formations over the northern portion of our
acreage.
On December 21, 2010, we and our partner in the Antelope project entered into a contract with
EPMG whereby EPMG will provide the capital to build and operate a 25-mile, low-pressure gas
gathering pipeline which will provide capacity for our current and future production from the Lower
Green River/Upper Wasatch Development project. We will provide capital to build flowlines to
connect the produced gas from our wells into the EPMG header system. As part of the contract
arrangement, we and our partner have dedicated approximately 75 percent of our Antelope leasehold
to the El Paso contract for 10 years, with a Harvest option to extend the dedication for up to an
additional nine years without any change in contract terms. The area dedication is limited
stratigraphically to the top of the Mesaverde formation, resulting in the Mesaverde deep gas not
being included in the dedication.
As of December 31, 2010, we received our first comprehensive reserve report covering the Uinta
Basin reserves in Utah. 2P reserves net to Harvest in Utah increased to 15.3 MMBOE at year end
2010, compared to 0.4 MMBOE at year end 2009. Proved Reserves net to Harvest increased to 4.6
MMBOE at December 31, 2010, compared to 0.4 MMBOE at year end 2009. 3P reserves net to Harvest in
Utah increased to 86.4 MMBOE at December 31, 2010, compared to 0.4 MMBOE at year end 2009. These
reserve additions are the result of our successful Antelope project delineation drilling programs
conducted during 2010 and ongoing in 2011 in the Lower Green River/Upper Wasatch and Monument Butte
Extension.
Monument Butte
The Monument Butte Extension was initiated with an eight well appraisal and development
drilling program to produce oil and natural gas from the Green River formation on the southern
portion of our Antelope land position. The Monument Butte Extension is non-operated, and we hold a
43 percent working interest in the initial eight wells. The parties participating in the wells
formed a 320 acre AMI, which contained the initial eight drilling locations. Operational
activities on these eight wells during the year ended December 31, 2010 consisted of completion of
drilling and completion of wells followed by routine production operations from the wells. During
year ended December 31, 2010, we had cash capital expenditure of $3.6 million in well costs. There
is no 2011 budget for the initial eight well program.
As a follow up to the successful completion of the initial eight well program that was drilled
in late 2009 and early 2010, a six well appraisal and development drilling program was approved.
The six well expansion is non-operated and is located on acreage immediately adjacent to the
initial eight well program. We have an approximate 37 percent working interest in the six wells.
At December 31, 2010, five of the six wells had been drilled and four were on production. The
sixth and final well in this program spud on February 3, 2011. During the year ended December 31,
2010, we had cash capital expenditures of $1.8 million in well costs and $0.1 million for
geological and geophysical costs.
The Harvest-operated K Moon #2-13-4-3 well was spud in November 2010 and commenced production
on February 16, 2011. We have an approximate 60 percent working interest in this well.
37
The 2011 budget for Monument Butte is $1.3 million which includes the planned drilling of the
one remaining well in the six-well expansion project and the completion of the K Moon #2-13-4-3.
Budong-Budong Project, Indonesia
We acquired our initial 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. The initial commitment to fund the first phase of the exploration program
was capped at $17.2 million. The commitment cap 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 cap of each component was met, all subsequent costs are shared by the parties in
proportion to their ownership interests. Prior to drilling the first exploration well, our partner
had a one-time option to increase the level of the carried interest to a maximum of $20.0 million. On
September 15, 2010, our partner exercised their option to increase the carry obligation by $2.7
million to a total of $19.9 million ($7.9 million for acquisition of seismic and $12.0 million for
drilling). The additional carry increased our ownership by 7.4 percent to 54.4 percent. As of
February 28, 2011, we had fulfilled all funding obligations to earn our 54.4 percent interest in
the Budong PSC. On March 3, 2011, we received notice that the Government of Indonesia and BPMIGAS
had approved this change in ownership interest.
On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by
the operator to a third party, to acquire an additional ten percent equity in the Budong PSC for a
consideration of $3.7 million payable ten business days after completion of the first exploration
well. Closing of this acquisition will increase our interest in the Budong PSC to 64.4 percent.
The change in ownership interest is subject approval from the Government of Indonesia and BPMIGAS.
During the initial exploration period, the Budong PSC covered 1.35 million acres. The term of
the Budong PSC is for 30 years and provided for an exploration period of up to ten years. Pursuant
to the terms of the Budong PSC, at end of the first three-year exploration phase, 35 percent of the
original area was relinquished to BPMIGAS. The second three-year exploration phase began in January
2010 covering 0.88 million acres.
Operational activities during 2010 focused on well planning, construction for two test well
sites, and mobilization of rig and ancillary equipment to the first drill site. After delays in
acquiring permits to mobilize the drilling rig from its port location to the drilling pad, the
first exploratory well, the Lariang-1 (LG-1), was spud on January 6, 2011. The well is to be
drilled to a depth of approximately 7,200 feet. As of March 2, 2011, the well had reached
approximately 4,500 feet in the Miocene, the secondary objective, and has logged and wireline
tested several oil and gas sands. During the year ended December 31, 2010, we incurred $8.5
million for surveying, permitting, engineering and well planning and $4.3 million for seismic,
geological and geophysical, and exploration support costs. The 2011 budget for the Budong PSC is
$15.5 million.
Dussafu Project Gabon
Operational activities during 2010 included the maturation of the prospect inventory and well
planning. We have purchased all long lead items required for drilling, and they are either on
drill site or en route to the drill site. Other drilling contracts are being tendered in
preparation to spud the exploration well which is expected to occur at the beginning of the second
quarter of 2011. The exploratory well to be drilled in the second quarter of 2011 will test
stacked reservoir potential in the pre-salt section. A Letter of Intent has been agreed for a
semi-submersible rig to commence a contract in April 2011 to drill the Ruche Marin prospect. In
order to be able to complete the drilling activities, a six month extension to November 27, 2011 of
the second Exploration Period has been requested. During the year ended December 31, 2010, we
incurred $2.6 million for prospect inventory and well planning and $0.5 million for seismic data
processing and reprocessing. The 2011 budget for the Dussafu PSC is $15.6 million.
Block 64 EPSA Project Oman
Operational activities during the year ended December 31, 2010 included geological studies,
baseline environmental and social study and 3-D pre-stack depth migration reprocessing of
approximately 1,150 square kilometers of existing 3-D seismic data. During 2011 geological and
geophysical interpretation of the reprocessed 3-D will take place to mature drilling locations. Well planning and procurement of long lead items
will commence in the first half of 2011 to enable the first of the two exploratory wells to
commence drilling in the fourth quarter of
38
2011. We incurred $0.4 million for costs associated
with signing the license, including signature bonus and data compilation and $1.2 million for
seismic data processing and reprocessing. We expect to drill the first of two exploratory wells in
the second half of 2011. The 2011 budget for the Block 64 EPSA is $2.0 million.
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. As a
result, we have obtained license extensions, with the current extension in effect until May 31,
2011. We are in the process of obtaining a new license extension and believe that it will be
granted. While no assurance can be given, we believe we will continue to receive contract
extensions so long as the border disputes persist. Operational activities during 2010 include
costs related to maintenance of the license. The 2011 budget for WAB 21 is minimal consisting of costs
required to maintain the license.
Other Exploration Projects
Relating to other projects, we incurred $0.4 million during the year ended December 31, 2010.
The 2011 budget for other projects is minimal consisting of costs required to complete projects
started in 2010.
Any of the exploratory wells to be drilled in 2011 on the Budong PSC and the Dussafu PSC could
have a significant impact on our ability to obtain financing, record reserves and generate cash
flow in 2011 and beyond.
Fusion Geophysical, LLC (Fusion)
On January 28, 2011, Fusions 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a
private purchaser pursuant to an Agreement and Plan of Merger. We received $1.3 million for our
equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full
of the outstanding balance of the prepaid service agreement, short term loan and accrued interest.
The Agreement and Plan of Merger includes an Earn Out provision wherein we would receive an
additional payment of up to a maximum of $2.7 million if FusionGeo, Inc.s 2011 gross profit
exceeds $5.6 million. The Earn Out payment will not be determined until early in 2012. We can
give no assurance that we will receive any Earn Out payment. See Item 15 Exhibits and Financial
Statement Schedules Notes to Consolidated Financial Statements, Note 9 Investment in Equity
Affiliates Fusion Geophysical LLC.
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.
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. |
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. |
39
|
|
|
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. |
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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 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, 2010 and the financial condition as of December 31,
2010 and 2009 in conjunction with our consolidated financial statements and related notes thereto.
Years Ended December 31, 2010 and 2009
We reported net
income attributable to Harvest of $15.3 million, or $0.43 diluted earnings per
share, for the year ended December 31, 2010, compared with a net loss attributable to Harvest of
$3.1 million, or $(0.09) diluted earnings per share, for the year ended December 31, 2009.
Revenues were higher for the year ended December 31, 2010 compared with the year ended
December 31, 2009 due to production from the Monument Butte Extension wells and the Lower Green
River/Upper Wasatch wells. Production for the two areas for the years ended December 31, 2010 and
2009 were:
40
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December 31, 2010 |
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December 31, 2009 |
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|
Lower Green |
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|
Monument |
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|
Lower Green |
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|
Monument |
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|
|
River/Upper |
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Butte |
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|
River/Upper |
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Butte |
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|
Wasatch |
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|
Extension |
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|
Wasatch |
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|
Extension |
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Barrels of oil sold |
|
|
33,932 |
|
|
|
106,094 |
|
|
|
|
|
|
|
2,683 |
|
Thousand cubic feet of gas sold |
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|
6,257 |
|
|
|
416,779 |
|
|
|
|
|
|
|
5,780 |
|
Total barrels of oil equivalent |
|
|
34,975 |
|
|
|
175,558 |
|
|
|
|
|
|
|
3,646 |
|
Average price per barrel |
|
$ |
69.63 |
|
|
$ |
64.85 |
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|
$ |
|
|
|
$ |
61.57 |
|
Average price per thousand cubic feet |
|
$ |
3.97 |
|
|
$ |
3.43 |
|
|
$ |
|
|
|
$ |
2.77 |
|
Total expenses and other non-operating (income) expense (in millions):
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|
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|
|
|
|
|
|
|
|
Year Ended |
|
|
|
|
|
|
December 31, |
|
|
Increase |
|
|
|
2010 |
|
|
2009 |
|
|
(Decrease) |
|
Lease operating and production taxes |
|
$ |
1.8 |
|
|
$ |
|
|
|
$ |
1.8 |
|
Depletion, depreciation and amortization |
|
|
3.8 |
|
|
|
0.4 |
|
|
|
3.4 |
|
Exploration expense |
|
|
8.0 |
|
|
|
7.8 |
|
|
|
0.2 |
|
General and administrative |
|
|
26.7 |
|
|
|
21.9 |
|
|
|
4.8 |
|
Taxes other than on income |
|
|
1.0 |
|
|
|
1.0 |
|
|
|
|
|
Investment earnings and other |
|
|
(0.6 |
) |
|
|
(1.2 |
) |
|
|
0.6 |
|
Interest expense |
|
|
2.7 |
|
|
|
|
|
|
|
2.7 |
|
Other non-operating expense |
|
|
4.0 |
|
|
|
|
|
|
|
4.0 |
|
Loss on exchange rates |
|
|
1.6 |
|
|
|
0.1 |
|
|
|
1.5 |
|
Income tax expense |
|
|
(0.2 |
) |
|
|
1.2 |
|
|
|
(1.0 |
) |
Lease operating costs were higher for the year ended December 31, 2010 compared to the year
ended December 31, 2009 due to the inception of domestic oil and natural gas operations beginning
in late December 2009. Costs incurred were primarily for water disposal, gas gathering
transportation and processing, fuel and other routine oil production activities. Depletion
expense, which was entirely attributable to U.S. production, was $3.3 million and $0.03 million
($16.71 and $6.59 per BOE) for the years ended December 31, 2010 and 2009,
respectively.
Our accounting method for oil and gas properties is the successful efforts method. During the
year ended December 31, 2010, we incurred $6.4 million of exploration costs related to seismic,
geological and geophysical, and exploration support costs and $1.6 million related to other general
business development activity. Included in the $6.4 million of exploration costs is the one-time
charge of $1.2 million for acquisition of seismic data for the Budong PSC related to our partner in
the Budong PSC exercising their option to increase the carry obligation. 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 first prospect in the AMI.
General and administrative costs were higher in the year ended December 31, 2010, than in the
year ended December 31, 2009, primarily due to higher employee related costs of $3.8 million and by
a reversal in 2009 of $1.3 million of accruals no longer required offset by a reduction in other
general office costs of $0.3 million. Taxes other than on income for the year ended December 31,
2010, were consistent with the year ended December 31, 2009.
Investment earnings and other decreased in the year ended December 31, 2010 compared to the
year ended December 31, 2009 due to lower interest rates earned on lower average cash balances.
Interest expense was higher for the year ended December 31, 2010 compared to the year ended
December 31, 2009 due to interest associated with our $32.0 million senior convertible note
offering in February 2010, our $60.0 million term loan facility occurring in October 2010 and
amortization of discount on the term loan facility related to the warrants issued in connection
with the $60 million term loan facility offset by interest capitalized to oil and gas properties of
$1.8 million. Other non-operating expense was higher in the year ended December 31, 2010 compared
to the year ended
41
December 31, 2009 due to the expensing of $2.9 million of costs related to a
future financing which is no longer being pursued and $1.1 million of costs related to other
strategic alternatives.
Income tax expense was lower for the year ended December 31, 2010 compared to the year ended
December 31, 2009 due to the receipt a $1.0 million income tax refund related to the recovery of
alternative minimum tax for the tax years 2005 and 2007, $0.2 million
reversal of a tax provision no longer needed, and lower tax assessed in the Netherlands
of $0.7 million offset by $0.5 million of additional income taxes assessed to Harvest Vinccler in
2010 for the 2007 and 2008 tax years. The 2010 tax assessment was the result of a tax audit
conducted by the SENIAT.
Net income from unconsolidated equity affiliates includes an $84.4 million remeasurement gain
on revaluation of monetary assets and liabilities due to the Bolivar devaluation in January 2010
and a $19.5 million financing charge related to the blended exchange rate charged by the Central
Bank of Venezuela for the purchase of foreign currency. See Item 7 Managements Discussion and
Analysis of Financial Condition and Results of Operations Operations, Venezuela.
At December 31, 2009, we recorded a $1.6 million charge to fully impair the carrying value of
our equity investment in Fusion. For the year ended December 31, 2010 and 2009, Fusion reported a
net loss of $2.4 million and $4.8 million ($1.2 million and $2.4 million net to our 49 percent
interest), respectively. The loss for 2010 is not reported in the year ended December 31, 2010 net
income from unconsolidated equity affiliates as reporting it would take our equity investment into
a negative position. On January 28, 2011, our minority equity investment in Fusions 69 percent
owned subsidiary, FusionGeo, Inc., was acquired by a private purchaser pursuant to an Agreement and
Plan of Merger. We received $1.3 million for our equity investment, subject to post-closing
adjustments, and $0.7 million for the repayment in full of the outstanding balance of the prepaid
service agreement, short term loan and accrued interest.
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
(1.2 |
) |
|
|
(3.8 |
) |
|
|
2.6 |
|
Interest expense |
|
|
|
|
|
|
1.7 |
|
|
|
(1.7 |
) |
Loss on exchange rate |
|
|
0.1 |
|
|
|
0.2 |
|
|
|
(0.1 |
) |
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
42
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 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:
|
|
|
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. |
|
|
|
|
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 9 Investment in
Equity Affiliates for additional information.
43
Capital Resources and Liquidity
Our liquidity outlook has changed since December 31, 2009 primarily as a result of
funding requirements of our exploration projects and development of our oil and gas properties.
The oil and gas industry is a highly capital intensive and cyclical business with unique operating
and financial risks. In Item 1A Risk Factors, we discuss a number of variables and risks
related to our exploration projects and our minority equity investment in Petrodelta that could
significantly utilize our cash balances, affect our capital resources and liquidity. We also point
out that the total capital required to develop the fields in Venezuela may exceed Petrodeltas
available cash and financing capabilities, and that there may be operational or contractual
consequences due to this inability.
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. We require capital principally
to fund the exploration and development of new oil and gas properties. For calendar year 2011, we
have established a preliminary exploration and drilling budget of approximately $46.5 million. We
are concentrating a substantial portion of this budget on the development of our Antelope project,
the Budong PSC and the Dussafu PSC. As is common in the oil and gas industry, we have various
contractual commitments pertaining to exploration, development and production activities.
Currently, we have a work commitment of $22.0 million which is a minimum amount to be spent on the
Block 64 EPSA for the drilling of two wells over a
three-year period which expires in May 2012. We currently plan
to fund this commitment in 2012, and we may be required to raise
capital to do so. We
also have minimum work commitments during the various phases of the exploration periods in the
Budong PSC and Dussafu PSC.
As a petroleum exploration and production company, our revenue, profitability, cash flows, and
future rate of growth are substantially dependent on the condition of the oil and gas industry
generally, our success with our exploration program, and the belief that Petrodelta will fund its
own operations and continue to pay dividends. Because our revenues are generated from customers
with the same economic interests, our operations are also susceptible to market volatility
resulting from economic, cyclical, weather or other factors related to the energy industry.
Changes in the level of operating and capital spending in the industry, decreases in oil or gas
prices, or industry perceptions about future oil and gas prices could adversely affecting our
financial position, results of operations and cash flows. Based on
our current level of cash flow from operations, we will be required
to raise capital to meet our general and administrative costs and
fund our oil and gas programs.
Revenues from the Monument Butte Extension and Lower Green River/Upper Wasatch projects have
increased significantly during 2010; however, our primary source of cash still remains to be
dividends from Petrodelta and funding from debt financing. In November 2010, Petrodeltas board of
directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net
to our 32 percent interest). The dividend represents the remaining 50 percent of the cash
withdrawal rights as shareholders on Petrodeltas net income as reported under IFRS for the year
ended December 31, 2009. This dividend is subject to shareholder approval, and will not be paid by
Petrodelta until Petrodelta shareholder approval is received.
Shareholder approval was received on March 14, 2011. We expect to receive future
dividends from Petrodelta; however, we expect that in the near term Petrodelta will reinvest most
of its earnings into the company in support of its drilling and appraisal activities. Therefore,
there is uncertainty that Petrodelta will pay additional dividends in 2011 or 2012.
Additionally, any dividend received from Petrodelta carries a liability to our non-controlling
interest holder, Vinccler, for its 20 percent share. Dividends declared and paid by Petrodelta are
paid to HNR Finance, our consolidated subsidiary. HNR Finance must declare a dividend in order for
us and our non-controlling interest holder, Vinccler, to receive our respective shares of
Petrodeltas dividends. A dividend from HNR Finance is due upon demand. Currently, Vinccler has
not demanded its respective share of the two most recent Petrodelta dividends and has waived such a
demand until at least April 2012. As of December 31, 2010, Vincclers share of the undistributed
dividends is $9.0 million inclusive of the unpaid November 2010
dividend. See Item 15 Exhibits and Financial Statement Schedules, Notes to
Consolidated Financial Statements, Note 16 Related Party Transactions.
We have incurred significant debt during 2010 which has imposed restrictions on us and
increased our vulnerability to adverse economic and industry conditions. Our monthly and
semi-annual interest expense has increased significantly, and our senior convertible notes and term
loan facility impose new restrictions on us. Our senior convertible notes and term loan facility
impose covenant restrictions on us that limit our ability to obtain additional financing. Our
ability to meet these covenants is primarily dependent on meeting customary affirmative covenant
clauses, including providing consolidated statements to be audited and accompanied by a report and
opinion of an independent certified public accountant, which report and opinion shall not be
subject to any going concern or like qualification. Our inability to satisfy the covenants contained in our long
term debt arrangements would constitute an event of default, if not waived. An uncured default
could result in our outstanding debt becoming immediately due and payable. If this were to occur,
we may not be able to obtain waivers or secure alternative financing to satisfy our obligations,
either of which would have a material adverse impact on our business. As of December 31, 2010, we
were in compliance with all of our long term debt covenants.
At December 31, 2010, we had cash on hand of $58.7 million.
We believe that this cash plus cash generated from Petrodelta dividends and funding from debt financing combined with our
ability to vary the timing of our capital expenditures is sufficient to fund our operations and capital commitments through at
least December 31, 2011. However, if the Petrodelta dividend payment is not received as expected or our cash sources and
requirements are different than expected, it could have a material adverse effect on our operations.
In order to increase our liquidity to levels sufficient to meet our commitments, we are
currently pursuing a number of actions including possible delay of discretionary capital spending
to future periods, possible farm-out or sale of assets, or other monetization of asset as necessary
to maintain the liquidity required to run our operations. We continue to pursue, as appropriate,
additional actions designed to generate liquidity including seeking of financing sources, accessing
equity and debt markets, increasing production in our producing assets, and cost reductions.
Although we believe that we will have adequate liquidity to meet our future operating requirements
and to remain compliant with the covenants under our long term debt arrangements, the factors
described above create uncertainty. Our lack of cash flow and the unpredictability of cash
dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no
assurance adequate financing can be raised. Accordingly, there can be no assurances that any of
these possible efforts will be successful or adequate, and if they are not, our financial condition
and liquidity could be materially adversely affected.
44
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. The notes are general unsecured
obligations, ranking equally with all 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. The net proceeds are being used to fund capital expenditures and for working
capital needs and general corporate purposes.
In September 2010, we announced the retention of Bank of America Merrill Lynch to provide
advisory services to assist us in exploring a broad range of strategic alternatives for enhancing
shareholder value. These alternatives could include, but are not limited to, certain extraordinary
transactions, including, possibly, a sale of assets or a sale or merger of the Company.
On October 29, 2010, we announced the closing of a $60.0 million term loan facility with MSD
Energy, an affiliate of MSD Capital, L.P., as the sole lender under the term loan facility. Under
the terms of the term loan
facility, interest is paid on a monthly basis at the initial rate of 10 percent and the term
loan will mature on October 28, 2012. The initial rate of interest increases to 15 percent on July
28, 2011, the Bridge Date. The Bridge Date may be extended at our option for three months by
paying a fee to MSD Energy in the amount of five percent of the initial principal amount of the
term loan facility. The net proceeds of the term loan facility are approximately $59.5 million,
after deducting fees related to the transaction. The net proceeds of the term loan facility are
being used to fund capital expenditures and for working capital needs and general corporate
purposes. The term loan facility is a general unsecured obligation, ranking equally with all other
unsecured senior indebtedness and senior in right of payment to our subordinated indebtedness, if
any. MSD Energy Investments, L.P., an affiliate of MSD Capital, L.P., is currently a shareholder
and a convertible note holder of Harvest.
In connection with the term loan, we issued to MSD Energy (1) 1.2 million warrants exercisable
at any time on or after the closing date for a period of five years from the closing date on a
cashless exercise basis at $15 per share until the Bridge Date, at which time the exercise price
per share will equal the lower of $15 or 120 percent of the average closing bid price of Harvests
common stock for the 20 trading days immediately preceding the Bridge Date; (2) 0.4 million
warrants exercisable at any time on or after the closing date for a period of five years from the
closing date on a cashless exercise basis at $20 per share until the Bridge Date, at which time the
exercise price per share will equal the lower of $15 or 120 percent of the average closing bid
price of Harvests common stock for the 20 trading days immediately preceding the Bridge Date; and
(3) 4.4 million warrants exercisable at any time on or after the Bridge Date for a period of five
years from the Bridge Date on a cashless exercise basis at the lower of $15 per share or 120
percent of the average closing price of Harvests common stock for the 20 trading days immediately
preceding the Bridge Date. The 4.4 million warrants may be redeemed by Harvest for $0.01 per share
at any time prior to the Bridge Date in conjunction with the repayment of the loan prior to the
Bridge Date.
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 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. On January 4, 2011,
the Venezuelan government published in the Official Gazette the Exchange Agreement which eliminated
the 2.60 Bolivars per U.S. Dollar exchange rate with an effective date of January 1, 2011. 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. We expect to receive future dividends from Petrodelta; however, we
expect that in the near term Petrodelta will reinvest most of its earnings into the company in
support of its drilling and appraisal activities. At
45
CVPs instructions, Petrodelta set up a
reserve within the equity section of its balance sheet for deferred tax assets. The setting up of
the reserve had no effect on Petrodeltas financial position, results of operations or cash flows.
However, the new reserve could have a negative impact on the amount of dividends received in the
future. It was anticipated that all of Petrodeltas available cash generated during 2010, and is
still anticipated for 2011, would be used to meet Petrodeltas current operating requirements and
would not be available for dividends. However, in August 2010, Petrodeltas board of directors
declared a dividend of $30.5 million, $12.2 million net to HNR Finance ($9.8 million net to our 32
percent interest), which was received on October 22, 2010. Petrodeltas board of directors
declared another dividend in November 2010 of $30.6 million. This dividend is pending approval by
Petrodeltas shareholders and will not be paid until approval is
received. Shareholder approval was received on March 14, 2011. There is no certainty
that Petrodelta will pay additional dividends in 2011 or 2012. See Item 1A Risk Factors and
Item 7 Managements Discussion and Analysis of Financial Condition and Results of Operations for
a 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) |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Net cash provided by (used in) operating activities |
|
$ |
(5,296 |
) |
|
$ |
(34,945 |
) |
|
$ |
50,380 |
|
Net cash used in investing activities |
|
|
(59,061 |
) |
|
|
(28,603 |
) |
|
|
(23,055 |
) |
Net cash provided by (used in) used in financing activities |
|
|
90,743 |
|
|
|
(1,300 |
) |
|
|
(51,001 |
) |
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
$ |
26,386 |
|
|
$ |
(64,848 |
) |
|
$ |
(23,676 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working Capital |
|
|
45,199 |
|
|
|
34,539 |
|
|
|
77,010 |
|
Current Ratio |
|
|
2.6 |
|
|
|
3.1 |
|
|
|
3.0 |
|
Total Cash, including restricted cash |
|
|
58,703 |
|
|
|
32,317 |
|
|
|
97,165 |
|
Total Debt |
|
|
81,237 |
|
|
|
|
|
|
|
|
|
The
increase in working capital of $10.7 million was primarily a result of increases in
long-term debt of $92.0 million and oil and gas revenue of $10.5 million offset by the dividend
received from Petrodelta of $12.2 million, capital expenditures of $59.6 million, net decrease in
other current assets of $4.5 million, net increase in accounts payable and other accrued expenses
of $4.2 million and administrative expenses, including interest on debt, of $11.2 million.
Cash Flow from Operating Activities. During the years ended December 31, 2010 and 2009, net
cash used in operating activities was approximately $5.3 million and $34.9 million, respectively.
The $29.6 million increase was primarily due to net working capital increases of $17.0 million
primarily related to increased oil and gas operations in Utah and Indonesia, increase in oil and
gas revenue of $10.5 million, increase in earnings of unconsolidated affiliate of $18.2 million,
offset by an increase in administrative expenses of $11.2 million.
Cash Flow from Investing Activities. During the year ended December 31, 2010, we had cash
capital expenditures of approximately $59.6 million. Of the 2010 expenditures, $47.8 million was
attributable to activity on the Antelope projects, $8.5 million was attributable to activity on the
Budong PSC, $2.6 million was attributable to activity on the Dussafu PSC and $0.7 million was
attributable to other projects. 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 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, 2010, we expensed $0.5 million of investigative costs related to new business development
projects and $2.9 million of costs related to a future financing neither of which are currently
being pursued. During the year ended December 31, 2009, we incurred
$0.6 million of investigative
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 $46.5 million for 2011 for U.S., Indonesia, Gabon
and Oman operations will be funded through our existing cash balances, accessing equity and debt
markets, and cost reductions. In addition, we could
delay the discretionary portion of our capital
spending to future periods or sell assets as necessary to maintain the liquidity required to run
our operations, as warranted.
46
Cash Flow from Financing Activities. During the year ended December 31, 2010, we closed an
offering of $32.0 million in aggregate principal amount of our 8.25 percent senior convertible
notes as well as a $60.0 million term loan facility, incurred $2.9 million in deferred financings
costs related to the $32.0 million convertible debt offering and the $60.0 million term loan
facility that are being amortized over the life of the financial instruments. During the year
ended December 31, 2009 we incurred $1.7 million in legal fees associated with prospective
financing.
Contractual Obligations
We have a lease obligation of approximately $30,400 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 $7,000 per month. This lease runs through November
2011. We also have lease commitments for an office in Utah for approximately $6,000 per month, an
office in Singapore for approximately $7,000 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 $9,000 per month. These leases expire
in September 2012, October 2012, March 2011, August 2011 and September 2015, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments (in thousands) Due by Period |
|
|
|
|
|
|
|
Less than |
|
|
|
|
|
|
|
|
|
|
After 4 |
|
Contractual Obligation |
|
Total |
|
|
1 Year |
|
|
1-2 Years |
|
|
3-4 Years |
|
|
Years |
|
Debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.25% Senior Convertible Note Due 2013 |
|
$ |
32,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
32,000 |
|
|
$ |
|
|
10.00% Term Loan Facility Due 2012 |
|
|
60,000 |
|
|
|
|
|
|
|
60,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Debt |
|
|
92,000 |
|
|
|
|
|
|
|
60,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest payments |
|
|
20,350 |
|
|
|
10,140 |
|
|
|
9,763 |
|
|
|
447 |
|
|
|
|
|
Asset retirement obligation |
|
|
663 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
663 |
|
Oil and gas activities(1) |
|
|
22,650 |
|
|
|
650 |
|
|
|
22,000 |
|
|
|
|
|
|
|
|
|
Office leases |
|
|
2,435 |
|
|
|
764 |
|
|
|
651 |
|
|
|
542 |
|
|
|
478 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other obligations |
|
|
46,098 |
|
|
|
11,554 |
|
|
|
32,414 |
|
|
|
989 |
|
|
|
1,141 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations |
|
$ |
138,098 |
|
|
$ |
11,554 |
|
|
$ |
92,414 |
|
|
$ |
32,989 |
|
|
$ |
1,141 |
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(1) |
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As is common in the oil and gas industry, we have various contractual
commitments pertaining to exploration, development and production activities. At
December 31, 2010, we had $0.7 million of commitments related to a drilling rig and
other equipment for our domestic operations. The commitment for the drilling rig of
$0.6 million was met in January 2011. We also have a funding commitment of $22.0
million on the Block 64 EPSA for the drilling of two wells over a three-year period
which expires in May 2012. |
We have minimum work funding commitments during the various phases of the exploration periods
in the Budong PSC and Dussafu PSC. Due to the uncertainty of when these commitments will be
incurred, these minimum work funding commitments are not included in the above table.
Senior Convertible Note
On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of
our 8.25 percent senior convertible notes. Under the terms of the notes, interest is payable
semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2010. The
senior convertible notes will mature on March 1, 2013, unless earlier redeemed, repurchased or
converted. See Item 7 Managements Discussion and Analysis of Financial Condition and Results
of Operations Capital Resources and Liquidity.
47
Term Loan Facility
On October 29, 2010, we announced the closing of a $60.0 million term loan facility with MSD
Energy, an affiliate of MSD Capital, L.P., as the sole lender under the term loan facility. The
net proceeds of the term loan facility are approximately $59.5 million, after deducting fees
related to the transaction. Under the terms of the term loan facility, interest is paid on a
monthly basis at the initial rate of 10 percent and the term loan will mature on October 28, 2012.
See Item 7 Managements Discussion and Analysis of Financial Condition and Results of
Operations Capital Resources and Liquidity.
Effects of Changing Prices, Foreign Exchange Rates and Inflation
Our results of operations and cash flow are affected by changing oil prices. Fluctuations in
oil prices may affect our total planned development activities and capital expenditure program.
Our net foreign exchange losses attributable to our international operations were $1.6 million
for the year ended December 31, 2010. The U.S. Dollar and Bolivar exchange rates had not been
adjusted from March 2005 until January 2010. However, there are many factors affecting foreign
exchange rates and resulting exchange gains and losses, most of which are beyond our control. It
is not possible for us to predict the extent to which we may be affected by future changes in
exchange rates and exchange controls.
Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official
exchange rate in February 2004, March 2005, January 2010 and again in January 2011. On January 8,
2010, the Venezuelan government published in the Official Gazette the Exchange Agreement, which
established new exchange rates for the Bolivar/U.S. Dollar currencies that went into effect on
January 11, 2010. On January 4, 2011, the Venezuelan government published in the Official Gazette
the Exchange Agreement which eliminated the 2.60 Bolivars
per U.S. Dollar exchange rate with an
effective date of January 1, 2011.
Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official
prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30
Bolivars per U.S. Dollar). However, in October 2010, Harvest Vinccler exchanged approximately $0.2
million through SITME and received an exchange rate of 5.19 Bolivars per U.S. Dollar. The monetary
assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid
expenses and other current assets. The monetary liabilities that are exposed to exchange rate
fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and
liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar
exchange rate. Harvest Vinccler and Petrodelta do not have, and have not had, any Bolivars pending
government approval for settlement for U.S. Dollars at the official exchange rate.
See Item 7 Managements Discussion and Analysis of Financial Condition and Results of
Operations Operations, Venezuela for a more complete discussion of the exchange agreements and
their effects on our Venezuelan operations.
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.
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
48
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.
There are many factors we consider when evaluating our equity investments for possible
impairment. Currency devaluations, inflationary economies and cash flow analysis are some of the
factors we consider in our evaluation. Since the Venezuelan currency devaluations have not
significantly affected Petrodeltas business and any dividends declared by Petrodelta are required
to be paid in U.S. Dollars per the conversion contract, we do not believe an impairment of the
investment of the asset is warranted at this time. See Item 7 Managements Discussion and
Analysis of Financial Condition and Results of Operations Venezuela for a complete description
of the situation in Venezuela and other matters. At December 31, 2010 and 2009, there were no
events that caused us to evaluate our investment in Petrodelta for impairment.
Capitalized Interest
We capitalize interest costs for qualifying oil and gas properties. The capitalization period
begins when expenditures are incurred on qualified properties, activities begin which necessary to
prepare the property for production and interest costs have been incurred. The capitalization
period continues as long as these events occur. The average additions for the period are used in
the interest capitalization calculation.
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
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.
49
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 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
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.
The reserves included herein were estimated using deterministic methods and presented as
incremental quantities. Under the deterministic incremental approach, discrete quantities of
reserves are estimated and assigned separately as proved, probable or possible based on their
individual level of uncertainty. Because of the differences in uncertainty, caution should be
exercised when aggregating quantities of oil and gas from different reserves categories.
Furthermore, the reserves and income quantities attributable to the different reserve categories
that are included herein have not been adjusted to reflect these varying degrees of risk associated
with them and thus are not comparable.
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
50
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 January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update (ASU) No. 2010-06, which is included in the Accounting Standards Codification (ASC)
under 820, Fair Value Measurements and Disclosures (ASC 820). This update requires the
disclosure of transfers between the observable input categories and activity in the unobservable
input category for fair value measurements. The guidance also requires disclosures about the
inputs and valuation techniques used to measure fair value and became effective for our interim and
annual reporting periods beginning January 1, 2010. The adoption of this guidance did not have an
impact on our consolidated financial position, results of operations or cash flows.
In February 2010, the FASB issued ASU No. 2010-09, which is included in the Codification under
ASC 855, Subsequent Events (ASC 855). This update removes the requirement for an SEC filer to
disclose the date through which subsequent events have been evaluated and became effective for our
interim and annual reporting periods beginning January 1, 2010. The adoption of this guidance did
not have an impact on our consolidated financial position, results of operations or cash flows.
In March 2010, the FASB issued ASU No. 2010-11, which is included in the Codification under
ASC 815, Derivatives and Hedging (ASC 815). This update clarifies the type of embedded credit
derivative that is exempt from embedded derivative bifurcation requirements. Only an embedded
credit derivative that is related to the subordination of one financial instrument to another
qualifies for the exemption. This guidance became effective for our interim and annual reporting
periods beginning January 1, 2010. The adoption of this guidance did not have a material impact on
our consolidated financial position, results of operations or cash flows.
In May 2010, the FASB issued ASU No. 2010-19, which is included in ASC under 830, Foreign
Currency (ASC 830). This update addresses the multiple foreign currency exchange rates and the
impact of highly inflationary accounting in Venezuela. Since the U.S. Dollar is the functional and
reporting currency for all of our Venezuela entities, the adoption of this update did not have an
impact on our consolidated financial position, results of operations or cash flows.
In July 2010, the FASB issued ASU 2010-20 Receivables (Topic 310): Disclosures about the
Credit Quality of Financing Receivables and the Allowance for Credit Losses (ASU 2010-20), which
amends existing guidance by requiring more robust and disaggregated disclosures by an entity about
the credit quality of its financing receivables and its allowance for credit losses. These
disclosures will provide financial statement users with
51
additional information about the nature of
credit risks inherent in financing receivables, how credit risks are analyzed and assessed in
determining allowance for credit losses, and reasons for any changes made in allowance for credit
losses. This update is generally effective for interim and annual reporting periods ending on or
after December 15, 2010; however, certain aspects of the update pertaining to activity that occurs
during a reporting period are effective for interim and annual reporting periods beginning on or
after December 15, 2010. The adoption of ASU 2010-20 did not have a material impact on our
consolidated financial position, results of operations or cash flows.
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.
We currently do not have any oil production that is hedged. While hedging limits the downside
risk of adverse price movements, it may also limit future revenues from favorable price movements.
Interest Rates
Total long-term debt at December 31, 2010 consisted of $32 million of fixed-rate unsecured
senior convertible notes maturing in 2013 unless earlier redeemed, purchased or converted and $60
million of fixed-rate unsecured term loan facility maturing in 2012. A hypothetical 10 percent
adverse change in the floating rate would not have a material effect on our results of operations
for the year ended December 31, 2010.
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.
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
52
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, 2010, 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, 2010. The effectiveness of our internal control over
financial reporting as of December 31, 2010, has been audited by PricewaterhouseCoopers LLP, an independent
registered public accounting firm, as stated in their report which appears herein.
Changes in Internal Control over Financial Reporting. There have been no changes in internal
control over financial reporting during the quarter ended December 31, 2010 that have materially
affected or are reasonably likely to materially affect that Companys internal control over
financial reporting.
Item 9B. Other Information
None.
53
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 2011 Annual Meeting of Stockholders.
Item 11. Executive Compensation
Please refer to the information under the caption Executive Compensation in our Proxy
Statement for the 2011 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 2011 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 2011 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 2011 Annual Meeting of Stockholders.
54
PART IV
Item 15. Exhibits and Financial Statement Schedules
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S-2 |
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S-5 |
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All other schedules are omitted because they are not applicable or the required information is
shown in the financial statements or the notes thereto.
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3.1 |
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Amended and Restated Certificate of Incorporation. (Incorporated by reference
to Exhibit 3.1 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.) |
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3.2 |
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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.) |
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4.1 |
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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.) |
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4.2 |
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Certificate of Designation, Rights and Preferences of the Series B Preferred
Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to
Exhibit 4.2 to our Form 10-Q filed on November 9, 2010, File No. 1-10762.) |
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4.3 |
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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.) |
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4.4 |
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Amendment to Third Amended and Restated Rights Agreement, dated as of October
28, 2010, between Harvest Natural Resources, Inc. and Wells Fargo Bank, N.A.
(Incorporated by reference to Exhibit 4.1 to our Form 8-K filed on October 29, 2010,
File No. 1-10762.) |
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4.5 |
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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.) |
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4.6 |
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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.) |
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4.7 |
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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.) |
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4.8 |
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Warrant Purchase Agreement, dated as of October 28, 2010, between Harvest
Natural Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by
reference to Exhibit 4.2 to our Form 8-K filed on October 29, 2010, File No. 1-10762.) |
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4.9 |
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Common Stock Purchase Warrant No. W-1, dated as of October 28, 2010, between
Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC.
(Incorporated by reference to Exhibit 4.3 to our Form 8-K filed on October 29, 2010,
File No. 1-10762.) |
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4.10 |
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Common Stock Purchase Warrant No. W-2, dated as of October 28, 2010, between
Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC.
(Incorporated by reference to Exhibit 4.4 to our Form 8-K filed on October 29, 2010,
File No. 1-10762.) |
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4.11 |
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Common Stock Purchase Warrant No. W-3, dated as of October 28, 2010, between
Harvest Natural Resources, Inc. and MSD Energy Investments Private II, LLC.
(Incorporated by reference to Exhibit 4.5 to our Form 8-K filed on October 29, 2010,
File No. 1-10762.) |
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10.1 |
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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).) |
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10.2 |
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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).) |
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10.3 |
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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.) |
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10.4 |
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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.) |
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10.5 |
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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.) |
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10.6 |
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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.) |
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10.7 |
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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.) |
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10.8 |
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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.) |
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10.9 |
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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.) |
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10.10 |
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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.) |
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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.) |
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10.12 |
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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].) |
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10.13 |
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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.) |
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10.14 |
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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.) |
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10.15 |
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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.) |
57
|
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.) |
|
|
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.) |
|
|
10.36 |
|
2010 Long Term Incentive Plan. (Incorporated by reference to Appendix A to
the Companys Definitive Proxy Statement on Schedule 14A filed with the Securities and
Exchange Commission on April 9, 2010, File No. 1-10762.) |
|
|
10.37 |
|
Form of 2010 Long Term Incentive Plan Employee Restricted Stock Award
Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August
9, 2010, File No. 1-10762.) |
|
|
10.38 |
|
Form of 2010 Long Term Incentive Plan Stock Option Award Agreement.
(Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2010,
File No. 1-10762.) |
|
|
10.39 |
|
Form of 2010 Long Term Incentive Plan Director Restricted Stock Award
Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August
9, 2010, File No. 1-10762.) |
58
|
10.40 |
|
Credit Agreement, dated as of October 28, 2010, between Harvest Natural
Resources, Inc. and MSD Energy Investments Private II, LLC. (Incorporated by reference
to Exhibit 10.1 to our Form 8-K filed on October 29, 2010, File No. 1-10762.) |
|
|
10.41 |
|
Guaranty, dated as of October 28, 2010, by Harvest (US) Holdings, Inc.,
Harvest Natural Resources, Inc. (UK) and Harvest Offshore China Company in favor of MSD
Energy Investments Private II, LLC. (Incorporated by reference to Exhibit 10.2 to our
Form 8-K filed on October 29, 2010, File No. 1-10762.) |
|
|
10.42 |
|
Term Note, dated as of October 28, 2010, of Harvest Natural Resources, Inc. in
favor of MSD Energy Investments Private II, LLC. (Incorporated by reference to Exhibit
10.3 to our Form 8-K filed on October 29, 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 24, 2011 between Harvest (US) Holdings, Inc. and
Ryder Scott Company. |
|
|
99.2 |
|
Reserve report dated February 24, 2011 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. |
59
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, 2010 and December 31, 2009, and the results of
their operations and their cash flows for each of the three years in the period ended December 31,
2010 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, 2010, 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.
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, 2011
S-1
HARVEST
NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(in thousands, except per share data) |
|
ASSETS |
|
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
58,703 |
|
|
$ |
32,317 |
|
Accounts and notes receivable, net |
|
|
|
|
|
|
|
|
Oil and gas revenue receivable |
|
|
1,907 |
|
|
|
166 |
|
Joint interest and other |
|
|
2,325 |
|
|
|
8,047 |
|
Note receivable |
|
|
3,420 |
|
|
|
3,265 |
|
Advances to equity affiliate |
|
|
1,706 |
|
|
|
4,927 |
|
Prepaid expenses and other |
|
|
4,793 |
|
|
|
2,214 |
|
|
|
|
|
|
|
|
TOTAL CURRENT ASSETS |
|
|
72,854 |
|
|
|
50,936 |
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS |
|
|
2,477 |
|
|
|
3,613 |
|
INVESTMENT IN EQUITY AFFILIATES |
|
|
287,933 |
|
|
|
233,989 |
|
PROPERTY AND EQUIPMENT: |
|
|
|
|
|
|
|
|
Oil and gas properties (successful efforts method) |
|
|
126,781 |
|
|
|
58,543 |
|
Other administrative property |
|
|
3,209 |
|
|
|
3,085 |
|
|
|
|
|
|
|
|
|
|
|
129,990 |
|
|
|
61,628 |
|
Accumulated depreciation and amortization |
|
|
(5,010 |
) |
|
|
(1,387 |
) |
|
|
|
|
|
|
|
|
|
|
124,980 |
|
|
|
60,241 |
|
|
|
|
|
|
|
|
|
|
$ |
488,244 |
|
|
$ |
348,779 |
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
Joint interest and royalty payable |
|
$ |
675 |
|
|
$ |
|
|
Accounts payable, trade and other |
|
|
2,530 |
|
|
|
696 |
|
Accounts payable carry obligation |
|
|
8,395 |
|
|
|
|
|
Accrued expenses |
|
|
15,087 |
|
|
|
9,920 |
|
Accrued interest |
|
|
896 |
|
|
|
4,691 |
|
Income taxes payable |
|
|
72 |
|
|
|
1,090 |
|
|
|
|
|
|
|
|
TOTAL CURRENT LIABILITIES |
|
|
27,655 |
|
|
|
16,397 |
|
OTHER LONG TERM LIABILITIES |
|
|
1,834 |
|
|
|
333 |
|
LONG TERM DEBT |
|
|
81,237 |
|
|
|
|
|
ASSET RETIREMENT LIABILITY |
|
|
663 |
|
|
|
50 |
|
COMMITMENTS AND CONTINGENCIES (See Note 4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2010 and 2009; issued 40,103 shares and 39,495
shares at December 31, 2010 and 2009, respectively |
|
|
401 |
|
|
|
395 |
|
Additional paid-in capital |
|
|
230,362 |
|
|
|
213,337 |
|
Retained earnings |
|
|
141,584 |
|
|
|
126,244 |
|
Treasury stock, at cost, 6,475 shares and 6,448 shares at
December 31, 2010 and 2009, respectively |
|
|
(65,543 |
) |
|
|
(65,383 |
) |
|
|
|
|
|
|
|
TOTAL HARVEST STOCKHOLDERS EQUITY |
|
|
306,804 |
|
|
|
274,593 |
|
NONCONTROLLING INTEREST |
|
|
70,051 |
|
|
|
57,406 |
|
|
|
|
|
|
|
|
TOTAL EQUITY |
|
|
376,855 |
|
|
|
331,999 |
|
|
|
|
|
|
|
|
|
|
$ |
488,244 |
|
|
$ |
348,779 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
S-2
HARVEST
NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in thousands, except per share data) |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
9,243 |
|
|
$ |
165 |
|
|
$ |
|
|
Gas sales |
|
|
1,453 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,696 |
|
|
|
181 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating costs and production taxes |
|
|
1,846 |
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
|
3,817 |
|
|
|
436 |
|
|
|
201 |
|
Exploration expense |
|
|
8,016 |
|
|
|
7,824 |
|
|
|
16,402 |
|
Dry hole costs |
|
|
|
|
|
|
|
|
|
|
10,828 |
|
General and administrative |
|
|
26,660 |
|
|
|
21,854 |
|
|
|
27,215 |
|
Taxes other than on income |
|
|
1,048 |
|
|
|
1,026 |
|
|
|
(206 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
41,387 |
|
|
|
31,140 |
|
|
|
54,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from Operations |
|
|
(30,691 |
) |
|
|
(30,959 |
) |
|
|
(54,440 |
) |
Other Non-Operating Income (Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
Gain on Financing Transactions |
|
|
|
|
|
|
|
|
|
|
3,421 |
|
Investment earnings and other |
|
|
557 |
|
|
|
1,168 |
|
|
|
3,849 |
|
Interest expense |
|
|
(2,689 |
) |
|
|
(5 |
) |
|
|
(1,730 |
) |
Other non-operating expense |
|
|
(3,952 |
) |
|
|
|
|
|
|
|
|
Loss on exchange rates |
|
|
(1,588 |
) |
|
|
(83 |
) |
|
|
(186 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,672 |
) |
|
|
1,080 |
|
|
|
5,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from Consolidated Companies Before Income Taxes |
|
|
(38,363 |
) |
|
|
(29,879 |
) |
|
|
(49,086 |
) |
Income Tax
Expense (Benefit) |
|
|
(184 |
) |
|
|
1,182 |
|
|
|
25 |
|
|
|
|
|
|
|
|
|
|
|
Loss from Consolidated Companies |
|
|
(38,179 |
) |
|
|
(31,061 |
) |
|
|
(49,111 |
) |
Net Income from Unconsolidated Equity Affiliates |
|
|
66,164 |
|
|
|
35,757 |
|
|
|
34,576 |
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
|
27,985 |
|
|
|
4,696 |
|
|
|
(14,535 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Net Income Attributable to Noncontrolling Interest |
|
|
12,645 |
|
|
|
7,803 |
|
|
|
6,929 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to Harvest |
|
$ |
15,340 |
|
|
$ |
(3,107 |
) |
|
$ |
(21,464 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to Harvest Per Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
|
$ |
(0.63 |
) |
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.43 |
|
|
|
(0.09 |
) |
|
$ |
(0.63 |
) |
|
|
|
|
|
|
|
|
|
|
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,
2008 |
|
|
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 |
|
|
Issuance of common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of stock options |
|
|
419 |
|
|
|
4 |
|
|
|
1,670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,674 |
|
Employee stock-based
compensation |
|
|
189 |
|
|
|
2 |
|
|
|
4,233 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,235 |
|
Discount on debt |
|
|
|
|
|
|
|
|
|
|
11,122 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,122 |
|
Purchase of treasury shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(160 |
) |
|
|
|
|
|
|
(160 |
) |
Net Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,340 |
|
|
|
|
|
|
|
12,645 |
|
|
|
27,985 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010 |
|
|
40,103 |
|
|
$ |
401 |
|
|
$ |
230,362 |
|
|
$ |
141,584 |
|
|
$ |
(65,543 |
) |
|
$ |
70,051 |
|
|
$ |
376,855 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Cash Flows From Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
27,985 |
|
|
$ |
4,696 |
|
|
$ |
(14,535 |
) |
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
|
3,817 |
|
|
|
436 |
|
|
|
201 |
|
Amortization of debt financing costs |
|
|
793 |
|
|
|
|
|
|
|
|
|
Write off of deferred financing costs |
|
|
2,795 |
|
|
|
|
|
|
|
|
|
Amortization of discount on debt |
|
|
359 |
|
|
|
|
|
|
|
|
|
Dry hole costs |
|
|
|
|
|
|
|
|
|
|
10,828 |
|
Gain on financing transactions |
|
|
|
|
|
|
|
|
|
|
(3,421 |
) |
Net income from unconsolidated equity affiliates |
|
|
(66,164 |
) |
|
|
(35,757 |
) |
|
|
(34,576 |
) |
Non-cash compensation related charges |
|
|
4,234 |
|
|
|
4,087 |
|
|
|
6,061 |
|
Dividend received from equity affiliate |
|
|
12,220 |
|
|
|
|
|
|
|
72,530 |
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts and notes receivable |
|
|
3,826 |
|
|
|
92 |
|
|
|
548 |
|
Advances to equity affiliate |
|
|
3,221 |
|
|
|
(1,195 |
) |
|
|
12,620 |
|
Prepaid expenses and other |
|
|
(2,579 |
) |
|
|
(1,055 |
) |
|
|
(5,632 |
) |
Joint interest and royalty payable |
|
|
675 |
|
|
|
|
|
|
|
|
|
Accounts payable |
|
|
1,835 |
|
|
|
(966 |
) |
|
|
(2,957 |
) |
Accounts payable, related party |
|
|
|
|
|
|
|
|
|
|
(10,093 |
) |
Advance from equity affiliate |
|
|
|
|
|
|
|
|
|
|
20,750 |
|
Accrued expenses |
|
|
5,738 |
|
|
|
(6,629 |
) |
|
|
(1,073 |
) |
Accrued interest |
|
|
(4,534 |
) |
|
|
|
|
|
|
(445 |
) |
Other long term liabilities |
|
|
1,501 |
|
|
|
333 |
|
|
|
|
|
Income taxes payable |
|
|
(1,018 |
) |
|
|
1,013 |
|
|
|
(426 |
) |
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used In) Operating Activities |
|
|
(5,296 |
) |
|
|
(34,945 |
) |
|
|
50,380 |
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Additions of property and equipment |
|
|
(59,619 |
) |
|
|
(28,022 |
) |
|
|
(26,317 |
) |
Investments in equity affiliates |
|
|
|
|
|
|
|
|
|
|
(2,161 |
) |
Decrease in restricted cash |
|
|
|
|
|
|
|
|
|
|
6,769 |
|
Investment costs |
|
|
558 |
|
|
|
(581 |
) |
|
|
(1,346 |
) |
|
|
|
|
|
|
|
|
|
|
Net Cash Used In Investing Activities |
|
|
(59,061 |
) |
|
|
(28,603 |
) |
|
|
(23,055 |
) |
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds from issuances of common stock |
|
|
1,674 |
|
|
|
386 |
|
|
|
1,565 |
|
Proceeds from issuance of long-term debt |
|
|
92,000 |
|
|
|
|
|
|
|
|
|
Purchase of treasury stock |
|
|
|
|
|
|
|
|
|
|
(29,416 |
) |
Financing costs |
|
|
(2,931 |
) |
|
|
(1,686 |
) |
|
|
(1,075 |
) |
Payments of note payable |
|
|
|
|
|
|
|
|
|
|
(7,211 |
) |
Dividend paid to minority interest |
|
|
|
|
|
|
|
|
|
|
(14,864 |
) |
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used In) Financing Activities |
|
|
90,743 |
|
|
|
(1,300 |
) |
|
|
(51,001 |
) |
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents |
|
|
26,386 |
|
|
|
(64,848 |
) |
|
|
(23,676 |
) |
Cash and Cash Equivalents at Beginning of Year |
|
|
32,317 |
|
|
|
97,165 |
|
|
|
120,841 |
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Year |
|
$ |
58,703 |
|
|
$ |
32,317 |
|
|
$ |
97,165 |
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosures of Cash Flow Information: |
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for interest expense
(net of capitalization) |
|
$ |
1,380 |
|
|
$ |
5 |
|
|
$ |
768 |
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for income taxes |
|
$ |
834 |
|
|
$ |
169 |
|
|
$ |
456 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
S-5
Supplemental Schedule of Noncash Investing and Financing Activities:
During the year ended December 31, 2010, we issued 0.3 million shares of restricted stock
valued at $1.8 million. Also some of our employees elected to pay withholding tax on restricted
stock grants on a cashless basis, which resulted in 26,260 shares being added to treasury stock at
cost; and 1,000 shares held in treasury that had been reissued as restricted stock were forfeited
and returned to treasury.
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.
See accompanying notes to consolidated financial statements.
S-6
HARVEST
NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Note 1 Organization
Harvest Natural Resources, Inc. (Harvest) is an independent energy company engaged in the
acquisition, exploration, development, production and disposition of oil and natural gas properties
since 1989, when it was incorporated under Delaware law.
We have significant interests in the Bolivarian Republic of Venezuela (Venezuela). Our
Venezuelan interests are owned through HNR Finance, B.V. (HNR Finance). Our ownership of HNR
Finance is through several corporations in all of which we have direct controlling interests.
Through these corporations, we indirectly own 80 percent of HNR Finance and our partner, Oil & Gas
Technology Consultants (Netherlands) Coöperatie U.A., a controlled affiliate of Venezolana de
Inversiones y Construcciones Clerico, C.A. (Vinccler), indirectly owns the remaining 20 percent
interest in HNR Finance. HNR Finance owns 40 percent of Petrodelta, S.A. (Petrodelta). As we
indirectly own 80 percent of HNR Finance, we indirectly own a net 32 percent interest in Petrodelta
(80 percent of 40 percent), and Vinccler indirectly owns eight percent (20 percent of 40 percent).
Corporación Venezolana del Petroleo S.A. (CVP) owns the remaining 60 percent of Petrodelta.
Petrodelta is governed by its own charter and bylaws and operates a portfolio of properties in
eastern Venezuela including large proven oil fields as well as properties with substantial
opportunities for both development and exploration. HNR Finance has a direct controlling interest
in Harvest Vinccler S.C.A. (Harvest Vinccler). Harvest Vincclers main business purposes are to
assist us in the management of Petrodelta and in negotiations with Petroleos de Venezuela S.A.
(PDVSA). We do not have a business relationship with Vinccler outside of Venezuela.
In addition to our interests in Venezuela, we have exploration acreage in the Gulf Coast
Region of the United States, mainly onshore in West Sulawesi in the Republic of Indonesia
(Indonesia), offshore of the Republic of Gabon (Gabon), onshore in the Sultanate of Oman
(Oman), and offshore of the Peoples Republic of China (China). We also have developed acreage
in the Antelope project in the Western United States in the Monument Butte Extension Appraisal and
Development Project (Monument Butte Extension) and Lower Green River/Upper Wasatch Oil
Delineation and Development Project (Lower Green River/Upper Wasatch) where we have established
production. See Note 10 United States, Note 11 Indonesia, Note 12 Gabon and Note 13
Oman and Note 14 China.
Note 2 Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of all wholly-owned and
majority-owned subsidiaries. All intercompany profits, transactions and balances have been
eliminated.
Reporting and Functional Currency
The United States Dollar (U.S. Dollar) is the reporting and functional currency for all of
our controlled subsidiaries and Petrodelta. Amounts denominated in non-U.S. Dollar currencies are
re-measured into U.S. Dollars, and all currency gains or losses are recorded in the consolidated
statement of operations. We attempt to manage our operations in such a manner as to reduce our
exposure to foreign exchange losses. However, there are many factors that affect foreign exchange
rates and resulting exchange gains and losses, many of which are beyond our influence.
On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange
Agreement, which established new exchange rates for the Venezuela Bolivar (Bolivar)/U.S. Dollar
currencies that went into effect on January 11, 2010. Per the Exchange Agreement, each exchange
rate is 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
S-7
sectors not expressly established by the 2.60 Bolivar exchange rate. The 4.30 Bolivar
exchange rate applies to the oil and gas sector.
The January 8, 2010 Exchange Agreement also established exchange rates for the
sale of foreign currency: 2.5935 Bolivars per U.S. Dollar and 4.2893 Bolivars per U.S. Dollar.
The 2.5935 Bolivars per U.S. Dollar rate applies to at least 30 percent of the currency. The
Central Bank is entitled to adjust the proportion of sales of foreign currency at each exchange
rate to attend market needs. Early in 2010, the Central Bank, in responding to needs of import
requirements of goods and services under each of the controlled exchange rates, adjusted the
percentage from 30 percent to 40 percent for the 2.5935 Bolivars per U.S. Dollar. The 40/60
percent split in sales of foreign currency between the two exchange rates creates a blended third
exchange rate of 3.61 Bolivars per U.S. Dollar. During 2010, PDVSA sold foreign currency to the
Central Bank in return for Bolivars. These foreign currency sales were for PDVSA and PDVSAs
subsidiaries. In December 2010, PDVSA invoiced Petrodelta $19.5 million
related to sales of foreign currency for Bolivars at the blended exchange rate of 3.61 Bolivars per
U.S. Dollar. The $19.5 million is calculated as the difference
between U.S. Dollar invoices remeasured at the official exchange rate
of 4.30 Bolivars per U.S. Dollar and the same invoices remeasured at
the blended exchange rate of 3.61 Bolivars per U.S. Dollar.
As an alternative to the use of the official exchange rate, an exemption under the Venezuelan
Criminal Exchange Law for transactions in certain securities resulted in an indirect securities
transaction market of foreign currency exchange, through which companies could obtain foreign
currency legally without requesting it from CADIVI. Publicly available quotes did not exist for
the securities transaction exchange rate but such rates could be obtained from brokers. Securities
transaction markets were used to move financial securities into and out of Venezuela. In May 2010,
the government of Venezuela effectively eliminated this indirect market of foreign currency
exchange and established the Sistema de Transacciones con Títulos en Moneda Extranjera (SITME)
for exchanging Bolivars. SITMEs purpose is to assist companies and individuals requiring foreign
currency (U.S. Dollars) for the import of goods and services into Venezuela. SITME may also be
used for buying or selling of Venezuelas bonds. The elimination of the indirect market for
foreign currency exchange and the establishment of SITME has not had, is not expected to have, an
impact on our business in Venezuela.
Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official
prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30
Bolivars per U.S. Dollar). However, in October 2010, Harvest Vinccler exchanged approximately $0.2
million through SITME and received an exchange rate of 5.19 Bolivars per U.S. Dollar. The monetary
assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid
expenses and other current assets. The monetary liabilities that are exposed to exchange rate
fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and
liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar
exchange rate. Petrodelta does not have, and has not had, any Bolivars pending government approval
for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. Harvest
Vinccler currently does not have any Bolivars pending government approval for settlement for U.S.
Dollars at the official exchange rate or the SITME exchange rate.
At December 31, 2009, Harvest Vinccler remeasured the appropriate monetary assets and
liabilities at the official exchange rate of 2.15 Bolivars per U.S. Dollar, Harvest Vincclers
functional and reporting currency. On January 31, 2010, Harvest Vinccler remeasured the
appropriate monetary assets and liabilities at the new official exchange rate of 4.30 Bolivars per
U.S. Dollar. During the year ended December 31, 2010, Harvest Vinccler recorded a $1.5 million
remeasurement loss on revaluation of monetary assets and liabilities. The remeasurement loss for
Harvest Vinccler was calculated as the difference between the old official exchange rate of 2.15
Bolivars per U.S. Dollar and the new official exchange rate of 4.30 Bolivars per U.S. dollar. The
primary factor in Harvest Vincclers loss on currency exchange rates is that Harvest Vinccler had
substantially higher Bolivar denominated monetary assets than Bolivar denominated monetary
liabilities. At December 31, 2010, the balances in Harvest Vincclers Bolivar denominated monetary
assets and liabilities accounts that are exposed to exchange rate changes are BsF 2.9 million and
BsF 3.2 million, respectively.
See Note 9 Investment in Equity Affiliates Petrodelta, S.A. for a discussion on the
effects of the exchange agreements on Petrodeltas business.
Revenue Recognition
We record revenue for our U.S. oil and natural gas operations when we deliver our production
to the customer and collectability is reasonably assured. Revenues from the production of oil and
natural gas on properties
S-8
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.
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.
Total long-term debt at December 31, 2010 consisted of $32 million of fixed-rate unsecured
senior convertible notes maturing in 2013 unless earlier redeemed, purchased or converted and $60
million of fixed-rate unsecured term loan facility maturing in 2012. A hypothetical 10 percent
adverse change in the floating rate would not have a material effect on our results of operations
for the year ended December 31, 2010.
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.
At December 31, 2010, note receivable plus accrued interest was approximately $3.4 million and
considered to be fully recoverable.
Other Assets
Other assets consist of investigative costs of $0.3 million associated with new business
development projects and deferred financing costs of $2.2 million. The investigative costs are
reclassified to oil and natural gas properties or expensed depending on managements assessment of
the likely outcome of the project. During the year ended
December 31, 2010, $2.9 million of costs
related to a future financing which we are no longer pursuing was expensed and $0.5 million of
investigative costs related to new business development was reclassified to exploration expense.
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.
Deferred financing costs relate to specific financing and are amortized over the life of the
financing to which the costs relate. See Note 3 Long-Term Debt.
Investment in Equity Affiliates
Investments in unconsolidated companies in which we have less than a 50 percent interest and
have significant influence are accounted for under the equity method of accounting. Investment in
Equity Affiliates is increased by additional investments and earnings and decreased by dividends
and losses. We review our Investment in Equity Affiliates for impairment whenever events and
circumstances indicate a decline in the recoverability of its carrying value.
S-9
There are many factors to consider when evaluating an equity investment for possible
impairment. Currency devaluations, inflationary economies and cash flow analysis are some of the
factors we consider in our evaluation for possible impairment. Since the Venezuelan currency
devaluations have not significantly affected Petrodeltas business and any dividends declared by
Petrodelta are required to be paid in U.S. Dollars per the conversion contract, we do not believe
an impairment of the investment of the asset is warranted at this time. At December 31, 2010 and
2009, there were no events that caused us to evaluate our investment in Petrodelta for impairment.
Property and Equipment
The major components of property and equipment at December 31 are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
Proved property costs |
|
$ |
27,355 |
|
|
$ |
1,646 |
|
Unproved property costs |
|
|
94,026 |
|
|
|
54,111 |
|
Oilfield inventories |
|
|
5,400 |
|
|
|
2,786 |
|
Other administrative property |
|
|
3,209 |
|
|
|
3,085 |
|
|
|
|
|
|
|
|
|
|
|
129,990 |
|
|
|
61,628 |
|
Accumulated depletion, impairment and depreciation |
|
|
(5,010 |
) |
|
|
(1,387 |
) |
|
|
|
|
|
|
|
|
|
$ |
124,980 |
|
|
$ |
60,241 |
|
|
|
|
|
|
|
|
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 proved reserves, as that term
is defined in Securities and Exchange Commission (SEC) regulations, have not been discovered,
capitalized costs associated with exploratory wells are charged to exploration expense. 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 our Utah operations, for the
years ended December 31, 2010 and 2009, was $3.3 million and $0.03 million ($16.71 and $6.59 per
equivalent barrel), respectively.
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 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
2010.
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
S-10
leasehold acquisition costs transferred from unproved leaseholds, are depleted using the
unit-of-production method 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, excluding oilfield inventories, consist of $3.3 million for West
Bay, $64.7 million for Antelope, $9.5 million for the Budong-Budong production sharing contract
(Budong PSC), $9.2 million for the Dussafu Marin exploration production sharing contract
(Dussafu PSC), $4.2 million for the Oman exploration and production sharing agreement (Block 64
EPSA) and $3.1 million for WAB-21.
Suspended Exploratory Drilling Costs. At December 31, 2010, oil and gas properties included
capitalized suspended exploratory drilling costs of $16.5 million. We did not have any suspended
exploratory drilling costs at December 31, 2009. The $16.5 million of suspended exploratory
drilling costs relates to drilling in the Mesaverde formation in the Bar F #1-20-3-2 (Bar F).
The Mesaverde Gas Exploration and Appraisal Project (Mesaverde) targeted the Mesaverde formation
in the Uintah Basin of Utah. Testing focused on the evaluation of the natural gas potential of the
Mesaverde tight gas reservoir over a prospective interval from 14, 000 to 17, 400 feet. While the
results to date have not definitively determined the commerciality of stand-alone development of
the Mesaverde in the current gas price environment, we believe that the test results confirm that
the Mesaverde formation exhibits sufficient quantities of hydrocarbons and reservoir over-pressure
to justify potential development, and we are actively pursuing efforts to assess whether reserves
can be attributed to this reservoir. If additional information becomes available that raises
substantial doubt as to the economic or operational viability of this project, the associated costs
will be expensed at that time.
Depreciation of other administrative property 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 $0.5 million, $0.4 million and $0.2 million for the years ended December 31, 2010, 2009 and
2008, respectively.
Capitalized Interest
We capitalize interest costs for qualifying oil and gas properties. The capitalization period
begins when expenditures are incurred on qualified properties, activities begin which are necessary
to prepare the property for production and interest costs have been incurred. The capitalization
period continues as long as these events occur. The average additions for the period are used in
the interest capitalization calculation. During the year ended December 31, 2010, we capitalized
interest costs for qualifying oil and gas property additions of $1.8 million. No interest was
capitalized for the year ended December 31, 2009.
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, 2010 and 2009, respectively, cash and cash equivalents include $51.0 million
and $26.8 million, respectively, in money market funds comprised of high quality, short-term
investments with minimal credit risk, which are reported at fair value. The fair value measurement
of these securities is based on quoted prices in active markets (level 1 input) for identical
assets. The estimated fair value of our senior convertible notes based on observable market
information (level 2 input) as of December 31, 2010 was $61.7 million. The estimated fair value of
our term loan facility based on internally developed inputs based on managements best estimate (level 3 input) for identical
liabilities as of December 31, 2010 was $60.0 million.
Our current assets and liabilities accounts include financial instruments, the most
significant of which are accounts receivables and trade payables. We believe the carrying values
of our current assets and liabilities approximate fair value, with the exception of the note
receivable. Because this note receivable is not publicly-traded
S-11
and not easily transferable, the
estimated fair value of our notes receivable is based on the market approach and time value of
money which approximates the note receivable book value of $3.4 million. The majority of inputs
used in the fair value calculation of the note receivable are Level 3 inputs and are consistent with
the information used in determining impairment of the note receivable.
Asset Retirement Liability
The accounting for asset retirement obligations standard requires entities to record the fair
value of a liability for a legal obligation to retire an asset in the period in which the liability
is incurred if a reasonable estimate of fair value can be made. No wells were abandoned during the
years ended December 31, 2010 or 2009. Changes in asset retirement obligations during the years
ended December 31, 2010 and 2009, respectively, were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Asset retirement obligations beginning of period |
|
$ |
50 |
|
|
$ |
|
|
Liabilities recorded during the period |
|
|
382 |
|
|
|
50 |
|
Liabilities settled during the period |
|
|
|
|
|
|
|
|
Revisions in estimated cash flows |
|
|
197 |
|
|
|
|
|
Accretion expense |
|
|
34 |
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations end of period |
|
$ |
663 |
|
|
$ |
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.
Noncontrolling Interests
We adopted the accounting standard for noncontrolling interests in consolidated financial
statements as of January 1, 2009. Our noncontrolling interest relates to Vincclers indirectly
owned 20 percent interest in HNR Finance (see Note 1 Organization).
Reserves
In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting. 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 guidance 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, 2010, as
follows:
|
|
|
All oil and gas reserves volumes presented as of and for the year ended December 31,
2010 and 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. |
S-12
|
|
|
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. |
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.
New Accounting Pronouncements
In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-06, which is
included in the Accounting Standards Codification (ASC) under 820, Fair Value Measurements and
Disclosures (ASC 820). This update requires the disclosure of transfers between the observable
input categories and activity in the unobservable input category for fair value measurements. The
guidance also requires disclosures about the inputs and valuation techniques used to measure fair
value and became effective for our interim and annual reporting periods beginning January 1, 2010.
The adoption of this guidance did not have an impact on our consolidated financial position,
results of operations or cash flows.
In February 2010, the FASB issued ASU No. 2010-09, which is included in the Codification under
ASC 855, Subsequent Events (ASC 855). This update removes the requirement for an SEC filer to
disclose the date through which subsequent events have been evaluated and became effective for our
interim and annual reporting periods beginning January 1, 2010. The adoption of this guidance did
not have an impact on our consolidated financial position, results of operations or cash flows.
In March 2010, the FASB issued ASU No. 2010-11, which is included in the Codification under
ASC 815, Derivatives and Hedging (ASC 815). This update clarifies the type of embedded credit
derivative that is exempt from embedded derivative bifurcation requirements. Only an embedded
credit derivative that is related to the subordination of one financial instrument to another
qualifies for the exemption. This guidance became effective for our interim and annual reporting
periods beginning January 1, 2010. The adoption of this guidance did not have a material impact on
our consolidated financial position, results of operations or cash flows.
In May 2010, the FASB issued ASU No. 2010-19, which is included in ASC under 830, Foreign
Currency (ASC 830). This update addresses the multiple foreign currency exchange rates and the
impact of highly inflationary accounting in Venezuela. Since the U.S. Dollar is the functional and
reporting currency for all of our Venezuela entities, the adoption of this update did not have an
impact on our consolidated financial position, results of operations or cash flows.
In July 2010, the FASB issued ASU 2010-20 Receivables (Topic 310): Disclosures about the
Credit Quality of Financing Receivables and the Allowance for Credit Losses (ASU 2010-20), which
amends existing guidance by requiring more robust and disaggregated disclosures by an entity about
the credit quality of its financing receivables and its allowance for credit losses. These
disclosures will provide financial statement users with additional information about the nature of
credit risks inherent in financing receivables, how credit risks are analyzed and assessed in
determining allowance for credit losses, and reasons for any changes made in allowance for credit
losses. This update is generally effective for interim and annual reporting periods ending on or
after December 15, 2010; however, certain aspects of the update pertaining to activity that occurs
during a reporting period are effective for interim and annual reporting periods beginning on or
after December 15, 2010. The adoption of ASU 2010-20 did not have a material impact on our
consolidated financial position, results of operations or cash flows.
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.
S-13
Reclassifications
Certain items in 2009 have been reclassified to conform to the 2010 financial statement
presentation.
Note 3 Long-Term Debt
Long-term debt consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Senior convertible notes, unsecured, with interest at 8.25%
See description below |
|
$ |
32,000 |
|
|
$ |
|
|
Term loan facility with interest at 10%
See description below |
|
|
60,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
92,000 |
|
|
|
|
|
Discount on term loan facility
See description below |
|
|
(10,763 |
) |
|
|
|
|
Less current portion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
81,237 |
|
|
$ |
|
|
|
|
|
|
|
|
|
On February 17, 2010, we closed an offering of $32.0 million in aggregate principal amount of
our 8.25 percent senior convertible notes. Under the terms of the notes, interest is payable
semi-annually in arrears on March 1 and September 1 of each year, beginning September 1, 2010. The
senior convertible notes will mature on March 1, 2013, unless earlier redeemed, repurchased or
converted. The notes are convertible into shares of our common stock at a conversion rate of
175.2234 shares of common stock per $1,000 principal amount of senior convertible notes, equivalent
to a conversion price of approximately $5.71 per share of common stock. The notes are general
unsecured obligations, ranking equally with all of our other unsecured senior indebtedness, if any,
and senior in right of payment to any of our subordinated indebtedness, if any. The notes are also
redeemable in certain circumstances at our option and may be repurchased by us at the purchasers
option in connection with occurrence of certain events. Financing costs of $1.9 million associated
with the senior convertible notes offering are being amortized over the remaining life of the
notes. These costs are amortized in Other Assets at December 31, 2010.
On October 29, 2010, we closed of a $60.0 million term loan facility with MSD Energy
Investments Private II, LLC (MSD Energy), an affiliate of MSD Capital, L.P., as the sole lender
under the term loan facility. Under the terms of the term loan facility, interest is paid on a
monthly basis at the initial rate of 10 percent and will mature on October 28, 2012. The initial
rate of interest increases to 15 percent on July 28, 2011, the Bridge Date. The Bridge Date may be
extended at our option for three months by paying a fee to MSD Energy in the amount of five percent
of the initial principal amount of the term loan facility. Financing costs of $0.3 million
associated with the term loan facility offering are being amortized over the remaining life of the
loan. These costs are amortized in Other Assets at December 31, 2010.
In connection with the term loan facility, we issued to MSD Energy (1) 1.2 million warrants
exercisable at any time on or after the closing date for a period of five years from the closing
date on a cashless exercise basis at $15 per share until the Bridge Date, at which time the
exercise price per share will equal the lower of $15 or 120 percent of the average closing bid
price of Harvests common stock for the 20 trading days immediately preceding the Bridge Date
(Tranche A); (2) 0.4 million warrants exercisable at any time on or after the closing date for a
period of five years from the closing date on a cashless exercise basis at $20 per share until the
Bridge Date, at which time the exercise price per share will equal the lower of $15 or 120 percent
of the average closing bid price of Harvests common stock for the 20 trading days immediately
preceding the Bridge Date (Tranche B); and (3) 4.4 million warrants exercisable at any time on or
after the Bridge Date for a period of five years from the Bridge Date on a cashless exercise basis
at the lower of $15 per share or 120 percent of the average closing price of Harvests common stock
for the 20 trading days immediately preceding the Bridge Date (Tranche C). The 4.4 million
warrants may be redeemed by Harvest for $0.01 per share at any time prior to the Bridge Date in
conjunction with the repayment of the loan prior to the Bridge Date.
The Black-Scholes option pricing model was used in pricing Tranche A and Tranche B. Tranche A
was priced at $5.46 per warrant, and Trance B was priced at $4.60 per warrant. The Monte Carlo
option pricing model
S-14
was used in pricing Trance C due the pricing and vesting variables in the
agreement. Tranche C was priced at $0.62 per warrant. The value of the warrants, $11.1 million,
is recorded as Discount on Debt with a corresponding credit to additional paid in capital on our
consolidated balance sheet at December 31, 2010. The Discount on Debt is being amortized over the
life of the warrants.
The principal payment requirements for our long-term debt outstanding at December 31, 2010 are
as follows (in thousands):
|
|
|
|
|
2011 |
|
$ |
|
|
2012 |
|
|
60,000 |
|
2013 |
|
|
32,000 |
|
|
|
|
|
|
|
$ |
92,000 |
|
|
|
|
|
Note 4 Liquidity
Our liquidity outlook has changed since December 31, 2009 primarily as a result of
funding requirements of our exploration projects and development of our oil and gas properties.
The oil and gas industry is a highly capital intensive and cyclical business with unique operating
and financial risks. In Item 1A Risk Factors, we discuss a number of variables and risks
related to our exploration projects and our minority equity investment in Petrodelta that could
significantly utilize our cash balances, affect our capital resources and liquidity. We also point
out that the total capital required to develop the fields in Venezuela may exceed Petrodeltas
available cash and financing capabilities, and that there may be operational or contractual
consequences due to this inability.
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. We require capital principally
to fund the exploration and development of new oil and gas properties. For calendar year 2011, we
have established a preliminary exploration and drilling budget of approximately $46.5 million. We
are concentrating a substantial portion of this budget on the development of our Antelope project,
the Budong PSC and the Dussafu PSC. As is common in the oil and gas industry, we have various
contractual commitments pertaining to exploration, development and production activities.
Currently, we have a work commitment of $22.0 million which is a minimum amount to be spent on the
Block 64 EPSA for the drilling of two wells over a three-year period which expires in May 2012.
We currently plan
to fund this commitment in 2012, and we may be required to raise
capital to do so. We
also have minimum work commitments during the various phases of the exploration periods in the
Budong PSC and Dussafu PSC.
As a petroleum exploration and production company, our revenue, profitability, cash flows, and
future rate of growth are substantially dependent on the condition of the oil and gas industry
generally, our success with our exploration program, and the belief that Petrodelta will fund its
own operations and continue to pay dividends. Because our revenues are generated from customers
with the same economic interests, our operations are also susceptible to market volatility
resulting from economic, cyclical, weather or other factors related to the energy industry.
Changes in the level of operating and capital spending in the industry, decreases in oil or gas
prices, or industry perceptions about future oil and gas prices could adversely affecting our
financial position, results of operations and cash flows. Based on
our current level of cash flow from operations, we will be required
to raise capital to meet our general and administrative costs and
fund our oil and gas programs.
Revenues from the Monument Butte Extension and Lower Green River/Upper Wasatch projects have
increased significantly during 2010; however, our primary source of cash still remains to be
dividends from Petrodelta and funding from debt financing. In November 2010, Petrodeltas board of
directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net
to our 32 percent interest). The dividend represents the remaining 50 percent of the cash
withdrawal rights as shareholders on Petrodeltas net income as reported under IFRS for the year
ended December 31, 2009. This dividend is subject to shareholder approval, and will not be paid by
Petrodelta until Petrodelta shareholder approval is received.
Shareholder approval was received on March 14, 2011. We expect to receive future
dividends from Petrodelta; however, we expect that in the near term Petrodelta will reinvest most
of its earnings into the company in support of its drilling and
appraisal activities. Therefore,
there is uncertainty that Petrodelta will pay additional dividends in 2011 or 2012.
Additionally, any dividend received from Petrodelta carries a liability to our non-controlling
interest holder, Vinccler, for its 20 percent share. Dividends declared and paid by Petrodelta are
paid to HNR Finance, our consolidated subsidiary. HNR Finance must declare a dividend in order for
us and our non-controlling interest holder, Vinccler, to receive our respective shares of
Petrodeltas dividends. A dividend from HNR Finance is due upon demand. Currently, Vinccler has
not demanded its respective share of the two most recent Petrodelta dividends and has waived such a
demand until at least April 2012. As of December 31, 2010, Vincclers share of the undistributed
dividends is $9.0 million inclusive of the unpaid November 2010
dividend. See Item 15 Exhibits and Financial Statement Schedules, Notes to
Consolidated Financial Statements, Note 16 Related Party Transactions.
We have incurred significant debt during 2010 which has imposed restrictions on us and
increased our vulnerability to adverse economic and industry conditions. Our monthly and
semi-annual interest expense has increased significantly, and our senior convertible notes and term
loan facility impose new restrictions on us. Our senior convertible notes and term loan facility
impose covenant restrictions on us that limit our ability to obtain additional financing. Our
ability to meet these covenants is primarily dependent on meeting customary affirmative covenant
clauses, including providing consolidated statements to be audited and accompanied by a report and
opinion of an independent certified public accountant, which report and opinion shall not be
subject to any going concern or like qualification. Our inability to satisfy the covenants contained in our long
term debt arrangements would constitute an event of default, if not waived. An uncured default
could result in our outstanding debt becoming immediately due and payable. If this were to occur,
we may not be able to obtain waivers or secure alternative financing to satisfy our obligations,
either of which would have a material adverse impact on our business. As of December 31, 2010, we
were in compliance with all of our long term debt covenants.
At December 31, 2010, we had cash on hand
of $58.7 million. We believe that this cash plus cash generated from Petrodelta dividends and funding from debt financing combined
with our ability to vary the timing of our capital expenditures is sufficient to fund our operations and capital commitments through
at least December 31, 2011. However, if the Petrodelta dividend payment is not received as expected or our cash sources and
requirements are different than expected, it could have a material adverse effect on our operations.
In order to increase our liquidity to levels sufficient to meet our commitments, we are
currently pursuing a number of actions including possible delay of discretionary capital spending
to future periods, possible farm-out or sale of assets, or other monetization of asset as necessary
to maintain the liquidity required to run our operations. We continue to pursue, as appropriate,
additional actions designed to generate liquidity including seeking of financing sources, accessing
equity and debt markets, increasing production in our producing assets, and cost reductions.
Although we believe that we will have adequate liquidity to meet our future operating requirements
and to remain compliant with the covenants under our long term debt arrangements, the factors
described above create uncertainty. Our lack of cash flow and the unpredictability of cash
dividends from Petrodelta could make it difficult to obtain financing, and accordingly, there is no
assurance adequate financing can be raised. Accordingly, there can be no assurances that any of
these possible efforts will be successful or adequate, and if they are not, our financial condition
and liquidity could be materially adversely affected.
S-15
Note 5 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, 2011.
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 August 2010, we
relinquished a portion of our office space in Houston, Texas, for an approximate $1,600 per month
reduction of cost. In December 2010, Harvest Vinccler extended its lease for office space in
Caracas, Venezuela for one year for approximately $7,000 per month. In October 2010, we signed a
two-year lease in Roosevelt, Utah for approximately $6,000 per month. In October 2010, we signed a
two-year lease for office space in Singapore for approximately $7,000 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 September 2010, we signed a five-year lease for office space in London for approximately
$9,000 per month. At December 31, 2010, we had $0.7 million of commitments related to a drilling
rig and other equipment for our domestic operations. The commitment for the drilling rig of $0.6
million was met in January 2011. We also have minimum work funding commitments during the various
phases of the exploration periods in the Budong-Budong Production Sharing Contract (Budong PSC),
Dussafu Marin Permit offshore Gabon in West Africa (Dussafu PSC) and Al Ghubar / Qarn Alam
license (Block 64 EPSA).
In April 2009, we signed an Exploration and Production Sharing Agreement (EPSA) with Oman
for the Block 64 EPSA. We have an obligation to drill two wells over a three-year period with a
funding commitment of $22.0 million.
Robert C. Bonnet and Bobby Bonnet Land Services vs. Harvest (US) Holdings, Inc., Branta
Exploration & Production, LLC, Ute Energy LLC, Cameron Cuch, Paula Black, Johnna Blackhair, and
Elton Blackhair in the United States District Court for the District of Utah. This suit was
served in April 2010 on Harvest and Elton Blackhair, a Harvest employee, alleging that the
defendants, among other things, intentionally interfered with Plaintiffs employment agreement with
the Ute Indian Tribe Energy & Minerals Department and intentionally interfered with Plaintiffs
prospective economic relationships. Plaintiffs seek actual damages, punitive damages, costs and
attorneys fees. We dispute Plaintiffs claims and plan to vigorously defend against them. We are
unable to estimate the amount or range of any possible loss.
Uracoa Municipality Tax Assessments. Our Venezuelan subsidiary, Harvest Vinccler, has
received nine assessments from a tax inspector for the Uracoa municipality in which part of the
Uracoa, Tucupita and Bombal fields are located as follows:
|
|
|
Three claims were filed in July 2004 and allege a failure to withhold for technical
service payments and a failure to pay taxes on the capital fee reimbursement and
related interest paid by 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. |
S-16
|
|
|
Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate
set by the municipality. Harvest Vinccler has filed a protest with the Tax Court in
Barcelona, Venezuela, on these claims. |
|
|
|
|
Two claims were filed in August 2006 alleging a failure to pay taxes on estimated
revenues for the second quarter of 2006 and a withholding error with respect to certain
vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona,
Venezuela, on one claim and filed a protest with the municipality on the other claim. |
|
|
|
|
Two claims were filed in March 2007 alleging a failure to pay taxes on estimated
revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a
protest with the municipality on these claims. |
Harvest Vinccler disputes the Uracoa tax assessments and believes it has a substantial basis for
its positions. Harvest Vinccler is unable to estimate the amount or range of any possible loss.
As a result of the SENIATs, the Venezuelan income tax authority, interpretation of the tax code as
it applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in
Caracas against the Uracoa Municipality for the refund of all municipal taxes paid since 1997.
Libertador Municipality Tax Assessments. Harvest Vinccler has received five
assessments from a tax inspector for the Libertador municipality in which part of the Uracoa,
Tucupita and Bombal fields are located as follows:
|
|
|
One claim was filed in April 2005 alleging the failure to pay taxes at a new rate
set by the municipality. Harvest Vinccler has filed a protest with the Mayors Office
and a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the
claim. On April 10, 2008, the Tax Court suspended the case pending a response from the
Mayors Office to the protest. If the municipalitys response is to confirm the
assessment, Harvest Vinccler will defer to the competent Tax Court to enjoin and
dismiss the claim. |
|
|
|
|
Two claims were filed in June 2007. One claim relates to the period 2003 through
2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second
claim alleges a failure to pay taxes on estimated revenues for the third and fourth
quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona,
Venezuela, to enjoin and dismiss both claims. |
|
|
|
|
Two claims were filed in July 2007 seeking to impose penalties on tax assessments
filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in
Barcelona, Venezuela, to enjoin and dismiss both claims. |
Harvest Vinccler disputes the Libertador allegations set forth in the assessments and believes it
has a substantial basis for its position. Harvest Vinccler is unable to estimate the amount or
range of any possible loss. As a result of the SENIATs interpretation of the tax code as it
applies to operating service agreements, Harvest Vinccler has filed claims in the Tax Court in
Caracas against the Libertador Municipality for the refund of all municipal taxes paid since 2002.
We are a defendant in or otherwise involved in other litigation incidental to our business.
In the opinion of management, there is no such litigation which will have a material adverse impact
on our financial condition, results of operations and cash flows.
Note 6 Taxes
Taxes Other Than on Income
The components of taxes other than on income were (in thousands):
S-17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Franchise taxes |
|
$ |
196 |
|
|
$ |
182 |
|
|
$ |
(951 |
) |
Payroll and other taxes |
|
|
852 |
|
|
|
833 |
|
|
|
745 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,048 |
|
|
$ |
1,026 |
|
|
$ |
(206 |
) |
|
|
|
|
|
|
|
|
|
|
During the year ended December 31, 2008, we reversed a $1.1 million franchise tax provision
that was no longer required.
Taxes on Income
The tax effects of significant items comprising our net deferred income taxes as of December
31, 2010, are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Operating loss carryforwards |
|
$ |
26,849 |
|
|
$ |
15,599 |
|
Alternative minimum tax credit |
|
|
1,222 |
|
|
|
|
|
Stock options |
|
|
1,330 |
|
|
|
1,426 |
|
Return to accrual adjustment |
|
|
4,720 |
|
|
|
|
|
Restricted stock |
|
|
256 |
|
|
|
|
|
Delay rentals |
|
|
176 |
|
|
|
|
|
Valuation allowance |
|
|
(28,343 |
) |
|
|
(17,025 |
) |
|
|
|
|
|
|
|
Net deferred tax asset |
|
|
6,210 |
|
|
|
|
|
Deferred tax liability: |
|
|
|
|
|
|
|
|
Geological and geophysical/seismic |
|
|
(505 |
) |
|
|
|
|
Intangible drilling costs |
|
|
(5,705 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax asset (liability) |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
The valuation
allowance increased by $11.3 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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Income (loss) before income taxes
United States |
|
$ |
(24,743 |
) |
|
$ |
(22,357 |
) |
|
$ |
(34,760 |
) |
Foreign |
|
|
(13,620 |
) |
|
|
(7,522 |
) |
|
|
(14,326 |
) |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(38,363 |
) |
|
$ |
(29,879 |
) |
|
$ |
(49,086 |
) |
|
|
|
|
|
|
|
|
|
|
The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
(1,210 |
) |
|
$ |
39 |
|
|
$ |
(128 |
) |
Foreign |
|
|
1,042 |
|
|
|
1,143 |
|
|
|
153 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(167 |
) |
|
|
1,182 |
|
|
|
25 |
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
Foreign |
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(184 |
) |
|
$ |
1,182 |
|
|
$ |
25 |
|
|
|
|
|
|
|
|
|
|
|
A comparison of the income tax expense (benefit) at the federal statutory rate to our
provision for income taxes is as follows (in thousands):
S-18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Computed tax expense (benefit) at the statutory rate |
|
$ |
(13,427 |
) |
|
$ |
(10,458 |
) |
|
$ |
(17,180 |
) |
Effect of foreign source income and rate differentials on
foreign income |
|
|
6,000 |
|
|
|
3,775 |
|
|
|
5,167 |
|
Change in valuation allowance |
|
|
11,111 |
|
|
|
9,184 |
|
|
|
6,059 |
|
Tax on undistributed earnings |
|
|
|
|
|
|
|
|
|
|
5,446 |
|
Deemed income inclusion under Subpart F |
|
|
|
|
|
|
|
|
|
|
968 |
|
Permanent differences |
|
|
2,062 |
|
|
|
|
|
|
|
|
|
Foreign disregarded entities |
|
|
|
|
|
|
21 |
|
|
|
(268 |
) |
Return to accrual adjustment |
|
|
(4,720 |
) |
|
|
(1,093 |
) |
|
|
(166 |
) |
Income tax refund |
|
|
(1,210 |
) |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
(247 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
$ |
(184 |
) |
|
$ |
1,182 |
|
|
$ |
25 |
|
|
|
|
|
|
|
|
|
|
|
Rate differentials for foreign income result from tax rates different from the U.S. tax rate
being applied in foreign jurisdictions.
Out-of-Period Adjustment During the fourth quarter of 2010, we recorded an out-of-period
adjustment in our consolidated financial statements for the year ended December 31, 2010. This
adjustment related to the accounting for an income tax refund of $1.0 million that had not been
accrued at September 30, 2010. The refund was applied for on September 15, 2010 and received on
October 25, 2010. We recorded the $1.0 million as an income tax benefit in the fourth quarter of
2010; however, the $1.0 million income tax refund should have been recognized as an income tax
benefit in the third quarter of 2010. As a result, Accounts and notes receivable joint
interest and other was understated and net income attributable to Harvest was understated by $1.0
million for the third quarter of 2010, or $(0.03) per diluted share, and net income attributable to Harvest was overstated by
$1.0 million for the fourth quarter of 2010, or $0.03 per diluted share. Net income attributable to Harvest is correctly
stated for the year ended December 31, 2010. The error has no impact to the consolidated
statements of cash flows. Management concluded the impact of the error is immaterial to the
financial statements in the period in which it occurred as well as the period in which it was
corrected.
At December 31, 2010, we had, for federal income tax purposes, operating loss carryforwards of
approximately $90.6 million, expiring in the years 2026 through 2030.
Accounting for Uncertainty in Income Taxes
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
2007. To date, the Internal Revenue Service (IRS) has not performed an examination of our U.S.
income tax returns for 2007 through 2009.
We do not have any unrecognized tax benefits or loss contingencies.
Note 7 Stock Option and Stock Purchase Plans
In May 2010, our shareholders approved the 2010 Long Term Incentive Plan (the 2010 Plan).
The 2010 Plan provides for the issuance of up to 1,700,000 shares of our common stock in
satisfaction of exercised stock options, stock appreciation rights (SARs), restricted stock,
restricted stock units (RSUs) and other stock-based awards to eligible participants including
employees, non-employee directors and consultants of our Company or subsidiaries. Under the 2010
Plan, no more than 500,000 shares may be granted as restricted stock. No individual may be granted
more than 1,000,000 options or SARs. The exercise price of stock options granted under the 2010
Plan must be no less than the fair market value of our common stock on the date of grant. All
options granted to date will vest in the manner and subject to the conditions specified in the
award agreement and expire five years from grant date. Restricted stock granted vest in the manner
and subject to the conditions specified in the award agreement. The 2010 Plan also permits the
granting of performance awards and other cash-based awards to eligible employees and consultants.
Performance awards may be in the form of performance stock, performance units and other form of
award established by the Board of Directors Human Resource Committee (the Committee) with
vesting based on the accomplishment of a performance goal. No individual may be awarded
performance related cash awards 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, the Committee shall act to effect one or
more of the following alternatives, which may vary among individual holders of awards granted under
the 2010 Plan and which may vary among awards held by any individual holder of an award granted
under the 2010 Plan: (1) accelerate vesting; (2) require mandatory surrender; (3) assume
outstanding awards or have a new award of a similar nature substituted; (4) adjust the number and
class of common stock covered by an award; and/or (5) make adjustments deemed appropriate to
reflect the change of control.
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
S-19
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 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.
A summary of the status of our stock option plans as of December 31, 2010, 2009 and 2008 and
changes during the years ending on those dates is presented below (shares in thousands):
S-20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
Average |
|
|
Remaining |
|
|
Aggregate |
|
|
Average |
|
|
Remaining |
|
|
Aggregate |
|
|
Average |
|
|
Remaining |
|
|
Aggregate |
|
|
|
Exercise |
|
|
Contractual |
|
|
Intrinsic |
|
|
Exercise |
|
|
Contractual |
|
|
Intrinsic |
|
|
Exercise |
|
|
Contractual |
|
|
Intrinsic |
|
|
|
Shares |
|
|
Price |
|
|
Life |
|
|
Value |
|
|
Shares |
|
|
Price |
|
|
Life |
|
|
Value |
|
|
Shares |
|
|
Price |
|
|
Life |
|
|
Value |
|
Outstanding at
beginning of
the year: |
|
|
3,363 |
|
|
$ |
9.35 |
|
|
|
|
|
|
|
|
|
|
|
3,783 |
|
|
$ |
8.54 |
|
|
|
|
|
|
|
|
|
|
|
4,172 |
|
|
$ |
7.80 |
|
|
|
|
|
|
|
|
|
Options granted |
|
|
467 |
|
|
|
7.10 |
|
|
|
|
|
|
|
|
|
|
|
118 |
|
|
|
4.60 |
|
|
|
|
|
|
|
|
|
|
|
444 |
|
|
|
10.28 |
|
|
|
|
|
|
|
|
|
Options exercised |
|
|
(419 |
) |
|
|
(4.01 |
) |
|
|
|
|
|
|
|
|
|
|
(205 |
) |
|
|
(2.11 |
) |
|
|
|
|
|
|
|
|
|
|
(548 |
) |
|
|
(2.86 |
) |
|
|
|
|
|
|
|
|
Options cancelled |
|
|
(185 |
) |
|
|
(9.62 |
) |
|
|
|
|
|
|
|
|
|
|
(333 |
) |
|
|
(2.95 |
) |
|
|
|
|
|
|
|
|
|
|
(285 |
) |
|
|
(11.34 |
) |
|
|
|
|
|
|
|
|
Outstanding at
end of the year |
|
|
3,226 |
|
|
|
9.70 |
|
|
|
3.7 |
|
|
|
8,522 |
|
|
|
3,363 |
|
|
|
9.35 |
|
|
|
4.2 |
|
|
|
1,312 |
|
|
|
3,783 |
|
|
|
8.54 |
|
|
|
5.3 |
|
|
|
1,846 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at
end of the year |
|
|
1,784 |
|
|
|
10.27 |
|
|
|
3.8 |
|
|
|
3,954 |
|
|
|
2,066 |
|
|
|
9.09 |
|
|
|
0.8 |
|
|
|
1,230 |
|
|
|
2,147 |
|
|
|
7.23 |
|
|
|
1.4 |
|
|
|
1,846 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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: |
|
2010 |
|
|
2009 |
|
|
2008 |
|
Weighted average fair value |
|
$ |
4.23 |
|
|
$ |
4.60 |
|
|
$ |
5.85 |
|
Weighted averaged expected life |
|
|
7 |
|
|
|
7 |
|
|
|
7 |
|
Valuation assumptions: |
|
|
|
|
|
|
|
|
|
|
|
|
Expected volatility |
|
|
57.6 |
% |
|
|
68.9 |
% |
|
|
46.6-49.7 |
% |
Risk-free interest rate |
|
|
2.7 |
% |
|
|
3.5 |
% |
|
|
3.0-3.9 |
% |
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, 2010, and changes during the year ended
December 31, 2010, is presented below (shares in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Weighted-Average |
|
|
|
|
|
|
Weighted-Average |
|
|
|
|
|
|
Weighted-Average |
|
|
|
Nonvested |
|
|
Grant-Date |
|
|
Nonvested |
|
|
Grant-Date |
|
|
Nonvested |
|
|
Grant-Date |
|
|
|
Options |
|
|
Fair Value |
|
|
Options |
|
|
Fair Value |
|
|
Options |
|
|
Fair Value |
|
Nonvested at beginning of the year |
|
|
1,297 |
|
|
$ |
5.50 |
|
|
|
1,636 |
|
|
$ |
5.74 |
|
|
|
1,800 |
|
|
$ |
5.84 |
|
Granted |
|
|
467 |
|
|
|
4.23 |
|
|
|
118 |
|
|
|
3.13 |
|
|
|
444 |
|
|
|
5.63 |
|
Vested |
|
|
(322 |
) |
|
|
(5.09 |
) |
|
|
(447 |
) |
|
|
(5.75 |
) |
|
|
(607 |
) |
|
|
(5.88 |
) |
Forfeited |
|
|
|
|
|
|
|
|
|
|
(10 |
) |
|
|
(6.54 |
) |
|
|
(1 |
) |
|
|
(5.62 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at end of the year |
|
|
1,442 |
|
|
|
5.18 |
|
|
|
1,297 |
|
|
|
5.50 |
|
|
|
1,636 |
|
|
|
5.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2010, there was $2.8 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, 2010, 2009 and 2008 was $2.6 million, $2.6 million and $4.0
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, 2010, a total of 0.4 million options issued outside of the plans were outstanding
and 0.3 million options were exercisable.
S-21
Stock options of 0.4 million were exercised in the year ended December 31, 2010 resulting in
cash proceeds of $1.7 million. Stock options of 0.2 million were exercised in the year ended
December 31, 2009 resulting in cash proceeds of $0.4 million.
Note 8 Operating Segments
We regularly allocate resources to and assess the performance of our operations by segments
that are organized by unique geographic and operating characteristics. The segments are organized
in order to manage regional business, currency and tax related risks and opportunities. Operations
included under the heading United States and Other include U.S. operations, corporate management,
cash management, business development and financing activities performed in the United States and
other countries which do not meet the requirements for separate disclosure. All intersegment
revenues, other income and equity earnings, expenses and receivables are eliminated in order to
reconcile to consolidated totals. Corporate general and administrative and interest expenses are
included in the United States and Other segment and are not allocated to other operating segments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in thousands) |
|
Segment Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales: |
|
|
|
|
|
|
|
|
|
|
|
|
United States and other |
|
$ |
10,696 |
|
|
$ |
181 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales |
|
|
10,696 |
|
|
|
181 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Income (Loss) Attributable to Harvest |
|
|
|
|
|
|
|
|
|
|
|
|
Venezuela |
|
|
62,050 |
|
|
|
39,696 |
|
|
|
33,020 |
|
Indonesia |
|
|
(7,108 |
) |
|
|
(5,124 |
) |
|
|
(8,966 |
) |
United States and other |
|
|
(39,602 |
) |
|
|
(37,679 |
) |
|
|
(45,518 |
) |
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Harvest |
|
$ |
15,340 |
|
|
$ |
(3,107 |
) |
|
$ |
(21,464 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(in thousands) |
|
Operating Segment Assets |
|
|
|
|
|
|
|
|
Venezuela |
|
$ |
292,023 |
|
|
$ |
249,484 |
|
Indonesia |
|
|
16,254 |
|
|
|
5,893 |
|
United States and other |
|
|
229,518 |
|
|
|
132,913 |
|
|
|
|
|
|
|
|
|
|
|
537,795 |
|
|
|
388,290 |
|
Intersegment eliminations |
|
|
(49,551 |
) |
|
|
(39,511 |
) |
|
|
|
|
|
|
|
|
|
$ |
488,244 |
|
|
$ |
348,779 |
|
|
|
|
|
|
|
|
Note 9 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.
The sale of oil and gas by Petrodelta to the Venezuelan government is pursuant to a Contract
for Sale and Purchase of Hydrocarbons with PDVSA Petroleo S.A. (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.
Merey 16 published prices are quoted and sold in U.S. Dollars. Natural gas delivered from the
Petrodelta Fields to PPSA is priced at $1.54 per thousand cubic feet. Natural gas deliveries are
paid in Bolivars, but the pricing for natural gas is referenced to the U.S. Dollar. 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
S-22
delivered, in
immediately available funds to the bank accounts designated by Petrodelta. Major contracts for
capital expenditures and lease operating expenditures are denominated in U.S. Dollars. Any
dividend paid by Petrodelta will be made in U.S. Dollars.
On February 4, 2010, Petrodeltas board of directors endorsed a capital budget of $205 million
for Petrodeltas 2010 business plan. The budget included 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.
Petrodelta contracted a workover rig which was mobilized on October 15, 2010. Due to delays in rig
availability, El Salto facilities project execution and lack of funding by PDVSA, Petrodelta only
spent $101.8 million of its 2010 budget.
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.
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 expected PDVSA to continue
requesting and receiving waivers, Petrodelta did not accrue a liability to LOCTI for the year ended
December 31, 2009. For filing years 2007 and 2008, PDVSA provided Petrodelta with a copy of the
waiver acceptance letter from LOCTI. PDVSA has stated that a waiver was granted for filing year
2009; however, LOCTI has not yet issued the acceptance letter to PDVSA for the 2009 filing year.
The potential exposure to LOCTI for the year ended December 31, 2009 after devaluation is $4.8
million, $2.4 million net of tax ($0.8 million net to our 32 percent interest). In January 2011,
PDVSA informed its consolidating entities, including Petrodelta, that effective with the 2010
reporting year it would no longer be requesting waivers to file the LOCTI declaration on a
consolidated basis. Based on this information, Petrodelta accrued the 2010 liability to LOCTI in
the amount of $4.6 million, $2.3 million net of tax
($0.7 million net to our 32 percent interest).
In December 2010, LOCTI was modified to reduce the amount of contributions beginning January 2011
to one percent of gross revenues for companies owned by individuals or corporations and 0.5 percent
for companies owned by Venezuela. Petrodeltas rate of contribution starting in 2011 will be 0.5
percent.
In 2008, the Venezuelan government published in the Official Gazette the Law of Special
Contribution to Extraordinary Prices at the Hydrocarbons International Market (Windfall Profits
Tax). The Windfall Profits Tax is 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). As
instructed by CVP, Petrodelta has applied the Windfall Profits Tax to gross oil production
delivered to PDVSA. The Windfall Profits Tax established a special 50 percent tax to the
Venezuelan government when the average price of the VEB exceeds $70 per barrel. In a similar
manner, the percentage is increased from 50 percent to 60 percent when the average price of the VEB
exceeds $100 per barrel. The Windfall Profits Tax is reported as expense on the income statement
and is deductible for Venezuelan tax purposes. Petrodelta recorded $14.1 million, $0.9 million and
$56.4 million of expense for the Windfall Profits Tax for the years ended December 31, 2010, 2009
and 2008, respectively.
In 2009, under instructions issued by CVP, Petrodelta set up a reserve within the equity
section of the balance sheet for deferred tax assets. 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
S-23
assets. Dividends received prior to 2009
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.
During the first quarter of 2009, PDVSA completed an actuarial study for their pension and
retirement plan. This pension and retirement plan covers all PDVSA employees and mixed companies.
In May 2009, upon completion of the review of this actuarial study, PDVSA sent a statement to
Petrodelta for its respective costs associated with the pension and retirement plan. The pension
adjustment was for past service costs covering the period from January 2008, when the Harvest
Vinccler employees were migrated to PDVSA payroll, through May 2009. It is a non-recurring
adjustment. Pension costs at December 31, 2009 reasonably reflected Petrodeltas employee
demographic and plan conditions. Petrodelta is not required to reimburse the pension costs to
PDVSA until PDVSA pays the pension benefits to employees. Petrodelta recorded additional pension
expense of $15.6 million ($5.0 million net to our 32 percent interest) in the three month period
ended June 30, 2009 based on the statement received. During the fourth quarter of 2009, PDVSA
reassessed the assumptions used in the 2009 actuarial study. This reassessment resulted in a
downward revision of $8.4 million ($2.7 million net to our 32 percent interest) of the pension and
retirement plan costs charged to Petrodelta in May 2009. The downward revision of the pension and
retirement plan costs was recorded in December 2009. The 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 the assumptions, the terms of the
relevant plans and allocation methodology as determined by PDVSA.
On January 8, 2010, the Venezuelan government published in the Official Gazette the Exchange
Agreement, which established new exchange rates for the Venezuela Bolivar/U.S. Dollar currencies
that went into effect on January 11, 2010. Per the Exchange Agreement, each exchange rate is
applied to foreign currency sales and purchases conducted through 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 4.30 Bolivar exchange rate applies to the oil and gas sector. During 2010, PDVSA sold
foreign currency to the Central Bank in return for Bolivars. These foreign currency sales were for
PDVSA and PDVSAs subsidiaries. In December 2010, PDVSA invoiced Petrodelta $19.5 million
related to sales of foreign currency for Bolivars at the blended exchange rate of
3.61 Bolivars per U.S. Dollar. The $19.5 million is calculated as the
difference between U.S. Dollar invoices remeasured at the official
exchange rate of 4.30 Bolivars per U.S. Dollar and the same invoices
remeasured at the blended exchange rate of 3.61 Bolivars per U.S.
Dollar. On January 4, 2011, the Venezuelan government published in the
Official Gazette the Exchange Agreement which eliminated the 2.60 Bolivars per U.S. Dollar exchange
rate with an effective date of January 1, 2011. The January 2011 Exchange Agreement eliminated the
average exchange rate available under the January 2010 Exchange Agreement to oil and gas producers
for exchanging dollars through CADIVI. See Note 2 Summary of Significant Accounting Policies
Reporting and Functional Currency for a description of the changes due to the Exchange Agreement.
At December 31, 2009, Petrodelta remeasured the appropriate monetary assets and liabilities at
the official exchange rate of 2.15 Bolivars per U.S. Dollar, Petrodeltas functional and reporting
currency. During the year ended December 31, 2010, Petrodelta remeasured the appropriate monetary
assets and liabilities at the new official exchange rate of 4.30 Bolivars per U.S. Dollar and
recorded an $84.4 million remeasurement gain on revaluation of monetary assets and liabilities. The
revaluation of Bolivars to U.S. Dollars was calculated as the difference between the old official
exchange rate of 2.15 Bolivars per U.S. Dollar and the new official exchange rate of 4.30 Bolivars
per U.S. dollar. The primary factor in Petrodeltas gain on currency exchange rates is that
Petrodelta had substantially higher Bolivar denominated monetary liabilities than Bolivar
denominated monetary assets. At December 31, 2010, the balances in Petrodeltas Bolivar
denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are
BsF 87.0 million and BsF 1,423.0 million, respectively.
In June 2010,
Petrodeltas board of directors approved the offsetting of accounts payable to PDVSA and its affiliates, including CVP, for 2010
royalties, taxes and operation expenditures against the receivable from PDVSA and its affiliates, including CVP, for 2010 oil
and gas deliveries at the exchange rate prevailing as of that date. During February 2011, per instructions received from CVP, Petrodelta proceeded to offset accounts receivable
and payables between PDVSA and its affiliates, including CVP, outstanding as of December 31, 2009 at the exchange rate prevailing
as of that date. The revised revaluation reduced Petrodeltas remeasurement gain $36.1 million from $120.5 million in January 2010
to $84.4 million in December 2010.
S-24
In August 2010, Petrodeltas board of directors declared a dividend of $30.5 million, $12.2
million net to HNR Finance ($9.8 million net to our 32 percent interest), which was received
October 22, 2010. The dividend represents 50 percent of the cash withdrawal rights as shareholders
on Petrodeltas net income as reported under International Financial Reporting Standards (IFRS)
for the year ended December 31, 2009.
In November 2010, Petrodeltas board of directors declared a dividend of $30.6 million, $12.2
million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend represents
the remaining 50 percent of the cash withdrawal rights as shareholders on Petrodeltas net income
as reported under IFRS for the year ended December 31, 2009. This dividend is subject to
shareholder approval, and will not be accrued on our consolidated balance sheet until Petrodelta
shareholder approval is received. Shareholder approval was received
on March 14, 2011.
Petrodeltas reporting and functional currency is the U.S. Dollar. HNR Finance owns a 40
percent interest in Petrodelta. Petrodeltas financial information is prepared in accordance with
IFRS which we have adjusted to conform to GAAP. All amounts through Net Income Equity Affiliate
represent 100 percent of Petrodelta. Summary financial information has been presented below at
December 31, 2010, 2009 and 2008, and for the years ended December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
604,173 |
|
|
$ |
451,473 |
|
|
$ |
458,113 |
|
Gas sales |
|
|
3,398 |
|
|
|
6,778 |
|
|
|
16,506 |
|
Royalty |
|
|
(204,688 |
) |
|
|
(156,799 |
) |
|
|
(168,790 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
402,883 |
|
|
|
301,452 |
|
|
|
305,829 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
44,749 |
|
|
|
48,311 |
|
|
|
52,946 |
|
Workovers |
|
|
8,910 |
|
|
|
|
|
|
|
24,663 |
|
Depletion, depreciation and amortization |
|
|
40,429 |
|
|
|
33,666 |
|
|
|
25,509 |
|
General and administrative |
|
|
15,508 |
|
|
|
9,750 |
|
|
|
5,974 |
|
Windfall profits tax |
|
|
14,116 |
|
|
|
882 |
|
|
|
56,377 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
123,712 |
|
|
|
92,609 |
|
|
|
165,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Operations |
|
|
279,171 |
|
|
|
208,843 |
|
|
|
140,360 |
|
Gain of exchange rate |
|
|
84,448 |
|
|
|
|
|
|
|
|
|
Investment earnings and other |
|
|
3,179 |
|
|
|
4 |
|
|
|
|
|
Interest expense |
|
|
(26,767 |
) |
|
|
(3,617 |
) |
|
|
(2,329 |
) |
|
|
|
|
|
|
|
|
|
|
Income before Income Tax |
|
|
340,031 |
|
|
|
205,230 |
|
|
|
138,031 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current income tax expense |
|
|
189,780 |
|
|
|
105,868 |
|
|
|
69,374 |
|
Deferred income tax expense (benefit) |
|
|
72,568 |
|
|
|
(43,922 |
) |
|
|
(52,560 |
) |
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
77,683 |
|
|
|
143,284 |
|
|
|
121,217 |
|
Adjustment to reconcile to reported Net Income from
Unconsolidated Equity Affiliate: |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense (benefit) |
|
|
(91,877 |
) |
|
|
38,516 |
|
|
|
34,827 |
|
|
|
|
|
|
|
|
|
|
|
Net Income Equity Affiliate |
|
|
169,560 |
|
|
|
104,768 |
|
|
|
86,390 |
|
Equity interest in unconsolidated equity affiliate |
|
|
40 |
% |
|
|
40 |
% |
|
|
40 |
% |
|
|
|
|
|
|
|
|
|
|
Income before amortization of excess basis in equity affiliate |
|
|
67,824 |
|
|
|
41,907 |
|
|
|
34,556 |
|
Amortization of excess basis in equity affiliate |
|
|
(1,414 |
) |
|
|
(1,356 |
) |
|
|
(1,155 |
) |
Conform depletion expense to GAAP |
|
|
(246 |
) |
|
|
183 |
|
|
|
2,533 |
|
|
|
|
|
|
|
|
|
|
|
Net income from unconsolidated equity affiliate |
|
$ |
66,164 |
|
|
$ |
40,734 |
|
|
$ |
35,934 |
|
|
|
|
|
|
|
|
|
|
|
S-25
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(in thousands) |
|
Current assets |
|
$ |
535,225 |
|
|
$ |
404,825 |
|
Property and equipment |
|
|
321,816 |
|
|
|
265,442 |
|
Other assets |
|
|
67,755 |
|
|
|
141,245 |
|
Current liabilities |
|
|
406,339 |
|
|
|
345,812 |
|
Other liabilities |
|
|
39,224 |
|
|
|
33,600 |
|
Net equity |
|
|
479,233 |
|
|
|
432,100 |
|
Fusion Geophysical, LLC (Fusion)
Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir
engineering. The purchase of Fusion extended 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, 2010, 2009 and 2008, respectively. Summarized financial information for Fusion
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Operating Revenues |
|
$ |
10,931 |
|
|
$ |
11,089 |
|
|
$ |
13,063 |
|
Net Loss |
|
$ |
(2,378 |
) |
|
$ |
(4,798 |
) |
|
$ |
(1,290 |
) |
Equity interest in unconsolidated equity affiliate |
|
|
49 |
% |
|
|
49 |
% |
|
|
49 |
% |
|
|
|
|
|
|
|
|
|
|
Net loss from unconsolidated equity affiliate |
|
|
(1,165 |
) |
|
|
(2,351 |
) |
|
|
(632 |
) |
Amortization of fair value of intangibles |
|
|
|
|
|
|
(995 |
) |
|
|
(726 |
) |
Impairment of investment |
|
|
|
|
|
|
(1,631 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from unconsolidated equity affiliate |
|
$ |
(1,165 |
) |
|
$ |
(4,977 |
) |
|
$ |
(1,358 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December, 31 |
|
|
|
2010 |
|
|
2009 |
|
Current assets |
|
$ |
1,925 |
|
|
$ |
2,726 |
|
Total assets |
|
|
23,780 |
|
|
|
30,205 |
|
Current liabilities |
|
|
7,447 |
|
|
|
8,024 |
|
Total liabilities |
|
|
7,479 |
|
|
|
12,242 |
|
Approximately 16 percent, 29 percent and 26 percent of Fusions revenue for the years ended
December 31, 2010, 2009 and 2008, 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, 2010,
the balance for prepaid services was approximately $0.6 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
S-26
therefore, we recorded a $1.6 million charge to fully impair the carrying value of our equity
investment in Fusion at December 31, 2009. For the year ended December 31, 2010, Fusion had a year
to date net loss. Since our investment in Fusion was fully impaired at year-end 2009, Fusions
2010 year to date net loss is not reported in the twelve months ended December 31, 2010 net income
from unconsolidated equity affiliates as reporting it would take our equity investment in Fusion
into a negative position.
On January 28, 2011, Fusions 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a
private purchaser pursuant to an Agreement and Plan of Merger. We received $1.3 million for our
equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full
of the outstanding balance of the prepaid service agreement, short term loan and accrued interest.
The Agreement and Plan of Merger includes an Earn Out provision wherein we would receive an
additional payment of up to a maximum of $2.7 million if FusionGeo, Inc.s 2011 gross profit
exceeds $5.6 million. The Earn Out payment will not be determined until early in 2012. We can
give no assurance that we will receive any Earn Out payment.
Note 10 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.
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. 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. We are the operator and have an initial working interest of 50 percent in West
Bay, the second prospect in the AMI. The first prospect in the AMI was abandoned in 2009 after a
dry hole was drilled. The private third party contributed these two prospects, including 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. The funding
obligation was met during 2009, and all costs are now being shared by the parties in proportion to
their working interests as defined in the AMI.
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.
West Bay Project
During the year ended December 31, 2010, operational activities in the West Bay prospect
focused on firming up plans for drilling on the identified initial drilling prospect and continuing
to evaluate the other leads and prospects in the project. Land, regulatory and surface access
preparations currently in progress are focused on taking the initial drilling prospect to
drill-ready status. During 2010, we finalized a 3-D seismic data trade with a third party and
merged the data set with our existing seismic data. The acquisition and merging of the additional
3-D seismic data allows for more complete technical evaluation of the leads and prospects
identified in the project. Based on the merged seismic data set, we now have four identified
drilling prospects on our acreage. Preliminary work is underway on a drilling barge concept that
will be utilized to drill the first two exploration wells. Current plans are to drill the first
exploration well in 2011, pending required surface access agreements with a private landowner and
pending receipt of necessary permits from the U.S. Army Corps of Engineers.
In February 2011, the previously existing Alligator Point Unit (as approved by the Texas
General Land Office [GLO]) expired. We have obtained from the GLO an extension until September
1, 2011 of a smaller version of the Alligator Point Unit defined more specifically by the drilling
prospects currently existing on the project. As a result of the GLO approval of the smaller
Alligator Point Unit and the anticipated expiry of five leases previously held by the larger unit,
we expect our lease position on the West Bay project to be reduced from approximately 13,000 acres
in February 2011 to approximately 10,050 acres in August 2011.
The West Bay project represents $3.3 million and $3.1 million of unproved oil and gas
properties as of December 31, 2010 and 2009, respectively.
S-27
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 was obligated to assemble the initial 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.
In July 2010, we executed a farm-out agreement with the private third party in the JEDA for
the acquisition of an incremental 10 percent interest in the Antelope Project with an effective
date of July 1, 2010. This acquisition
includes all leases, the Mesaverde, the Lower Green River/Upper Wasatch and the Monument Butte
Extension. The acquisition excludes the initial eight wells previously drilled in the Monument
Butte Extension. Total consideration for the incremental 10 percent interest is $20.0 million, of
which (1) $3.0 million was paid on August 2, 2010 (the closing date of the acquisition); (2) $3.0
million to be used as a credit against future joint interest billings or if joint interest billings
do not accumulate to $3.0 million by October 1, 2010, at the sole election of the private third
party, the balance is to be paid by us within 15 days of receipt of written request from the
private third party; and (3) a capped $14.0 million carry of a portion of our partners exploration
and development cost obligations in the upcoming Lower Green River/Upper Wasatch and Monument Butte
Extension drilling programs in the Antelope project. On October 1, 2010, the private third party
elected to receive in cash the remaining balance of the joint interest billing credit of $2.4
million. At December 31, 2010, the outstanding balance on the $14.0 million exploration and
development cost obligation carry is $8.4 million. Based on current plans, we anticipate the full
carry obligation will be met in the first half of 2011. This acquisition increases our ownership
in the Antelope project to 70 percent.
The Antelope leasing activities represents $41.1 million and $19.4 million unproved oil and
gas properties as of December 31, 2010 and 2009, respectively.
The Antelope 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.
Mesaverde
Operational activities during the year ended December 31, 2010 included completion of the
initial testing activities on the Mesaverde horizons in the deep natural gas test well (the Bar F)
that commenced drilling on June 15, 2009. The Bar F was drilled to a total depth of 17,566 feet
and an extended production test of the Mesaverde has been completed. Testing was 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. Gas was
tested at flow rates of 1.5-2 million cubic feet per day (MMCFD) from selected intervals. While
the results to date have not definitively determined the commerciality of a stand-alone development
of the Mesaverde in the current gas price environment, we believe that the test results confirm
that the Mesaverde formation exhibits sufficient quantities of hydrocarbons and reservoir
over-pressure to justify potential development, and we are actively pursuing efforts to assess
whether reserves can be attributed to this reservoir. The Mesaverde reservoir remains potentially
prospective
S-28
over a portion of our land position. Exploratory drilling costs for the Mesaverde have
been suspended pending further evaluation. The Mesaverde project represents $16.5 million and
$11.3 million of unproved oil and gas properties on our December 31, 2010 and 2009 balance sheets,
respectively.
Lower Green River/Upper Wasatch
The Lower Green River/Upper Wasatch is a second prospective horizon that is being pursued in
the Antelope project. After completion of the initial testing program on the Mesaverde deep gas in
the Bar F well as described above, we moved uphole in the same well to test multiple oil bearing
intervals at depths from 8,200 feet to 9,500 feet in the Lower Green River and Upper Wasatch.
Extended flow testing of the well conducted during the second quarter of 2010 indicated that a
commercial oil discovery was made in the Lower Green River and Upper Wasatch. A five well Lower
Green River/Upper Wasatch delineation and development drilling program was planned to further
delineate and appraise the extent of the Lower Green River/Upper Wasatch discovery made in the Bar
F, and to establish additional production from the Lower Green River/Upper Wasatch reservoirs in at
least some of the five appraisal wells. Based on results of the initial wells in the five well
delineation and development drilling program, an additional sixth well was added to the program to
be drilled in early 2011.
The five-well delineation and development drilling program was initiated in the third quarter
of 2010. Five wells were in varying stages of completion and drilling and production facilities
installation as of December 31, 2010.
During the fourth quarter of 2010, we initiated permitting activities on a planned 170 square
mile 3-D seismic acquisition program which is expected to be acquired in late 2011 and which will
be targeted at imaging the Green River and Wasatch formations over the northern portion of our
acreage.
On December 21, 2010, we and our partner in the Antelope project entered into a contract with
El Paso Midstream Group, Inc. (EPMG) whereby EPMG will provide the capital to build and operate a
25-mile, low-pressure gas gathering pipeline which will provide capacity for our current and future
production from the Lower Green River/Upper Wasatch Development project. We will provide capital
to build flowlines to connect the produced gas from our wells into the EPMG header system. As part
of the contract arrangement, we and our partner have dedicated approximately 75 percent of our
Antelope leasehold to the El Paso contract for 10 years, with a Harvest option to extend the
dedication for up to an additional nine years without any change in contract terms. The area
dedication is limited stratigraphically to the top of the Mesaverde formation, resulting in the
Mesaverde deep gas not being included in the dedication.
The Lower Green River/Upper Wasatch represents $21.2 million of proved and $10.5 million of
unproved oil and gas properties on our December 31, 2010 balance sheet and $5.6 million of
unproved oil and gas properties on our December 31, 2009 balance sheet.
Monument Butte
The Monument Butte Extension was initiated in the fourth quarter of 2009 with an eight well
appraisal and development drilling program to produce oil and natural gas from the Green River
formation. The parties participating in the wells formed a 320 acre AMI, which contained the
initial eight drilling locations.
As a follow up to the successful completion of the initial eight well program that was drilled
in late 2009 and early 2010, a six well appraisal and development drilling program was approved in
2010. The six well expansion is on acreage immediately adjacent to the initial eight well program.
The first 14 wells in the Monument Butte Extension (as defined above) are non-operated, and we
hold a 43 percent working interest in the initial eight wells and an approximate 37 percent working
interest in the follow-up six wells.
During 2010, an additional Harvest operated well, the K Moon #2-13-4-3, was added to the
project. We have an approximate 60 percent working interest in the well.
S-29
Operational activities during 2010 for the Monument Butte Extension consisted of routine
production operations from the initial eight wells and implementation of the six well expansion
program in third quarter 2010. Five of the six wells were drilled and four were on production as
of December 2010. The sixth and final well spud on February 3, 2011. The Monument Butte Extension
represents $6.2 million of proved and $0.7 million of unproved oil and gas properties and $1.6
million of proved and $0.3 million of unproved oil and gas properties on our December 31, 2010 and
2009 balance sheets, respectively.
Note 11 Indonesia
In December 2007, we entered into a Farmout Agreement to acquire a 47 percent interest in the
Budong PSC located mostly onshore West Sulawesi, Indonesia. In April 2008, the Government of
Indonesia approved the assignment to us of the 47 percent interest in the Budong PSC. Our partner
is the operator through the exploration phase as required by the terms of the Budong PSC, and we
have an option to become operator, if approved by Government of Indonesia and BPMIGAS, the oil and
gas regulatory authority, in any subsequent development and production phase.
We acquired our original 47 percent interest in the Budong PSC by committing to fund the first
phase of the exploration program including the acquisition of 2-D seismic and drilling of the first
two exploration wells under a Farmout Agreement with operator of the Budong PSC. Under the Farmout
Agreement, the initial commitment was to fund the first phase of the exploration program up to a
cap of $17.2 million. The commitment cap 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 cap of each component was met, all subsequent costs are shared by the parties in
proportion to their ownership interests. Prior to drilling the first exploration well, our partner
had a one-time option to increase the level of the carried interest to a maximum of $20.0 million.
On September 15, 2010, our partner exercised their option to increase the carry obligation by $2.7
million to a total of $19.9 million ($7.9 million for acquisition of seismic and $12.0 million for
drilling). The additional carry increased our ownership by 7.4 percent
to 54.4 percent. On March 3, 2011, the Government of Indonesia and BPMIGAS approved this
change in ownership interest.
On January 5, 2011, we exercised our first refusal right to a proposed transfer of interest by
the operator to a third party, which has allowed us to acquire an additional 10 percent equity in
the Budong PSC at a cost of $3.7 million payable ten business days after completion of the first
exploration well. Closing of this acquisition, which is subject to the approval of the Government
of Indonesia and BPMIGAS, will increase our interest in the Budong PSC to 64.4 percent.
During the initial exploration period, the Budong PSC covered 1.35 million acres. The term of
the Budong PSC is for 30 years which provides for an exploration period of up to ten years.
Pursuant to the Budong PSC, at end of the first three-year exploration phase, 35 percent of the
original area was relinquished to BPMigas. The second three-year exploration phase began in
January 2010 covering 0.88 million acres.
Operational activities during 2010 focused on well planning, construction for two test well
sites, mobilization of rig and ancillary equipment to the first drill site. After delays in
acquiring permits to mobilize the drilling rig from its port location to the drilling pad, the
first exploratory well, the Lariang-1 (LG-1), was spud on January 6, 2011. The Budong PSC
represents $10.9 million and $2.0 million of unproved oil and gas properties on our December 31,
2010 and 2009 balance sheets, respectively.
Note 12 Gabon
We are the operator of the Dussafu PSC with a 66.667 percent ownership interest. Located
offshore Gabon, adjacent to the border with the Republic of Congo, the Dussafu PSC covers an area
of 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. It was agreed that
the second three-year exploration phase be extended until May 27, 2011, at which time the partners
can elect to enter a third exploration phase. Operational
S-30
activities during 2010 included the
maturation of the prospect inventory and well planning. We have issued purchase orders for long
lead items required for drilling. Other drilling contracts are being tendered in preparation to
spud the exploration well in the second quarter of 2011. The exploratory well to be drilled in the
second quarter of 2011 will test stacked reservoir potential in the pre-salt section. A Letter of
Intent has been agreed for a semi-submersible rig to commence a contract in April 2011 to drill the
Ruche Marin prospect. To complete the drilling activities a six month extension to November 27,
2011 of the second Exploration Period has been requested. The Dussafu PSC represents $9.2 million
and $6.9 million of unproved oil and gas properties on our December 31, 2010 and 2009 balance
sheets, respectively.
Note 13 Oman
In April 2009, we signed an EPSA with Oman for the Block 64 EPSA. We have a 100 percent
working interest in Block 64 EPSA during the exploration phase. Oman Oil Company has the option to
back-in to up to a 20 percent interest in Block 64 EPSA after the discovery of gas.
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 shallow oil fields within Block 64 EPSA area. The 955,600 acre block is located
in the gas and condensate rich Ghaba Salt Basin in close proximity to the Barik, Saih Rawl and Saih
Nihayda gas and condensate fields. We have an obligation to drill two wells over a three-year
period with a funding commitment of $22.0 million. Operational activities during 2010 included
geological studies, baseline environmental and social study and 3-D pre-stack depth migration
reprocessing of approximately 1,150 square kilometers of existing 3-D seismic data. During 2011,
geological and geophysical interpretation of the reprocessed 3-D will take place to mature drilling
locations. Well planning and procurement of long lead items will commence in the first half of 2011
to enable the first of the two exploratory wells to commence drilling in the fourth quarter of
2011. The Block 64 EPSA represents $4.2 million and $3.8 million of unproved oil and gas
properties on our December 31, 2010 and 2009 balance sheets, respectively.
Note 14 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. We are in the process of obtaining a new license extension and believe that it will be
granted. While no assurance can be given, we believe we will continue to receive contract
extensions so long as the border disputes persist. WAB-21 represents $3.1 million and $3.0 million
of unproved oil and gas properties on our December 31, 2010 and 2009 balance sheets, respectively.
Note 15 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 33.5 million, 33.1
million and 34.1 million for the years ended December 31, 2010, 2009 and 2008, 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 39.3
million, 33.1 million and 34.1 million for the years ended December 31, 2010, 2009 and 2008,
respectively.
An aggregate of 2.9 million options and 6.0 million warrants were excluded from earnings per
share calculations because their exercise price exceeded the average price for the year ended
December 31, 2010. An aggregate of 3.7 million options were excluded from earnings per share
calculations because their exercise price
S-31
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.
Note 16 Related Party Transactions
Dividends declared and paid by Petrodelta are paid to HNR Finance. HNR Finance must declare a
dividend in order for the partners, Harvest and Vinccler, to receive their respective shares of
Petrodeltas dividend. Petrodelta has declared two dividends, totaling $33.0 million, which have
been received by HNR Finance and for which HNR Finance has not
distributed to the partners. At December 31, 2010, Vincclers share of the undistributed dividends is $6.6 million.
Note 17 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 5, 2011, we exercised our first refusal right to a proposed transfer of interest by
the operator to a third party, to acquire an additional ten percent equity in the Budong PSC for a
consideration of $3.7 million payable ten business days after completion of the first exploration
well. Closing of this acquisition will increase our interest in the Budong PSC to 64.4 percent.
The change in ownership interest is subject approval from the Government of Indonesia and BPMIGAS.
On January 28, 2011, Fusions 69 percent owned subsidiary, FusionGeo, Inc., was acquired by a
private purchaser pursuant to an Agreement and Plan of Merger. We received $1.3 million for our
equity investment, subject to post-closing adjustments, and $0.7 million for the repayment in full
of the outstanding balance of the prepaid service agreement, short term loan and accrued interest.
The Agreement and Plan of Merger includes an Earn Out provision wherein we would receive an
additional payment of up to a maximum of $2.7 million if FusionGeo, Inc.s 2011 gross profit
exceeds $5.6 million. The Earn Out payment will not be determined until early in 2012.
We can give no assurance that we will receive any Earn Out payment.
In February 2011, the previously existing Alligator Point Unit (as approved by the GLO)
expired. We have obtained from the GLO an extension until September 1, 2011 of a smaller version
of the Alligator Point Unit defined more specifically by the drilling prospects currently existing
on the project. As a result of the GLO approval of the smaller Alligator Point Unit and the
anticipated expiry of five leases previously held by the larger unit, we expect our lease position
on the West Bay project to be reduced from approximately 13,000 acres in February 2011 to
approximately 10,050 acres in August 2011.
On March 3, 2011, the Government of Indonesia and BPMIGAS approved our change in ownership
interest in the Budong PSC from 47 percent to 54.4 percent.
S-32
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, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
3,124 |
|
|
$ |
2,914 |
|
|
$ |
1,919 |
|
|
$ |
2,739 |
|
Expenses |
|
|
(7,773 |
) |
|
|
(9,771 |
) |
|
|
(11,078 |
) |
|
|
(12,765 |
) |
Non-operating loss |
|
|
(1,812 |
) |
|
|
(572 |
) |
|
|
(92 |
) |
|
|
(5,196 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from consolidated companies before income taxes |
|
|
(6,461 |
) |
|
|
(7,429 |
) |
|
|
(9,251 |
) |
|
|
(15,222 |
) |
Income tax expense (benefit) |
|
|
(19 |
) |
|
|
152 |
|
|
|
699 |
|
|
|
(1,016 |
) (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from consolidated companies |
|
|
(6,442 |
) |
|
|
(7,581 |
) |
|
|
(9,950 |
) |
|
|
(14,206 |
) |
Net income from unconsolidated equity affiliates |
|
|
38,367 |
|
|
|
8,915 |
|
|
|
6,148 |
|
|
|
12,734 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
31,925 |
|
|
|
1,334 |
|
|
|
(3,802 |
) |
|
|
(1,472 |
) |
Less: Net income attributable to noncontrolling interest |
|
|
7,335 |
|
|
|
1,630 |
|
|
|
1,189 |
|
|
|
2,491 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Harvest |
|
$ |
24,590 |
|
|
$ |
(296 |
) |
|
$ |
(4,991 |
) |
|
$ |
(3,963 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Harvest per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.74 |
|
|
$ |
(0.01 |
) |
|
$ |
(0.15 |
) |
|
$ |
(0.12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.64 |
|
|
$ |
(0.01 |
) |
|
$ |
(0.15 |
) |
|
$ |
(0.12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Includes an out-of-period income tax benefit adjustment of $1.0 million identified
during the fourth quarter of 2010 which relates to the third quarter
of 2010. See note 6 Taxes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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-33
|
|
|
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, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs |
|
$ |
|
|
|
$ |
|
|
|
$ |
2,703 |
|
|
$ |
21,757 |
|
|
$ |
24,460 |
|
Exploration costs |
|
|
1,698 |
|
|
|
2,763 |
|
|
|
10,468 |
|
|
|
27,576 |
|
|
|
42,505 |
|
Development costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,667 |
|
|
|
7,667 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,698 |
|
|
$ |
2,763 |
|
|
$ |
13,171 |
|
|
$ |
57,000 |
|
|
$ |
74,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved property costs |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
27,355 |
|
|
$ |
27,355 |
|
Unproved property costs |
|
|
4,216 |
|
|
|
9,177 |
|
|
|
9,459 |
|
|
|
71,173 |
|
|
|
94,025 |
|
Oilfield Inventories |
|
|
|
|
|
|
|
|
|
|
1,435 |
|
|
|
3,965 |
|
|
|
5,400 |
|
Less accumulated depletion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,327 |
) |
|
|
(3,327 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,216 |
|
|
$ |
9,177 |
|
|
$ |
10,894 |
|
|
$ |
99,166 |
|
|
$ |
123,453 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2010 consisted of the following by year incurred (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
Prior |
|
Property acquisition costs |
|
$ |
94,025 |
|
|
$ |
37,184 |
|
|
$ |
35,307 |
|
|
$ |
18,371 |
|
|
$ |
3,163 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S-34
|
|
|
|
|
TABLE III Results of operations for oil and natural gas producing activities (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
Revenue: |
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
10,696 |
|
|
$ |
181 |
|
Expenses: |
|
|
|
|
|
|
|
|
Operating, selling and distribution expenses and taxes
other than on income |
|
|
1,846 |
|
|
|
15 |
|
Exploration expense |
|
|
8,016 |
|
|
|
7,824 |
|
Depletion |
|
|
3,298 |
|
|
|
29 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
13,160 |
|
|
|
7,868 |
|
|
|
|
|
|
|
|
Results of operations from oil and natural gas producing activities |
|
$ |
(2,464 |
) |
|
$ |
(7,687 |
) |
|
|
|
|
|
|
|
|
|
|
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. 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.
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 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.
See the following section Additional Supplemental Information on Oil and Natural Gas Producing
Activities (unaudited) for Venezuela Equity Affiliate as of December 31, 2010, 2009 and 2008, TABLE
IV Quantities of Oil and Natural Gas Reserves for Petrodeltas reserves.
S-35
The table shown below represents our interests in the United States. At December 31,
2009 we had three Proved Developed wells and five Proved Undeveloped (PUD) locations identified
in the Monument Butte area. During 2010, we identified and approved the development of 41 further
locations. A total of 13 wells have been moved to Proved Developed Producing (PDP) in 2010
including the five PUD locations identified at December 31, 2009 and eight other wells. This
results in a total of 16 PDP wells and 43 identified PUD locations at December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
Oil and NGL |
|
|
Gas |
|
|
Oil and NGL |
|
|
Gas |
|
|
|
(MBbls) |
|
|
(MMcf) |
|
|
(MBbls) |
|
|
(MMcf) |
|
Proved Reserves |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1 |
|
|
226 |
|
|
|
1,126 |
|
|
|
|
|
|
|
|
|
Revisions |
|
|
147 |
|
|
|
914 |
|
|
|
|
|
|
|
|
|
Acquisitions |
|
|
15 |
|
|
|
12 |
|
|
|
229 |
|
|
|
1,132 |
|
Extensions |
|
|
3,267 |
|
|
|
4,863 |
|
|
|
|
|
|
|
|
|
Production |
|
|
(140 |
) |
|
|
(423 |
) |
|
|
(3 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves at December 31 |
|
|
3,515 |
|
|
|
6,492 |
|
|
|
226 |
|
|
|
1,126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
659 |
|
|
|
2,476 |
|
|
|
131 |
|
|
|
653 |
|
Undeveloped |
|
|
2,856 |
|
|
|
4,016 |
|
|
|
95 |
|
|
|
473 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved |
|
|
3,515 |
|
|
|
6,492 |
|
|
|
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
$64.45 per barrel for oil and $3.75 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, 2010.
S-36
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
(in thousands) |
|
|
|
December 31, 2010 |
|
|
December 31, 2009 |
|
Future cash inflows from sales of oil and gas |
|
$ |
250,712 |
|
|
$ |
14,626 |
|
Future production costs |
|
|
(75,602 |
) |
|
|
(3,674 |
) |
Future development costs |
|
|
(62,246 |
) |
|
|
(1,171 |
) |
Future income tax expenses |
|
|
(37,262 |
) |
|
|
(3,147 |
) |
|
|
|
|
|
|
|
Future net cash flows |
|
|
75,602 |
|
|
|
6,634 |
|
Effect of discounting net cash flows at 10% |
|
|
(45,632 |
) |
|
|
(1,911 |
) |
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
29,970 |
|
|
$ |
4,723 |
|
|
|
|
|
|
|
|
TABLE VI Changes in the Standardized Measure of Discounted Future Net Cash Flows from
Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
(in thousands) |
|
|
|
2010 |
|
|
2009 |
|
Standardized Measure at January 1 |
|
$ |
4,723 |
|
|
$ |
|
|
Sales of oil and natural gas, net of related costs |
|
|
(8,850 |
) |
|
|
(166 |
) |
Revisions to estimates of proved reserves: |
|
|
|
|
|
|
|
|
Net changes in prices, net of production costs |
|
|
2,766 |
|
|
|
|
|
Quantities |
|
|
3,734 |
|
|
|
|
|
Purchase and sale of reserves in place |
|
|
387 |
|
|
|
|
|
Extensions, discoveries and improved recovery, net of future costs |
|
|
36,211 |
|
|
|
6,978 |
|
Accretion of discount |
|
|
535 |
|
|
|
|
|
Development costs incurred |
|
|
2,427 |
|
|
|
|
|
Changes in estimated development costs |
|
|
(1,256 |
) |
|
|
|
|
Net change in income taxes |
|
|
(10,707 |
) |
|
|
(2,089 |
) |
|
|
|
|
|
|
|
Standardized Measure at December 31 |
|
$ |
29,970 |
|
|
$ |
4,723 |
|
|
|
|
|
|
|
|
S-37
Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)
for Petrodelta S.A. as of December 31, 2010, 2009 and 2008
The following tables summarize the proved reserves, drilling and production activity, and
financial operating data at the end of each year for our net 32 percent interest in Petrodelta.
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, 2010, 2009 and
2008.
TABLE I Total costs incurred in oil and natural gas acquisition, exploration and development
activities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Development costs |
|
$ |
29,976 |
|
|
$ |
26,605 |
|
|
$ |
17,144 |
|
Exploration costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
29,976 |
|
|
$ |
26,605 |
|
|
$ |
17,744 |
|
|
|
|
|
|
|
|
|
|
|
TABLE II Capitalized costs related to oil and natural gas producing activities (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Proved property costs |
|
$ |
139,702 |
|
|
$ |
108,696 |
|
|
$ |
79,807 |
|
Unproved property costs |
|
|
1,365 |
|
|
|
163 |
|
|
|
3,036 |
|
Oilfield inventories |
|
|
9,630 |
|
|
|
10,748 |
|
|
|
7,892 |
|
Less accumulated depletion and impairment |
|
|
(43,856 |
) |
|
|
(27,089 |
) |
|
|
(16,966 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
106,841 |
|
|
$ |
92,518 |
|
|
$ |
73,769 |
|
|
|
|
|
|
|
|
|
|
|
TABLE III Results of operations for oil and natural gas producing activities (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
194,423 |
|
|
$ |
146,640 |
|
|
$ |
151,878 |
|
Royalty |
|
|
(65,500 |
) |
|
|
(50,176 |
) |
|
|
(54,013 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
128,923 |
|
|
|
96,464 |
|
|
|
97,865 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating,
selling and distribution expenses and taxes other than on income |
|
|
22,359 |
|
|
|
15,742 |
|
|
|
42,876 |
|
Depletion |
|
|
12,387 |
|
|
|
10,123 |
|
|
|
5,903 |
|
Income tax expense |
|
|
47,089 |
|
|
|
35,300 |
|
|
|
23,530 |
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
81,835 |
|
|
|
61,165 |
|
|
|
72,309 |
|
|
|
|
|
|
|
|
|
|
|
Results of operations from oil and natural gas producing activities |
|
$ |
47,088 |
|
|
$ |
35,299 |
|
|
$ |
25,556 |
|
|
|
|
|
|
|
|
|
|
|
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 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.
S-38
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 originally 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 in 2009 and again in 2010 when the wells drilled in El
Salto resulted in a modification to the El Salto program.
During 2010, Petrodelta drilled 16 wells. Six of the wells were previously identified PUD
locations and ten wells were previously classified Probable, Possible or undefined. In 2010, an
additional 24 PUD locations were identified through drilling activity. At December 31, 2010,
Petrodelta had a total of 182 PUD (33,906 MBOE) locations identified. Since the implementation of
its 2007 business plan, Petrodelta has drilled 40 gross wells (2008 nine wells [1,394 MBOE], 2009
15 wells [1,999 MBOE] and 2010 16 wells [1,954MBOE]) which have moved to the proved developed
producing (PDP) category. Of these 40 locations drilled since 2008, 23 (3,730 MBOE) represent
the movements of PUD locations to PDP locations. The other 17 new producing wells (1,617 MBOE)
were previously classified Probable, Possible or un-defined. All
above MBOE represent our net 32
percent interest, net of a 33.33 percent royalty.
Petrodelta has a track record of identifying, executing and converting its PUD locations to
PDP locations in accordance with the business plan defined by the conversion contract executed in
2007 and subsequent updates. However, the timing and pace of the development is controlled by the
majority owner, PDVSA through CVP, although we have substantial negative control provisions as a
noncontrolling interest shareholder. In 2010, Petrodelta submitted a revised business plan to
PDVSA which substantially increases the total projected drilling activity and production volumes
compared to the 2007 business plan, but which is otherwise consistent with the 2007 business plan.
The 2010 business plan, as approved by PDVSA, contemplates sustained drilling activities through
the year 2024 to fully develop the El Salto and Temblador fields. In accordance with this revised
development plan for Petrodelta, HNR Finance has elected to report a portion of their PUDs to be
developed past a five year window. Most PUD locations are scheduled to be drilled within five
years of their first identification; however, there are some PUD locations that are scheduled to be
drilled more than five years after the PUD locations were first identified. At December 2010, the
proportion of proved reserves expected to be drilled in the sixth year after initial booking is 21
percent of Proved (BOE) reserves and the proportion drilled in the seventh year is two percent of
Proved (BOE) reserves. As a noncontrolling interest shareholder in Petrodelta, HNR Finance has
limited ability to control the development plans that are periodically prepared and/or approved by
the Venezuelan government. Since this constraint represents a hindrance to development not
experienced by typical operations, inclusion of a portion of the activities planned for year six
and seven represents a fair comparison to operators with assets covered by more flexible regulatory
conditions where increasing rig count can ameliorate a slow development plan.
From 2008 through 2010, a number of factors adversely affected the pace of development of the
fields. 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. Since early 2009, 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 continues to have an adverse effect on Petrodeltas ability to carry out its business plan.
These events have been outside of our control.
In summary, Petrodelta has operated the Petrodelta Fields since October 2007 when the
Conversion Contract was signed. The business plan, as defined by the Conversion Contract, defines
the development of the Petrodelta Fields. Under its business plan, Petrodelta has demonstrated a
track record of identifying, executing and converting its PUD locations to PDP locations. However,
the timing and pace of the development is controlled by
the majority owner, PDVSA through CVP, and as a noncontrolling interest shareholder in
Petrodelta, HNR Finance
has limited ability to control the development plans that are periodically
prepared and or approved by PDVSA and CVP.
S-39
The tables shown below represent HNR Finances 40 percent ownership interest and our net 32
percent ownership interest, both net of a 33.33 percent royalty, in Venezuela in each of the years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority |
|
|
|
|
Proved Reserves-Crude oil, condensate, |
|
|
|
|
|
Interest in |
|
|
32% |
|
and natural gas liquids (MBbls) |
|
HNR Finance |
|
|
Venezuela |
|
|
Net Total |
|
As of December 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1, 2010 |
|
|
47,419 |
|
|
|
(9,483 |
) |
|
|
37,936 |
|
Revisions |
|
|
(230 |
) |
|
|
45 |
|
|
|
(185 |
) |
Extensions |
|
|
7,199 |
|
|
|
(1,440 |
) |
|
|
5,759 |
|
Production |
|
|
(2,283 |
) |
|
|
457 |
|
|
|
(1,826 |
) |
|
|
|
|
|
|
|
|
|
|
Proved Reserves at end of the year |
|
|
52,105 |
|
|
|
(10,421 |
) |
|
|
41,684 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
16,342 |
|
|
|
(3,268 |
) |
|
|
13,074 |
|
Undeveloped |
|
|
35,763 |
|
|
|
(7,153 |
) |
|
|
28,610 |
|
|
|
|
|
|
|
|
|
|
|
Total Proved |
|
|
52,105 |
|
|
|
(10,421 |
) |
|
|
41,684 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
13,415 |
|
|
|
(2,683 |
) |
|
|
10,732 |
|
Undeveloped |
|
|
29,394 |
|
|
|
(5,878 |
) |
|
|
23,516 |
|
|
|
|
|
|
|
|
|
|
|
Total Proved |
|
|
42,809 |
|
|
|
(8,561 |
) |
|
|
34,248 |
|
|
|
|
|
|
|
|
|
|
|
S-40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority |
|
|
|
|
|
|
|
|
|
|
Interest in |
|
|
32% |
|
Proved Reserves-Natural gas (MMcf) |
|
HNR Finance |
|
|
Venezuela |
|
|
Net Total |
|
As of December 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves at January 1, 2010 |
|
|
62,710 |
|
|
|
(12,542 |
) |
|
|
50,168 |
|
Revisions |
|
|
(843 |
) |
|
|
169 |
|
|
|
(674 |
) |
Extensions |
|
|
2,192 |
|
|
|
(438 |
) |
|
|
1,754 |
|
Production |
|
|
(1,491 |
) |
|
|
298 |
|
|
|
(1,193 |
) |
|
|
|
|
|
|
|
|
|
|
Proved Reserves at end of the year |
|
|
62,568 |
|
|
|
(12,513 |
) |
|
|
50,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
22,850 |
|
|
|
(4,569 |
) |
|
|
18,281 |
|
Undeveloped |
|
|
39,718 |
|
|
|
(7,944 |
) |
|
|
31,774 |
|
|
|
|
|
|
|
|
|
|
|
Total Proved |
|
|
62,568 |
|
|
|
(12,513 |
) |
|
|
50,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
30,168 |
|
|
|
(6,034 |
) |
|
|
24,134 |
|
Undeveloped |
|
|
37,636 |
|
|
|
(7,527 |
) |
|
|
30,109 |
|
|
|
|
|
|
|
|
|
|
|
Total Proved |
|
|
67,804 |
|
|
|
(13,561 |
) |
|
|
54,243 |
|
|
|
|
|
|
|
|
|
|
|
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
$70.43 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
S-41
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority |
|
|
|
|
|
|
|
|
|
|
Interest in |
|
|
|
|
|
|
HNR Finance |
|
|
Venezuela |
|
|
Net Total |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
December 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows from sales of oil and gas |
|
$ |
3,748,419 |
|
|
$ |
(749,684 |
) |
|
$ |
2,998,735 |
|
Future production costs |
|
|
(870,498 |
) |
|
|
174,100 |
|
|
|
(696,398 |
) |
Future development costs |
|
|
(296,744 |
) |
|
|
59,349 |
|
|
|
(237,395 |
) |
Future income tax expenses |
|
|
(1,241,452 |
) |
|
|
248,290 |
|
|
|
(993,162 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
1,339,725 |
|
|
|
(267,945 |
) |
|
|
1,071,780 |
|
Effect of discounting net cash flows at 10% |
|
|
(608,526 |
) |
|
|
121,705 |
|
|
|
(486,821 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future
net cash flows |
|
$ |
731,199 |
|
|
$ |
(146,240 |
) |
|
$ |
584,959 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
S-42
TABLE VI Changes in the Standardized Measure of Discounted Future Net Cash Flows from
Proved Reserves (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Venezuela |
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Standardized Measure at January 1 |
|
$ |
400,295 |
|
|
$ |
111,361 |
|
|
$ |
523,378 |
|
Sales of oil and natural gas, net of related costs |
|
|
(107,689 |
) |
|
|
(80,725 |
) |
|
|
(54,988 |
) |
Revisions to estimates of proved reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
Net changes in prices, net of production taxes |
|
|
190,119 |
|
|
|
408,054 |
|
|
|
(673,320 |
) |
Quantities |
|
|
(18,284 |
) |
|
|
(25,424 |
) |
|
|
(119,678 |
) |
Extensions, discoveries and improved recovery, net of future costs |
|
|
248,917 |
|
|
|
187,636 |
|
|
|
50,515 |
|
Accretion of discount |
|
|
78,403 |
|
|
|
24,940 |
|
|
|
106,481 |
|
Net change in income taxes |
|
|
(181,186 |
) |
|
|
(262,214 |
) |
|
|
457,582 |
|
Development costs incurred |
|
|
29,965 |
|
|
|
26,756 |
|
|
|
7,791 |
|
Changes in estimated development costs |
|
|
(29,465 |
) |
|
|
(429 |
) |
|
|
13,128 |
|
Timing differences and other |
|
|
(26,116 |
) |
|
|
10,340 |
|
|
|
(199,528 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized Measure at December 31 |
|
$ |
584,959 |
|
|
$ |
400,295 |
|
|
$ |
111,361 |
|
|
|
|
|
|
|
|
|
|
|
S-43
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, 2011 |
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, 2011, on behalf of
the registrant and in the capacities indicated:
|
|
|
Signature |
|
Title |
|
/s/ James A. Edmiston
James A. Edmiston
|
|
Director, President and Chief Executive
Officer
(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-44
SCHEDULE II
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
|
Balance at |
|
|
Charged to |
|
|
Charged
to Other |
|
|
Deductions
From |
|
|
Balance at
End of |
|
|
|
Beginning of Year |
|
|
Income |
|
|
Accounts |
|
|
Reserves |
|
|
Year |
|
At December 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts deducted from applicable assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax valuation allowance |
|
$ |
17,025 |
|
|
$ |
11,318 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
28,343 |
|
Investment at cost |
|
|
1,350 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,350 |
|
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 |
|
S-45
SCHEDULE III
Financial Statements and Notes
for Petrodelta, S.A.
S-46
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación
Venezolana del Petróleo, S.A.)
Financial Statements at December 31, 2010
and 2009
and Independent Auditors Report
S-47
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Index
|
|
|
|
|
|
|
Pages |
|
|
|
S-49-50 |
|
|
|
|
|
|
FINANCIAL STATEMENTS AS OF DECEMBER 31 2010 AND 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
S-51 |
|
|
|
|
S-52 |
|
|
|
|
S-53 |
|
|
|
|
S-54 |
|
|
|
|
S-55 |
|
|
|
|
S-56 |
|
|
|
|
|
|
|
|
|
S-56 |
|
|
|
|
S-58 |
|
|
|
|
S-59 |
|
|
|
|
S-73 |
|
|
|
|
S-75 |
|
|
|
|
S-76 |
|
|
|
|
S-77 |
|
|
|
|
S-83 |
|
|
|
|
S-85 |
|
|
|
|
S-86 |
|
|
|
|
S-86 |
|
|
|
|
S-86 |
|
|
|
|
S-87 |
|
|
|
|
S-87 |
|
|
|
|
S-89 |
|
|
|
|
S-90 |
|
|
|
|
S-91 |
|
|
|
|
S-92 |
|
|
|
|
S-93 |
|
|
|
|
S-95 |
|
|
|
|
S-96 |
|
|
|
|
S-98 |
|
|
|
|
S-98 |
|
|
|
|
S-102 |
|
|
|
|
S-102 |
|
|
|
|
S-103 |
|
S-48
INDEPENDENT AUDITORS REPORT
To the Stockholders and Board of Director of
Petrodelta, S.A.
Report on the Financial Statements
We have audited the accompanying financial statements of Petrodelta, S.A.
(a subsidiary 60% owned by Corporacion Venezolana del Petroleo, S.A. CVP), which comprise
the statements of financial position as at December 31, 2010 and 2009, and the statements of
comprehensive income, statements of changes in equity and statements of cash flows for the year
then ended, and a summary of significant accounting policies and other explanatory information.
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, and for such internal control as
management determines is necessary to enable the preparation of financial statements that are free
from material misstatement, whether due to fraud or error.
Auditors Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We
conducted our audits in accordance with auditing standards generally accepted in the United States
of America. Those standards require that we comply with ethical requirements and plan and perform
the audit to obtain reasonable assurance about whether the financial statements are free from
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
Urbanización Valles de Camoruco. Las 4 Avenidas. Reda Building. Torre B. Oficina 5-11. Valencia.
Carabobo. Venezuela. Telfs: 58-241 8253518 / 8255337 Fax: 8259828. RIF: J-30785734-0
PGFA Perales, Pistone & Asociados es firma miembro de
International
S-49
PETRODELTA, S.A.
(Subsidiary owned 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
management, as well as evaluating the overall presentation of the financial statements. 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 at December 31, 2010 and 2009, and 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 21 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
March 10, 2011
Valencia, Venezuela.
Urbanización Valles de Camoruco. Las 4 Avenidas. Reda Building. Torre B. Oficina 5-11. Valencia.
Carabobo. Venezuela. Telfs: 58-241 8253518 / 8255337 Fax: 8259828. RIF: J-30785734-0
PGFA Perales, Pistone & Asociados es firma miembro de
International
S-50
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 |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
|
|
U.S. Dollars |
|
Bolivars |
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
8 |
|
|
321,816 |
|
|
|
265,442 |
|
|
|
1,383,809 |
|
|
|
570,700 |
|
Deferred income tax |
|
7-(f) |
|
|
60,205 |
|
|
|
143,898 |
|
|
|
258,881 |
|
|
|
309,381 |
|
Recoverable tax credits |
|
7-(k) |
|
|
8,072 |
|
|
|
10,753 |
|
|
|
34,710 |
|
|
|
23,119 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current assets |
|
|
|
|
390,093 |
|
|
|
420,093 |
|
|
|
1,677,400 |
|
|
|
903,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid expenses and other assets |
|
10 |
|
|
407 |
|
|
|
559 |
|
|
|
1,750 |
|
|
|
1,202 |
|
Inventories |
|
11 |
|
|
24,997 |
|
|
|
21,472 |
|
|
|
107,487 |
|
|
|
46,165 |
|
Accounts receivable |
|
12 |
|
|
506,356 |
|
|
|
368,979 |
|
|
|
2,177,331 |
|
|
|
793,305 |
|
Cash and cash equivalents |
|
13 |
|
|
3,465 |
|
|
|
3,062 |
|
|
|
14,900 |
|
|
|
6,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current asset |
|
|
|
|
535,225 |
|
|
|
394,072 |
|
|
|
2,301,468 |
|
|
|
847,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
|
|
|
925,318 |
|
|
|
814,165 |
|
|
|
3,978,868 |
|
|
|
1,750,455 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity, see statements of changes in equity |
|
14 |
|
|
479,233 |
|
|
|
432,100 |
|
|
|
2,060,702 |
|
|
|
929,015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for abandonment cost |
|
9 y 16 |
|
|
29,798 |
|
|
|
24,416 |
|
|
|
128,131 |
|
|
|
52,494 |
|
Provision for retirement benefits |
|
16 |
|
|
8,439 |
|
|
|
9,184 |
|
|
|
36,288 |
|
|
|
19,746 |
|
Deferred income tax |
|
7-(f) |
|
|
1,509 |
|
|
|
2,653 |
|
|
|
6,488 |
|
|
|
5,704 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current liabilities |
|
|
|
|
39,746 |
|
|
|
36,253 |
|
|
|
170,907 |
|
|
|
77,944 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
15 |
|
|
52,095 |
|
|
|
105,332 |
|
|
|
224,009 |
|
|
|
226,464 |
|
Dividends payable |
|
14 |
|
|
18,330 |
|
|
|
31,126 |
|
|
|
78,819 |
|
|
|
66,921 |
|
Accruals and other liabilities |
|
16 |
|
|
171,415 |
|
|
|
154,863 |
|
|
|
737,085 |
|
|
|
332,955 |
|
Income tax payable |
|
7 |
|
|
164,499 |
|
|
|
54,491 |
|
|
|
707,346 |
|
|
|
117,156 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
|
|
406,339 |
|
|
|
345,812 |
|
|
|
1,747,259 |
|
|
|
743,496 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
|
|
446,085 |
|
|
|
382,065 |
|
|
|
1,918,166 |
|
|
|
821,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity and liabilities |
|
|
|
|
925,318 |
|
|
|
814,165 |
|
|
|
3,978,868 |
|
|
|
1,750,455 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes (1 to 26) are an integral part of these financial statements.
S-51
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, |
|
|
|
|
2010 |
|
2009 |
|
2008 |
|
2010 |
|
2009 |
|
2008 |
|
|
Note |
|
U.S. Dollars |
|
Bolivars |
Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of crude oil |
|
|
|
|
604,173 |
|
|
|
451,473 |
|
|
|
458,113 |
|
|
|
2,597,945 |
|
|
|
970,667 |
|
|
|
984,943 |
|
Sales of gas |
|
|
|
|
3,413 |
|
|
|
6,778 |
|
|
|
16,506 |
|
|
|
14,676 |
|
|
|
14,573 |
|
|
|
35,488 |
|
|
|
|
|
|
|
|
|
|
21 |
|
|
607,586 |
|
|
|
458,251 |
|
|
|
474,619 |
|
|
|
2,612,621 |
|
|
|
985,240 |
|
|
|
1,020,431 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operational expenses |
|
17 |
|
|
(53,659 |
) |
|
|
(48,311 |
) |
|
|
(77,609 |
) |
|
|
(230,734 |
) |
|
|
(103,869 |
) |
|
|
(166,859 |
) |
Depletion, depreciation and amortization |
|
8 |
|
|
(39,167 |
) |
|
|
(32,571 |
) |
|
|
(24,778 |
) |
|
|
(168,418 |
) |
|
|
(70,028 |
) |
|
|
(53,273 |
) |
Sales, general and administrative expenses |
|
|
|
|
(16,213 |
) |
|
|
(10,841 |
) |
|
|
(6,705 |
) |
|
|
(69,716 |
) |
|
|
(23,308 |
) |
|
|
(14,416 |
) |
Royalties |
|
7 (g) |
|
|
(218,819 |
) |
|
|
(157,681 |
) |
|
|
(225,167 |
) |
|
|
(940,922 |
) |
|
|
(339,014 |
) |
|
|
(484,109 |
) |
|
|
|
|
|
|
|
Operating income |
|
|
|
|
279,728 |
|
|
|
208,847 |
|
|
|
140,360 |
|
|
|
1,202,831 |
|
|
|
449,021 |
|
|
|
301,774 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income and expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial income |
|
18 |
|
|
84,448 |
|
|
|
3 |
|
|
|
268 |
|
|
|
363,126 |
|
|
|
7 |
|
|
|
577 |
|
Financial expenses |
|
18 |
|
|
(26,767 |
) |
|
|
(3,439 |
) |
|
|
(2,371 |
) |
|
|
(115,098 |
) |
|
|
(7,394 |
) |
|
|
(5,098 |
) |
Other income |
|
|
|
|
3,179 |
|
|
|
|
|
|
|
|
|
|
|
13,669 |
|
|
|
|
|
|
|
|
|
Other expense |
|
|
|
|
(557 |
) |
|
|
(181 |
) |
|
|
(226 |
) |
|
|
(2,395 |
) |
|
|
(389 |
) |
|
|
(486 |
) |
|
|
|
|
|
|
|
Profit before tax |
|
|
|
|
340,031 |
|
|
|
205,230 |
|
|
|
138,031 |
|
|
|
1,462,133 |
|
|
|
441,245 |
|
|
|
296,767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense |
|
7 - (a) |
|
|
(262,348 |
) |
|
|
(61,946 |
) |
|
|
(16,814 |
) |
|
|
(1,128,096 |
) |
|
|
(133,184 |
) |
|
|
(36,150 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net profit |
|
|
|
|
77,683 |
|
|
|
143,284 |
|
|
|
121,217 |
|
|
|
334,037 |
|
|
|
308,061 |
|
|
|
260,617 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Translation adjustment |
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
929,015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income for the year |
|
|
|
|
77,683 |
|
|
|
143,284 |
|
|
|
121,217 |
|
|
|
1,263,052 |
|
|
|
308,061 |
|
|
|
260,617 |
|
|
|
|
|
|
|
|
The accompanying notes (1 to 26) are an integral part of these financial statements
S-52
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of Changes in Equity
Years ended December 31, 2010 and 2009
(Expressed In Thousands of U.S. Dollar)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Legal reserve |
|
|
|
|
|
|
|
|
|
|
Capital |
|
Shareholder |
|
Share |
|
and other |
|
|
|
|
|
|
Note |
|
stock |
|
contribution |
|
premium |
|
reserves |
|
Distributable |
|
Total |
Balances at December 31, 2007 |
|
|
|
|
|
|
465 |
|
|
|
6,512 |
|
|
|
212,451 |
|
|
|
47 |
|
|
|
181,325 |
|
|
|
400,800 |
|
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 |
|
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 |
|
Total comprehensive income for the year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
77,683 |
|
|
|
77,683 |
|
Transfer from other reserves |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(82,549 |
) |
|
|
82,549 |
|
|
|
|
|
Dividends declared |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(30,550 |
) |
|
|
(30,550 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2010 |
|
|
|
|
|
|
6,977 |
|
|
|
|
|
|
|
212,451 |
|
|
|
59,394 |
|
|
|
200,411 |
|
|
|
479,233 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes (1 to 26) are an integral part of these financial statements
S-53
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Statements of Changes in Equity
Years ended December 31, 2010 and 2009
(Expressed in Thousands of bolivars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Legal reserve |
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
Capital |
|
Shareholder |
|
Share |
|
and other |
|
|
|
|
|
translation |
|
|
|
|
Note |
|
stock |
|
contribution |
|
premium |
|
reserves |
|
Distributable |
|
adjustment |
|
Total |
Balances at December 31, 2007 |
|
|
|
|
|
|
1,000 |
|
|
|
14,000 |
|
|
|
456,770 |
|
|
|
100 |
|
|
|
389,846 |
|
|
|
|
|
|
|
861,716 |
|
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 |
|
Total comprehensive income for the year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
308,061 |
|
|
|
|
|
|
|
308,061 |
|
Appropriation to other reserves |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
303,677 |
|
|
|
(303,677 |
) |
|
|
|
|
|
|
|
|
Dividends declared |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(111,533 |
) |
|
|
|
|
|
|
(111,533 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009 |
|
|
|
|
|
|
15,000 |
|
|
|
|
|
|
|
456,770 |
|
|
|
305,177 |
|
|
|
152,068 |
|
|
|
|
|
|
|
929,015 |
|
Total comprehensive income for the year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
334,037 |
|
|
|
929,015 |
|
|
|
1,263,052 |
|
Transfer from other reserves |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(51,284 |
) |
|
|
51,284 |
|
|
|
|
|
|
|
|
|
Dividends declared |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(131,365 |
) |
|
|
|
|
|
|
(131,365 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2010 |
|
|
|
|
|
|
15,000 |
|
|
|
|
|
|
|
456,770 |
|
|
|
253,893 |
|
|
|
406,024 |
|
|
|
929,015 |
|
|
|
2,060,702 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes (1 to 26) are an integral part of these financial statements
S-54
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, |
|
|
2010 |
|
2009 |
|
2008 |
|
2010 |
|
2009 |
|
2008 |
|
|
U.S. Dollars |
|
Bolivars |
Cash flow from operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net profit |
|
|
77,683 |
|
|
|
143,284 |
|
|
|
121,217 |
|
|
|
334,037 |
|
|
|
308,059 |
|
|
|
260,617 |
|
|
|
|
|
|
Adjustments to reconcile net income to net cash
(used in) provided by operating activities - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
|
40,429 |
|
|
|
33,188 |
|
|
|
25,508 |
|
|
|
173,845 |
|
|
|
71,354 |
|
|
|
54,843 |
|
Income tax expense |
|
|
189,780 |
|
|
|
|
|
|
|
|
|
|
|
816,054 |
|
|
|
|
|
|
|
|
|
Financial expense transferred from related party |
|
|
19,475 |
|
|
|
|
|
|
|
|
|
|
|
83,743 |
|
|
|
|
|
|
|
|
|
Provision for abandonment cost |
|
|
(2,043 |
) |
|
|
(3,603 |
) |
|
|
(10,866 |
) |
|
|
(8,785 |
) |
|
|
(7,746 |
) |
|
|
(23,362 |
) |
Deferred income tax |
|
|
72,568 |
|
|
|
(43,922 |
) |
|
|
(52,560 |
) |
|
|
312,042 |
|
|
|
(94,432 |
) |
|
|
(113,004 |
) |
Financial cost on provision for abandonment cost |
|
|
3,339 |
|
|
|
1,639 |
|
|
|
2,344 |
|
|
|
14,358 |
|
|
|
3,524 |
|
|
|
5,039 |
|
Financial income for variation in the exchange rate |
|
|
(84,439 |
) |
|
|
|
|
|
|
|
|
|
|
(363,088 |
) |
|
|
|
|
|
|
|
|
Tax credit financial cost |
|
|
3,951 |
|
|
|
1,792 |
|
|
|
|
|
|
|
16,989 |
|
|
|
3,853 |
|
|
|
|
|
Revenues from asset disincorporation |
|
|
(2,892 |
) |
|
|
|
|
|
|
|
|
|
|
(12,436 |
) |
|
|
|
|
|
|
|
|
Net changes in operating assets - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(154,936 |
) |
|
|
(113,738 |
) |
|
|
(133,756 |
) |
|
|
(666,225 |
) |
|
|
(244,537 |
) |
|
|
(287,575 |
) |
Material and supplies Inventories |
|
|
3,493 |
|
|
|
(8,923 |
) |
|
|
(10,833 |
) |
|
|
15,020 |
|
|
|
(19,185 |
) |
|
|
(23,291 |
) |
Prepaid expenses and other assets |
|
|
152 |
|
|
|
20,918 |
|
|
|
(20,604 |
) |
|
|
654 |
|
|
|
44,974 |
|
|
|
(44,299 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net changes in operating liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
|
(38,033 |
) |
|
|
16,228 |
|
|
|
321,555 |
|
|
|
(163,542 |
) |
|
|
34,890 |
|
|
|
691,343 |
|
Income taxes paid |
|
|
(52,526 |
) |
|
|
54,491 |
|
|
|
(153,037 |
) |
|
|
(225,863 |
) |
|
|
117,157 |
|
|
|
(329,030 |
) |
Accruals and other liabilities |
|
|
69,775 |
|
|
|
(3,480 |
) |
|
|
132,090 |
|
|
|
300,035 |
|
|
|
(7,482 |
) |
|
|
283,994 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total adjustments |
|
|
68,093 |
|
|
|
(45,410 |
) |
|
|
99,841 |
|
|
|
292,801 |
|
|
|
(97,631 |
) |
|
|
214,658 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
145,776 |
|
|
|
97,874 |
|
|
|
221,058 |
|
|
|
626,838 |
|
|
|
210,430 |
|
|
|
475,275 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of property, plant and equipment |
|
|
(101,799 |
) |
|
|
(81,425 |
) |
|
|
(39,347 |
) |
|
|
(437,736 |
) |
|
|
(175,064 |
) |
|
|
(84,596 |
) |
Disincorporation of assets |
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(101,778 |
) |
|
|
(81,425 |
) |
|
|
(39,347 |
) |
|
|
(437,645 |
) |
|
|
(175,064 |
) |
|
|
(84,596 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paid dividends |
|
|
(43,346 |
) |
|
|
(20,750 |
) |
|
|
(181,325 |
) |
|
|
(186,388 |
) |
|
|
(44,613 |
) |
|
|
(389,849 |
) |
|
|
|
|
|
Net cash used in financing activities |
|
|
(43,346 |
) |
|
|
(20,750 |
) |
|
|
(181,325 |
) |
|
|
(186,388 |
) |
|
|
(44,613 |
) |
|
|
(389,849 |
) |
|
|
|
|
|
Effect for variation in the exchange rate in cash and cash equivalents |
|
|
(249 |
) |
|
|
|
|
|
|
|
|
|
|
(1,071 |
) |
|
|
|
|
|
|
|
|
Effect for variation in the exchange rate in the foreign currency |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash increase |
|
|
403 |
|
|
|
(4,301 |
) |
|
|
386 |
|
|
|
8,317 |
|
|
|
(9,247 |
) |
|
|
830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at the beginning of the period |
|
|
3,062 |
|
|
|
7,363 |
|
|
|
6,977 |
|
|
|
6,583 |
|
|
|
15,830 |
|
|
|
15,000 |
|
|
|
|
|
|
Cash and cash equivalents at the end of the period |
|
|
3,465 |
|
|
|
3,062 |
|
|
|
7,363 |
|
|
|
14,900 |
|
|
|
6,583 |
|
|
|
15,830 |
|
|
|
|
|
|
The accompanying notes (1 to 26) are an integral part of these financial statements
S-55
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
Petrodelta. S.A. was incorporated and is domiciled in the Bolivarian Republic of Venezuela
Venezuela. Its main offices are located at Avenida Alirio Ugarte Pelayo, Edificio Harvest
Vinccler, Ala Norte, Planta Baja in Maturín, Monagas State. Its legal address is: Avenida
Veracruz con Calle Cali, Urbanización Las Mercedes, Edificio Pawa, Piso 5, Caracas, Distrito
Capital. |
|
|
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. |
|
|
On March 10, 2011, 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. The financial statements as of December 31, 2009 were approved by the Shareholders
of the Company on February 26, 2010. |
|
|
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 turn, billed the Company. These costs were recognized in the statements of
comprehensive |
S-56
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
income 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 reach to an agreement. 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, 2010 and 2009, the Company has operated with employees
assigned by its shareholders or their related companies since it has no direct employees. At
December 31, 2010 and 2009, the Company had 432 and 356 employees, respectively, assigned by
its shareholders or their related companies. |
|
|
During the year ended December 31, the Company drilled 16 (2010) and 18 (2009) development
wells, produced approximately 8.6 (2010) and 7.8 (2009) million barrels of oil and sold 2.2
(2010) and 4.4 (2009) billion cubic feet of natural gas. |
|
|
|
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, as per the bylaws and
common rights norms applicable. |
|
|
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 the final selling price. Company management considers that, other than associated
gas, no hydrocarbon derivatives are consumed. |
S-57
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
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, 2010 and 2009 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, 2009 have been prepared and are
presented for purposes of comparison with the financial statements
for the year ended December 31, 2010. |
|
|
|
|
The statements of comprehensive income, changes in equity accounts and of cash flows for
the year ended December 31, 2008 and their respective disclosures, are presented for
purposes of additional information required by the Corporate Management of PDVSA. |
|
|
(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 (U.S. Dollar or US$) and bolivars
(bolivar or Bs.). The Companys functional currency is the U.S. Dollar, 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 U.S. Dollars. |
|
|
|
|
The financial statements in bolivars are presented for statutory purposes. |
|
|
|
|
All financial information presented in U.S. dollars and bolivars has been rounded in
thousands. |
S-58
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
(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. |
|
|
|
|
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 judgment in the application of accounting policies, which
significantly affect financial statement amounts is described in the following notes: |
|
- |
|
Note 8 - depletion, depreciation and amortization |
|
|
- |
|
Note 9 - provision for abandonment costs |
|
|
- |
|
Note 19 - Valuation of financial instruments |
|
|
|
Information on areas of uncertainty affecting managements estimates which significantly
affect financial statement amounts in future periods are described in the following
notes: |
|
- |
|
Note 3 -t- 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 7 -f- deferred income tax |
|
|
- |
|
Note 20 - 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 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 |
S-59
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
position. Exchange gains or losses on monetary items in currencies other than the U.S.
Dollar are presented in the statements of comprehensive income. 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. All other nonmonetary items denominated in foreign currency
and measured at historical cost are converted at the exchange rate at the date of the
transaction. |
|
(b) |
|
Translation to the presentation currency |
|
|
|
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. |
|
|
|
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 the date of such statement. |
|
- |
|
Income and expenses in the statements of comprehensive income at the
exchange rate at the date of transaction. |
|
- |
|
All exchange gain and losses generated as a result of the retranslation just
described are recognized in the statements of comprehensive income as other
comprehensive income and accumulated as a separate component of equity. |
|
- |
|
Equity accounts are translated at the exchange rate in effect at the date
of each related transaction, except for retained earnings which are translated at
the weighted-average rate for the relevant year. |
|
(c) |
|
Financial instruments |
|
|
|
Non-derivative financial instruments consist of cash and cash equivalents, recoverable
tax credits, accounts receivable, accounts payable to suppliers, provisions and other
liabilities (see Note 3-i and Note 5). |
|
|
|
|
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. |
S-60
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
During the years ended December 31, 2010 and 2009, the Company conducted no transactions
with derivative instruments. |
|
|
|
|
The balance of assets and liabilities are offset and the net amount
shown in the statement of financial position when and only when, the Company has a legal right to offset amounts and
intends to settle on a net basis or to realize the asset and settle the liability simultaneously. |
|
|
(d) |
|
Property, plant and equipment |
|
|
|
|
Recognition and measurement |
|
|
|
|
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, taking into
consideration what is established under IFRS 6 Exploration For and Evaluation of Mineral
Rights in relation to accounting for exploration and evaluation expenditures, including
the recognition of exploration and evaluation assets. 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. |
|
|
|
|
The cost of property, plant and equipment includes disbursements that are directly
attributable to the acquisition of such assets and the amounts associated with asset
retirement obligations (See Note 8). |
|
|
|
|
Finance costs of projects requiring major investments, and costs incurred for specific
financing of projects, are recognized as part of property, plant and equipment, when can
be directly related to the construction or acquisition of a capable asset. Capitalization
of such costs is suspended during periods when the development of construction activity
is interrupted, and capitalization ends when necessary activities are substantially
complete for the utilization of a capable asset. An asset is considered capable, when it
requires a period of substantially time necessary before is ready for use. |
|
|
|
|
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. |
|
|
|
|
Gain or loss generated by the sale, retirement or disposal of an asset from property,
plant and equipment, is determined by the difference between the amount received from
sale, retirement or disposal, if any, and the net carrying value in the books of the
Company, and is recognized as other income or expense, net in the statements of
comprehensive income. |
S-61
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
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. |
|
|
|
|
Subsequent costs |
|
|
|
|
Costs for major maintenance or general repairs, as well as replacement of significant
parts or property, plant and equipment are capitalized when identified as a separate
component of the asset to which such maintenance, repair and replacement 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. |
|
|
|
|
Depletion, depreciation and amortization |
|
|
|
|
Depletion, 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 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
statements of comprehensive income. |
|
|
|
|
When parts of a property, plant and equipment asset have different useful lives, they are
recorded separately as a significant component of that asset. |
|
|
|
|
Depreciation methods and average useful lives of property, plant and equipment are
reviewed annually. Land is not depreciated. |
|
|
(e) |
|
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. |
|
|
(f) |
|
Inventories |
|
|
|
|
Inventories are stated at the lower of cost and net realizable value. Net realizable
value is the estimated selling price in the normal course of business, less costs to
complete and estimated selling costs. |
|
|
|
|
The cost of inventories of crude oil and its products is determined using the average
cost method. |
S-62
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
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. |
|
|
(g) |
|
Accounts receivable |
|
|
|
|
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, 2010 and 2009, the Company does not expect to incur
losses on uncollectible accounts and, therefore, has not set aside a provision in this
connection other than those described in the hydrocarbon purchase sale agreement with
PDVSA Petróleo. |
|
|
(h) |
|
Cash and cash equivalent |
|
|
|
|
Petrodelta, S.A. considers as cash and cash equivalents time deposits and all other cash
placements with original maturities of less than three months and available on a current
basis which at December 31, 2010 and 2009 amounted to approximately US$3.465 thousands
and US$3.062 thousands (Bs.14.901 thousands and Bs.6.582 thousands), respectively. |
|
|
(i) |
|
Impairment in the value of long-lived assets |
|
|
|
|
Non-derivative financial assets |
|
|
|
|
The Company asses the carrying amount of its financial assets at each reporting date to
determine whether there is any objective evidence of impairment. 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. |
|
|
|
|
Objective evidence that financial assets are impaired can include default or lack of
compliance from debtors, restructuring a balance due to the Company in terms that may not
be considered in other circumstances, signs that a debtor or issuer declares bankrupt or
the instrument no longer has a market. |
|
|
|
|
|
Significant financial assets are reviewed individually to determine their impairment.
The remaining financial assets with similar credit risk characteristics are evaluated as
a group. |
|
|
|
|
In evaluating impairment, the Company uses historical trends of the probability of
defaults, timing of recoveries and the amount of loss incurred, adjusted for managements
judgment as to whether current economic and credit conditions are such that the actual
losses are likely to be greater or less than the suggested by historical trends. |
|
|
|
|
An impairment loss related to a financial asset is calculated as the difference between
its carrying amount and the present value of the estimated future cash flows, discounted
at the effective interest rate. Impairment losses are recognized in the statements of
|
S-63
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
comprehensive income. An impairment loss is reversed if the amount can be related
objectively to an event occurring after the impairment loss was recognized. |
|
|
|
|
Non-financial assets |
|
|
|
The carrying amounts of non-financial assets, excluding inventory and deferred tax, are
reviewed at each reporting date of the statement of financial position to determine
whether evidence of impairment exists. If any such indication exists, then the
recoverable value of the asset is estimated. |
|
|
|
The recoverable value of an asset o cash-generating unit is the greater between its
carrying value and its fair value, less direct selling expenses. When determining the
carrying value, expected future net cash flows are discounted using present value
techniques, using a discount rate before tax that reflects current market conditions over
the time value of money and specific risks that the asset may bear. 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. A cash-generating unit is the assets grouped at the lowest levels for which there
are separately identifiable cash flows. When evaluating impairment, goodwill acquired
during business combinations is allocated among cash-generating units that are expected
to benefit from combination synergies. |
|
|
|
An impairment loss is recognized when the carrying amount of an asset or its
cash-generating unit exceeds its recoverable amount. Impairment loss is recognized in the
statements of comprehensive income for the year and the asset cost is shown net of this
impairment charge. |
|
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Impairment losses can be reversed only if the reversion is related to a change in the
estimates used after the impairment loss was recognized. This reversion shall not exceed
the book value of assets net of depreciation or amortization as if the impairment had
never been recognized. |
|
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|
Income tax expense comprises current and deferred income tax. Income tax expense is
recognized in the results for each year, except to the extent that it relates to items
that should be directly recognized in the other comprehensive income. |
|
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|
Current income tax is the expected tax payable based on the taxable income for the year,
using the methodology established by current laws and tax rates at the reporting date and
any adjustment to taxes payable from previous years. Current income tax payable also
includes fiscal responsibility derived from dividends declared. |
|
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|
Deferred income tax is recognized using the balance sheet method. Deferred tax assets and
liabilities are recognized by the timing differences that exist between assets and
liabilities values presented in the statement of financial position and its corresponding
fiscal value, as well as operating losses and tax credit carryforwards. The value of
deferred tax assets and liabilities is determined based on tax rates expected to be
applicable to taxable income for |
S-64
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
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|
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. |
|
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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. |
|
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A provision is recognized 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. When the
effect of the time value of money is significant, the provision is determined by applying
a discount rate associated with the estimated payment terms, if the terms can be
estimated reliably as well as the risk associated with those obligations. |
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Environmental issues |
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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 current or future revenues are expensed or
capitalized as appropriate. Expenditures for past operations that do not contribute to
generating current or future income are charged to expense. Recognition of these
provisions coincides with the identification of an obligation for environmental
remediation where the Company has sufficient information to determine a fair estimate of
the respective cost. Subsequent adjustments to estimates, if necessary, are made upon
obtaining additional information. |
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Asset retirement |
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Obligations associated with the retirement of long-lived assets are recognized at fair
value on the date on which such obligation is incurred, based on future discounted cash
flows. The fair values are determined based on current regulations and technologies. |
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Changes in fair values of obligations are added to or deducted from the cost of the
respective asset. The adjusted depreciation amount of the asset is depreciated over its
remaining useful life. Therefore, once its useful life has ended all subsequent changes
in the fair value of the obligation are recognized in the statements of comprehensive
income. The increase in the obligation for each year is recognized in the results of
operations as financial expenses. |
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Litigation and other claims |
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Provision for litigations and claims are recognized in the event that legal action has
been lodged, government investigations have been initiated and other legal actions are
outstanding or subject to be filed in the future against the Company, as a result of past |
S-65
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
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events, which may result in a probable outflow of economic benefits to pay for that
obligation which may be reliably estimated. The Company has no legal suits or claims that
need to be recorded or disclosed at the date of the statements of financial position. |
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Damages to Land |
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Liabilities caused by damage to land resulting from the regular activities carried out by
the Company to access the different existing areas or new, for which third-party property
or economic activity can be or are affected causing the need to compensate the economic
effects caused Are recorded when known the existence of the
liability. As a result of the expansion of the activities in 2010, the Company caused damages to
third parties and currently is in negotiation process with different owners. Management
believes that potential liabilities reached U.S. $2,093 thousands (Bs.9.000 miles) and
were included in the results of 2010. |
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(l) |
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Revenue recognition |
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Income from sales of crude oil and gas, are measured at fair value for the cash receipts
or amounts to be received, net of commercial discounts and royalties on volumes transferred on
behalf of the Republic of Venezuela, and is recorded in the statements 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. |
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(m) |
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Royalties, extraction taxes and other taxes |
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Royalties, extraction taxes and other related taxes are calculated
according to the provisions of the Hydrocarbons Law and other laws regulating the oil industry
(see Note 1 and 7) and are recognized in the statements of comprehensive income when caused. |
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(n) |
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Capital stock |
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Common shares are classified as equity. For the years ended December 31, 2010 and 2009,
the Company has no preferred shares (See Note 14). |
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(o) |
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Share premium |
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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). |
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(p) |
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Legal reserve |
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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).
|
S-66
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
(q) |
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Other equity reserves |
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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. |
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(r) |
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Dividend distribution |
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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 of the Company and the corresponding shareholders minute is filed before the
Register of Commerce. |
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(s) |
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Accounting estimates requiring a high degree of judgment |
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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. |
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Below is a summary of the most significant accounting estimates made by the Company: |
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Estimates of oil reserves |
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|
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 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. |
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|
Reserves studies of crude oil and gas assigned to the Company has been updated as of
November 30, 2010 by the superintendence of reservoir of the Company who possesses
adequate technological elements necessary to determine reserves, and its impact in the
statements of comprehensive income is being reflected as of December 31, 2010. |
S-67
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
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Assessment of impairment in the value of property, plant and equipment |
|
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|
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, 2010 and 2009, the Company has not identified impairment in the
carrying value of property, plant and equipment as a result of these estimates. |
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Abandonment cost calculation |
|
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|
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). |
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(t) |
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Related party transactions |
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|
The Company does not disclose, as part of balances and transactions with related
companies (See Note 21), 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. |
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(u) |
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Accrual for employee benefits |
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|
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
to 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: |
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Termination benefits |
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|
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 (See Note 22). 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. |
S-68
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
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Profit sharing and bonuses |
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|
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. |
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|
During the years ended December 31, 2010 and 2009, the Company has not had direct
employees and, therefore, has not recorded liabilities derived from these labor-related
benefits except for the payroll related cost monthly billed to the Company by PDVSA
Petróleos S.A.. |
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Retirement Plan |
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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. |
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|
Improvements made to the plans benefits, in connection with past service cost, are
expensed in the statements of comprehensive income 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 statements of comprehensive income. |
|
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|
The amount accounted for as income or expense is 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 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. |
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|
Post-retirement benefits other than retirement |
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|
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. |
S-69
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
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|
Past service cost and the actuarial income or loss are recorded by using the method set
out in the retirement plan per the contract. |
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|
The provision for this concept is provided by PDVSA which is based on actuary studies. |
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(v) |
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New accounting standards not yet adopted |
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|
Certain new standards, amendments and interpretations to existing standards were not
effective for the year ended December 31, 2010 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 December 2010, the IASB published amendments to IAS 12 Income Taxes
effective for accounting periods beginning on or after January 1, 2012. The
amendments set out in Deferred Tax: Recovery of Underlying Assets, provides a
practical solution to the problem by introducing a presumption that recovery of the
carrying amount will, normally be through sale. As a result of the amendments,
SIC-21 Income TaxesRecovery of Revalued Non-Depreciable Assets would no longer
apply to investment properties carried at fair value. The amendments also
incorporate into IAS 12 the remaining guidance previously contained in SIC-21,
which is accordingly withdrawn. |
|
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- |
|
In October 2010, the IASB published amendments to IFRS 7 Financial
Instruments Disclosure effective for accounting periods beginning on or after July
1, 2011. The amendments will allow users of financial statements to improve their
understanding of transfer transactions of financial assets (for example,
securitizations), including understanding the possible effects of any risks that may
remain with the entity that transferred the assets. The amendments also require
additional disclosures if a disproportionate amount of transfer transactions are
undertaken around the end of a reporting period. |
|
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- |
|
In May 2010, the IASB published improvements to International Financial
Reporting Standards effective from January 1, 2011. The improvements consist of a
mixture of substantive changes and clarifications in the following standards and
interpretations considered most important for the Company: IFRS 7 Financial
Instruments Disclosure; IAS 1 Presentation of Financial Statements and IAS 27
Consolidated and Separate Financial Statements. |
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- |
|
In November 2009, the IASB published amendments is to IFRIC 14 Prepayments of
a Minimum Funding Requirement, which has an effective date for annual periods
beginning on or after January 1, 2011 and which itself is an interpretation of IAS
19 Employee Benefits. The amendment applies in the limited circumstances when an
entity is subject to minimum funding requirements and makes an early payment of
contributions to cover those requirements. The amendment permits such an entity to
treat the benefit of such an early payment as an asset. |
S-70
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
- |
|
In November 2009, the IASB published an amendment to IAS 24 Related Party
Disclosures which is effective for annual periods beginning on or after January 1,
2011. IAS 24 was revised in 2009 by: (a) simplifying the definition of a related
party, clarifying its intended meaning and eliminating inconsistencies from the
definition and by (b) providing a partial exemption from the disclosure requirements
for government-related entities. |
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- |
|
In November 2009, the IASB issued IFRS 9 Financial Instruments, effective for
annual periods beginning on or after January 1, 2013, with earlier application
permitted. IFRS 9 replaces those parts of IAS 39 relating to the classification and
measurement of financial assets. Key features are as follows: |
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Financial assets are required to be classified into two measurement
categories: those to be measured subsequently at fair value, and those to
be measured subsequently at amortized cost. The decision is to be made at
initial recognition. The classification depends on the entitys business
model for managing its financial instruments and the contractual cash flow
characteristics of the instrument. |
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An instrument is subsequently measured at amortized cost only if it is a
debt instrument and both (i) the objective of the entitys business model
is to hold the asset to collect the contractual cash flows, and (ii) the
assets contractual cash flows represent only payments of principal and
interest (that is, it has only basic loan features). All other debt
instruments are to be measured at fair value through profit or loss. |
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|
All equity instruments are to be measured subsequently at fair value.
Equity instruments that are held for trading will be measured at fair value
through profit or loss. For all other equity investments, an irrevocable
election can be made at initial recognition, to recognize unrealized and
realized fair value gains and losses through other comprehensive income
rather than profit or loss. There is to be no recycling of fair value gains
and losses to profit or loss. This election may be made on an instrument-by
instrument basis. Dividends are to be presented in profit or loss, as long
as they represent a return on investment. |
|
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|
The Company completed the analysis of these standards and determined no significant
effects on its financial statements. |
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(w) |
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Recently adopted accounting pronouncements |
|
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|
The following standards and interpretations became effective during 2010: |
|
- |
|
In November 2009, the International Financial Reporting Interpretations
Committee (IFRIC) issued IFRIC 19 Extinguishing Financial Liabilities with Equity
Instruments effective from July 1, 2010 to provide guidance on how to account for
the extinguishment of a financial liability by the issue of equity instruments.
These |
S-71
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
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|
transactions are often referred to as debt for equity swaps. IFRIC 19 clarifies the
requirements of International Financial Reporting Standards (IFRSs) when an entity
renegotiates the terms of a financial liability with its creditor and the creditor agrees
to accept the entitys shares or other equity instruments to settle the financial
liability fully or partially. IFRIC 19 clarifies that: |
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|
the entitys equity instruments issued to a creditor are part of the
consideration paid to extinguish the financial liability. |
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|
the equity instruments issued are measured at their fair value. If
their fair value cannot be reliably measured, the equity instruments
should be measured to reflect the fair value of the financial liability
extinguished. |
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|
the difference between the carrying amount of the financial liability
extinguished and the initial measurement amount of the equity
instruments issued is included in the entitys profit or loss for the
period. |
|
- |
|
In June 2009, the IASB issued amendments to IFRS 2 Share-based Payment that
clarify the accounting for group cash-settled share-based payment transactions. The
amendments clarify how an individual subsidiary in a group should account for some
share-based payment arrangements in its own financial statements. In these
arrangements, the subsidiary receives goods or services from employees or suppliers
but its parent or another entity in the group must pay those suppliers. The
amendments clarifies that: |
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|
An entity that receives goods or services in a share-based payment
arrangement must account for those goods or services no matter which
entity in the group settles the transaction, and no matter whether the
transaction is settled in shares or cash. |
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|
In IFRS 2 a group has the same meaning as in IAS 27 Consolidated
and Separate Financial Statements, that is, it includes only a parent
and its subsidiaries. |
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|
The amendments to IFRS 2 also incorporate guidance previously
included in IFRIC 8 Scope of IFRS 2 and IFRIC 11 IFRS 2Group and
Treasury Share Transactions. As a result, the IASB has withdrawn IFRIC
8 and IFRIC 11. |
|
- |
|
In April 2009, the IASB published improvements to International Financial
Reporting Standards. The improvement included amendments to certain existing
standards and interpretations. Amendments to IFRS 2, IAS 38, IFRIC 9 and IFRIC 16 are
effective for annual periods beginning on or after July 1, 2009, and amendments to
IFRS 5, IFRS 8, IAS 1, IAS 7, IAS 17, IAS 36 and IAS 39 are effective for annual
periods beginning on or after January 1, 2010. The improvements consist of a mixture
of substantive changes and clarifications to the following standards and
interpretations: IFRS 2 Share-based Payment clarifying that contributions of
businesses in common control transactions and formation of joint ventures are not
within the scope of IFRS 2; IFRS 5 Non-current Assets held for sale and discounted
operations clarifying disclosure requirements set by this and other standards for
non-current assets (or disposal groups) classified as held for |
S-72
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
sale or discontinued operations; IFRS 8 Operating Segments amending disclosure
requirements for a measure of segment assets; IAS 1 Presentation of Financial
Statements amending regarding non-current/current classification of liabilities
settled by equity instruments; IAS 7 Statement of Cash Flows clarifying that only
expenditures that result in a recognized asset are eligible for classification as
investing activities; IAS 17 Leases clarifying the considerations for classification
of land leases and setting out transition requirements for reclassification of
unexpired leases; IAS 18 Revenue providing additional guidance for determining whether
an entity acts as a principal or an agent; IAS 36 Impairment of Assets clarifying
that a cash generating unit shall not be larger than an operating segment before
aggregation; IAS 38 Intangible Assets amended regarding measurement of fair value of
intangible assets acquired in a business combinations, providing additional guidance
on techniques used in the absence of an active market; IAS 39 Financial Instruments
amended to exclude from its scope certain forward contracts resulting in business
combinations, to clarify the period of reclassifying gains or losses on the hedged
instruments from equity to profit or loss and to provide guidance for circumstances
when prepayment options are closely related to the host contract; IFRIC 9 Reassessment
of Embedded Derivatives clarifying that embedded derivatives in contracts acquired in
common control transactions and formation of joint ventures are not within the scope
of IFRIC 9; and IFRIC 16 Hedges of a Net Investment in a Foreign Operation amended for
removal of the restriction that hedging instruments may not be held by the foreign
operation that itself is being hedged. |
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|
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) |
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|
On January 8, 2010, Official Gazette 39,342 was published containing Foreign Exchange
Agreement No. 14, effective as of January 11, 2010, establishing exchange rates for the
purchase and sale of currency, other than local currency, for legal entities as follows: |
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|
|
Payment in currency, other than local currency, transactions aimed at imports by
the sector of food, health, education, machinery and equipment and science and
technology, as well as payments for the activities of the public sector not related
to petroleum, will be made at an exchange rate of Bs.2.60 per U.S. Dollar; payments
of all other foreign currency sale transactions will be made at an exchange rate of
Bs.4.30 per U.S. Dollar. |
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|
Payment of purchase of currency, other than local currency, obtained: i) by the
public sector, other than those originating from hydrocarbon imports regulated by
Foreign Exchange Agreement 9, will be made at an exchange rate of Bs.2.5935 per
U.S. Dollar; and ii) the remaining purchases of foreign currency will be made at an
exchange rate of Bs.4.2893 per U.S. Dollar. |
S-73
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
Payment of currency purchase, other than local currency, transactions,
originating from export of hydrocarbons, regulated under Foreign Exchange Agreement
No. 9, will be made at an exchange rate of Bs.4.2893 and Bs.2.5935 per U.S. Dollar,
pursuant to the provisions of the BCV, and proportions determined by that entity
for payment of sale transactions. An exchange rate of Bs.2.5935, per U.S. Dollar
will be applicable to at least 30% of those currencies purchase transactions, other
than the local currency (see note 18). |
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|
The previous paragraph is applicable to mix companies affiliates of PDVSA. |
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|
In addition, this Agreement enables legal entities, other than PDVSA, in the area of
exports of goods and services to withhold and manage up to thirty percent (30%) of income
in foreign currency from the exports made; this percentage will be used to cover expenses
from export activities other than long-term debt. This Agreement also established that
purchase and sale transactions of foreign currency with payment requested to the BCV
before the effective date will be paid at an exchange rate of Bs.2.14 per U.S. Dollar and
Bs.2.15 per U.S. Dollar, respectively, as established in Foreign Exchange Agreement No. 2,
dated March 1, 2005. |
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In May 2010, the Venezuelan Government established the Sistema de Transacciones con
Títulos en Moneda Extranjera (SITME) for exchanging Bolivars. SITMEs purpose is to
assist companies and individuals requiring foreign currency (U.S. Dollars) for the import
of goods and services into Venezuela. SITME may also be used for buying or selling of
Venezuelas bonds. The Company does not have, and has not had, any Bolivars pending
government approval for settlement for U.S. Dollars at the official exchange rate or the
SITME exchange rate. |
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|
On December 30, 2010, Foreign Exchange Agreement No. 14, effective as of January 1, 2011,
was published in Official Gazette 39,584. This Agreement sets the exchange rate at
Bs.4.2893 per U.S. Dollar for purchases and Bs.4,30 per U.S. Dollar for sales. This
resolution supersedes Foreign Exchange Agreement No. 14, dated January 8, 2010, published
in Official Gazette of the Bolivarian Republic of Venezuela 39,342, dated January 8, 2010;
as well as Foreign Exchange Agreements No. 15, No. 16, No. 17, and any other provision
that may come into conflict with this Foreign Exchange Agreement. |
|
|
|
|
The pronouncement of the Exchange Agreement No. 14 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 Bolivarian Republic of Venezuela. |
|
|
|
|
On November 21, 2005, the Ministry of Finance and BCV published Exchange Agreement
No. 9, in the Official Gazette No. 38,318, later revised on March 22, 2007 and published
in the Official Gazette No. 38.650, 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 |
S-74
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
currency flows generated by its activities, asset and liability positions in foreign
currency, and payments made by PDVSA abroad. |
(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 valuation methods. When applicable, additional information on fair value
estimates of assets and liabilities is disclosed in the specific notes to the statements of
financial position. |
|
|
|
Non-derivative current financial assets and liabilities |
|
|
|
The carrying amounts of financial assets and liabilities included in prepaid expenses and
other assets, accounts receivable, cash and cash equivalents and accounts payable to
suppliers approximate their fair value because of the short-term maturities of these
instruments. |
|
|
|
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 (see note 7-k). |
|
|
|
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. |
|
|
|
Derivative financial assets and liabilities |
|
|
|
The fair value of derivative financial instruments is based on the amount that the Company
will receive or pay to terminate the agreements, taking into account current commodity
prices, interest rate and the current creditworthiness of the parties involved. During the
years ended December 31, 2010 and 2009, the Company did not engage in operations involving
derivative financial instruments. |
S-75
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
Non-derivative financial obligations |
|
|
|
The fair value of non-derivative financial obligations, which is determined for disclosure
purposes, is calculated based on information provided by financial institutions and the
present value of future principal and interest cash flows, discounted at the market interest
rate at the reporting date, based on the inherent risk of those obligations. |
(6) |
|
Financial Risk Management |
|
|
Local and international conditions, such as 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, 2010 and 2009, 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 |
|
|
|
Market risk is the risk that changes in market prices, including foreign exchange rates,
interest rates or sales prices, will affect the Companys income or the value of its
financial instruments. The Companys general risk management focuses on the uncertainty
surrounding financial markets and seeks to minimize the potential adverse effects on the
Companys performance. |
|
|
|
The Company is exposed to risks stemming from changes in the sale price of hydrocarbons,
which depend on external market factors. At December 31, 2010 and 2009, 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, 2010 and 2009, the Company has no mechanisms in place to
protect against exposure to hydrocarbon sales price fluctuations. |
|
|
|
In addition, 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. |
|
|
|
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. |
|
|
|
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 |
S-76
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
estimated sales and cash requirements which correspond mainly to operation and maintenance of
production facilities. |
|
|
|
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. |
|
|
Below is a summary of taxes affecting the Companys operations, stated in thousands: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
2010 |
|
2009 |
|
2008 |
|
|
U.S. Dollars |
|
Bolivars |
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated income tax expense |
|
|
189,780 |
|
|
|
105,868 |
|
|
|
69,374 |
|
|
|
816.054 |
|
|
|
227,616 |
|
|
|
149,154 |
|
Deferred income tax (benefit) expense |
|
|
72,568 |
|
|
|
(43,922 |
) |
|
|
(52,560 |
) |
|
|
312,042 |
|
|
|
(94,432 |
) |
|
|
(113,004 |
) |
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
262,348 |
|
|
|
61,946 |
|
|
|
16,814 |
|
|
|
1,128.096 |
|
|
|
133,184 |
|
|
|
36,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
2010 |
|
2009 |
|
2008 |
|
|
U.S. Dollars |
|
Bolivars |
Royalties, extraction tax, surface and windfall taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty on oil production |
|
|
181,252 |
|
|
|
135,442 |
|
|
|
138,311 |
|
|
|
779,384 |
|
|
|
291,200 |
|
|
|
297,369 |
|
Royalty on gas production |
|
|
1,824 |
|
|
|
2,483 |
|
|
|
11,294 |
|
|
|
7,843 |
|
|
|
5,338 |
|
|
|
24,282 |
|
Royalty for the municipalities |
|
|
6,789 |
|
|
|
8,613 |
|
|
|
10,687 |
|
|
|
29,193 |
|
|
|
18,518 |
|
|
|
22,977 |
|
Royalty for endogenous development projects |
|
|
13,578 |
|
|
|
6,935 |
|
|
|
5,343 |
|
|
|
58,385 |
|
|
|
14,910 |
|
|
|
11,487 |
|
Surface tax |
|
|
201 |
|
|
|
1,946 |
|
|
|
1,596 |
|
|
|
865 |
|
|
|
4,184 |
|
|
|
3,431 |
|
Windfall tax |
|
|
14,116 |
|
|
|
882 |
|
|
|
56,377 |
|
|
|
60,697 |
|
|
|
1,896 |
|
|
|
121,211 |
|
Accrual for investments in social project |
|
|
1,059 |
|
|
|
1,380 |
|
|
|
1,559 |
|
|
|
4,555 |
|
|
|
2,968 |
|
|
|
3,352 |
|
|
|
|
|
|
|
|
|
|
|
Total royalties, surface tax and other taxes |
|
|
218,819 |
|
|
|
157,681 |
|
|
|
225,167 |
|
|
|
940,922 |
|
|
|
339,014 |
|
|
|
484,109 |
|
|
|
|
|
|
|
(a) |
|
Income tax |
|
|
|
|
Reconciliation between the nominal and the effective income tax rates for each year is
shown below: |
S-77
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
|
|
|
|
2010 |
|
|
|
|
|
2009 |
|
|
|
|
|
2008 |
|
|
|
|
|
|
Thousands |
|
|
|
|
|
Thousands |
|
|
|
|
|
Thousands |
|
|
|
|
|
|
U.S. |
|
|
|
|
|
|
|
|
|
U.S. |
|
|
|
|
|
|
|
|
|
U.S. |
|
|
|
|
% |
|
Dollars |
|
Bolivars |
|
% |
|
Dollars |
|
Bolivars |
|
% |
|
Dollars |
|
Bolivars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit before tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net profit |
|
|
|
|
|
|
77,683 |
|
|
|
334,037 |
|
|
|
|
|
|
|
143,284 |
|
|
|
308,051 |
|
|
|
|
|
|
|
121,217 |
|
|
|
260,617 |
|
Income tax expense |
|
|
|
|
|
|
262,348 |
|
|
|
1,128,096 |
|
|
|
|
|
|
|
61,946 |
|
|
|
133,184 |
|
|
|
|
|
|
|
16,814 |
|
|
|
36,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit before tax |
|
|
|
|
|
|
340,031 |
|
|
|
1,462,133 |
|
|
|
|
|
|
|
205,230 |
|
|
|
441,245 |
|
|
|
|
|
|
|
138,031 |
|
|
|
296,767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil-sector nominal income tax rate |
|
|
50 |
|
|
|
170,016 |
|
|
|
731,067 |
|
|
|
50 |
|
|
|
102,615 |
|
|
|
220,622 |
|
|
|
50 |
|
|
|
69,016 |
|
|
|
148,383 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax inflation adjustment |
|
|
(5 |
) |
|
|
(16,325 |
) |
|
|
(70,198 |
) |
|
|
(11 |
) |
|
|
(23,096 |
) |
|
|
(49,656 |
) |
|
|
(28 |
) |
|
|
(38,697 |
) |
|
|
(83,199 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax |
|
|
21 |
|
|
|
72,568 |
|
|
|
312,042 |
|
|
|
(21 |
) |
|
|
(43,922 |
) |
|
|
(94,432 |
) |
|
|
(38 |
) |
|
|
(52,560 |
) |
|
|
(113,004 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-deductible provisions and other |
|
|
11 |
|
|
|
36,089 |
|
|
|
155,185 |
|
|
|
13 |
|
|
|
26,349 |
|
|
|
56,650 |
|
|
|
28 |
|
|
|
39,055 |
|
|
|
83,970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective rate |
|
|
77 |
|
|
|
262,348 |
|
|
|
1,128,096 |
|
|
|
30 |
|
|
|
61,946 |
|
|
|
133,184 |
|
|
|
12 |
|
|
|
16,814 |
|
|
|
36,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The increase in the effective tax rate is mainly attributable to:
- |
|
Increase in taxable income as a result of accounting for variation in
the foreign exchange rate that had an impact on the income tax expense
calculated for companies with monetary assets and liabilities
denominated in currencies other than bolivar. |
|
- |
|
Decrease on deferred tax assets as a result of the difference
calculated between the financial base and the taxable base of
property, plant and equipment. |
|
(b) |
|
Tax loss carryforwards |
|
|
|
|
The current Income Tax Law allows tax losses to be carried forward for three years to
offset future taxable income, except losses resulting from the application of the fiscal
inflation adjustment, which can be carried forward one year. |
|
|
(c) |
|
Tax inflation adjustment |
|
|
|
|
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. |
|
|
(d) |
|
Transfer pricing |
|
|
|
|
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. |
S-78
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
(e) |
|
Income tax rate |
|
|
|
|
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. |
|
|
(f) |
|
Deferred income tax |
|
|
|
|
The components of deferred income tax expense at December 31, 2009 and 2010 shown in the
results of each year are as follows (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Movement during the year 2010, |
|
|
|
|
|
|
|
|
|
Net deferred |
|
|
|
|
|
|
|
|
|
|
Income (Loss) |
|
Effect for |
|
|
|
|
|
|
|
|
|
tax at |
|
|
|
|
|
|
|
|
|
|
Recognized |
|
variation in |
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2009 |
|
In results for |
|
the exchange |
|
2010 |
|
2010 |
|
|
Asset (Liability) |
|
the year |
|
rate |
|
Asset (Liability) |
|
(see Note 14) |
|
|
|
|
|
|
|
In U.S. Dollars- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
|
|
|
|
(2,653 |
) |
|
|
4,527 |
|
|
|
1,326 |
|
|
|
3,200 |
|
|
|
|
|
|
|
3,200 |
|
Property, plant and equipment |
|
|
104,556 |
|
|
|
|
|
|
|
(86,372 |
) |
|
|
|
|
|
|
18,184 |
|
|
|
|
|
|
|
18,184 |
|
Inventories |
|
|
4,520 |
|
|
|
|
|
|
|
(5,507 |
) |
|
|
|
|
|
|
|
|
|
|
(987 |
) |
|
|
(987 |
) |
Accruals and other payables |
|
|
34,822 |
|
|
|
|
|
|
|
14,784 |
|
|
|
(11,307 |
) |
|
|
38,821 |
|
|
|
(522 |
) |
|
|
38,299 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
143,898 |
|
|
|
(2,653 |
) |
|
|
(72,568 |
) |
|
|
(9,981 |
) |
|
|
60,205 |
|
|
|
(1,509 |
) |
|
|
58,696 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In Bolivars- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
|
|
|
|
(5,704 |
) |
|
|
19,464 |
|
|
|
|
|
|
|
13,760 |
|
|
|
|
|
|
|
13,760 |
|
Property, plant and equipment |
|
|
224,796 |
|
|
|
|
|
|
|
(371,400 |
) |
|
|
224,795 |
|
|
|
78,191 |
|
|
|
|
|
|
|
78,191 |
|
Inventories |
|
|
9,717 |
|
|
|
|
|
|
|
(23,680 |
) |
|
|
9,719 |
|
|
|
|
|
|
|
(4,244 |
) |
|
|
(4,244 |
) |
Accruals and other payables |
|
|
74,867 |
|
|
|
|
|
|
|
63,572 |
|
|
|
26,247 |
|
|
|
166,930 |
|
|
|
(2,244 |
) |
|
|
164,686 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
309,380 |
|
|
|
(5,704 |
) |
|
|
(312,044 |
) |
|
|
260,761 |
|
|
|
258,881 |
|
|
|
(6,488 |
) |
|
|
252,393 |
|
|
|
|
|
|
|
|
S-79
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred |
|
|
|
|
|
|
Income (Loss) |
|
|
|
|
|
|
|
|
|
tax at |
|
|
|
|
|
|
Recognized |
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
In results for |
|
2009 |
|
2009 |
|
|
Asset |
|
the year |
|
Asset (Liability) |
|
(see Note 14) |
|
|
|
|
|
|
|
|
|
In U.S. Dollars- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
|
|
|
|
(2,653 |
) |
|
|
|
|
|
|
(2,653 |
) |
|
|
(2,653 |
) |
Property, plant and equipment |
|
|
66,004 |
|
|
|
38,552 |
|
|
|
104,556 |
|
|
|
|
|
|
|
104,556 |
|
Inventories |
|
|
5,184 |
|
|
|
(664 |
) |
|
|
4,520 |
|
|
|
|
|
|
|
4,520 |
|
Accruals and other payables |
|
|
26,135 |
|
|
|
8,687 |
|
|
|
34,822 |
|
|
|
|
|
|
|
34,822 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
97,323 |
|
|
|
43,922 |
|
|
|
143,898 |
|
|
|
(2,653 |
) |
|
|
141,245 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In Bolivars- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
|
|
|
|
(5,704 |
) |
|
|
|
|
|
|
(5,704 |
) |
|
|
(5,704 |
) |
Property, plant and equipment |
|
|
141,909 |
|
|
|
82,887 |
|
|
|
224,796 |
|
|
|
|
|
|
|
224,796 |
|
Inventories |
|
|
11,145 |
|
|
|
(1,428 |
) |
|
|
9,717 |
|
|
|
|
|
|
|
9,717 |
|
Accruals and other payables |
|
|
56,190 |
|
|
|
18,678 |
|
|
|
74,868 |
|
|
|
|
|
|
|
74,868 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
209,244 |
|
|
|
94,433 |
|
|
|
309,381 |
|
|
|
(5,704 |
) |
|
|
303,677 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(g) |
|
Royalties |
|
|
|
|
According with the Venezuelan Hydrocarbon Law (LOH), 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 2010, 2009 and 2008 amounted
to US$183,076 thousands, US$137,925 thousands and US$149,605 thousands (Bs.787,227
thousands, Bs.296,538 thousands and Bs.321,651 thousands), respectively, included in the
statements of comprehensive income under Royalties. |
|
|
(h) |
|
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. In determining this tax, the taxpayer may deduct the amount that would have
been paid for royalty, including the additional royalty paid as special advantage. This
tax is |
S-80
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
effective since 2006. The Company incurred no tax in this connection for 2010, 2009 and
2008. |
|
|
(i) |
|
Surface tax |
|
|
|
|
The Venezuelan Hydrocarbon Law establishes 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.
Petrodelta, S.A. incurred in this tax during 2010, 2009 and 2008 for US$201 thousands,
US$1,946 thousands and US$1,596 thousands (Bs.865 thousands, Bs.4,184 thousands and
Bs.3,431 thousands), respectively, included in the statements of comprehensive income
under royalties. |
|
|
(j) |
|
General consumption tax |
|
|
|
|
The Venezuelan Hydrocarbon Law Reform establishes 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 the final selling price. Company management
considers that, other than associated gas, no hydrocarbon derivatives are consumed. |
|
|
(k) |
|
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, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
U.S. Dollars |
|
Bolivars |
Recoverable amounts at the beginning of the year |
|
|
17,922 |
|
|
|
9,604 |
|
|
|
38,532 |
|
|
|
20,649 |
|
Generated during the year |
|
|
8,443 |
|
|
|
10,110 |
|
|
|
36,307 |
|
|
|
21,736 |
|
Adjustment to net realizable value |
|
|
(3,951 |
) |
|
|
(1,792 |
) |
|
|
(16,990 |
) |
|
|
(3,853 |
) |
Effect for variation in the exchange rate |
|
|
(8,961 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recoverable amounts at end of the year |
|
|
13,453 |
|
|
|
17,922 |
|
|
|
57,849 |
|
|
|
38,532 |
|
|
|
|
|
|
Non-current portion of recoverable tax credits |
|
|
8,072 |
|
|
|
10,753 |
|
|
|
34,710 |
|
|
|
23,119 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of recoverable tax credits |
|
|
5,381 |
|
|
|
7,169 |
|
|
|
23,139 |
|
|
|
15,413 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S-81
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
At December 31, 2010 and 2009, the Company adjusted the amount of recoverable tax
credits to the net realizable value applying a discount rate for assets deterioration of
13.098%. 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, 2010 and 2009, the adjustment for US$3,951 thousands and US$1,792 thousands (Bs.16,990
thousands and Bs.3,853 thousands), respectively, is included in the statements of
comprehensive income under the category of financial expenses. |
|
|
(l) |
|
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.
Petrodelta, S.A. incurred in this tax during 2010, 2009 and 2008 for US$14,116 thousands,
US$882 thousands and US$56,377 thousands (Bs.60,697 thousands, Bs.1,896 thousands and
Bs.121,211 thousands), respectively, included in the statements of comprehensive income
under royalties. |
|
|
m) |
|
Other taxes |
|
|
|
|
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 assigned to Petrodelta 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 assigned to Petrodelta 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 2010, 2009 and 2008 for US$20,367 thousands, US$15,548
thousands and US$16,030 thousands (Bs.87,578 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, 2010, 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 |
S-82
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
take place and 2.22% for a special fund to be administered by the Executive branch to
finance endogenous development projects. |
(8) Property, Plant and Equipment, Net
|
|
Property, plant and equipment, net at December 31 comprises the following (in thousands): |
|
|
|
U.S. Dollars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells and |
|
|
|
|
|
Asset |
|
|
|
|
|
|
|
|
production |
|
Construction |
|
retirement |
|
Furniture and |
|
Strategic |
|
|
|
|
facilities |
|
in progress |
|
obligations |
|
equipment |
|
inventories |
|
Total |
Cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008 |
|
|
211,660 |
|
|
|
30,946 |
|
|
|
16,279 |
|
|
|
3,737 |
|
|
|
10,272 |
|
|
|
272,894 |
|
Additions |
|
|
|
|
|
|
77,696 |
|
|
|
|
|
|
|
3,729 |
|
|
|
|
|
|
|
81,425 |
|
Transfers |
|
|
75,730 |
|
|
|
(75,730 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Strategic Inventories |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,842 |
|
|
|
1,842 |
|
Assets retirement obligations |
|
|
|
|
|
|
|
|
|
|
3,603 |
|
|
|
|
|
|
|
|
|
|
|
3,603 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009 |
|
|
287,390 |
|
|
|
32,912 |
|
|
|
19,882 |
|
|
|
7,466 |
|
|
|
12,114 |
|
|
|
359,764 |
|
Additions |
|
|
|
|
|
|
98,650 |
|
|
|
|
|
|
|
3,149 |
|
|
|
|
|
|
|
101,799 |
|
Transfers and capitalization |
|
|
52,807 |
|
|
|
(52,807 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Divestiture of Assets |
|
|
(35 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(35 |
) |
Strategic inventories |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,018 |
) |
|
|
(7,018 |
) |
Asset retirement obligations |
|
|
|
|
|
|
|
|
|
|
2,043 |
|
|
|
|
|
|
|
|
|
|
|
2,043 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2010 |
|
|
340,162 |
|
|
|
78,755 |
|
|
|
21,925 |
|
|
|
10,615 |
|
|
|
5,096 |
|
|
|
456,553 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008 |
|
|
55,721 |
|
|
|
|
|
|
|
3,629 |
|
|
|
1,784 |
|
|
|
|
|
|
|
61,134 |
|
Depreciation and amortization |
|
|
30,198 |
|
|
|
|
|
|
|
1,895 |
|
|
|
1,095 |
|
|
|
|
|
|
|
33,188 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009 |
|
|
85,919 |
|
|
|
|
|
|
|
5,524 |
|
|
|
2,879 |
|
|
|
|
|
|
|
94,322 |
|
Depreciation and amortization |
|
|
36,490 |
|
|
|
|
|
|
|
2,677 |
|
|
|
1,262 |
|
|
|
|
|
|
|
40,429 |
|
Divestiture of Assets |
|
|
(14 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2010 |
|
|
122,395 |
|
|
|
|
|
|
|
8,201 |
|
|
|
4,141 |
|
|
|
|
|
|
|
134,737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net cost at December
31, 2010 |
|
|
217,767 |
|
|
|
78,755 |
|
|
|
13,724 |
|
|
|
6,474 |
|
|
|
5,096 |
|
|
|
321,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net cost at December
31, 2009 |
|
|
201,471 |
|
|
|
32,912 |
|
|
|
14,358 |
|
|
|
4,587 |
|
|
|
12,114 |
|
|
|
265,442 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S-83
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
Bolivars-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells and |
|
|
|
|
|
Asset |
|
Furniture |
|
|
|
|
|
|
production |
|
Construction |
|
retirement |
|
and |
|
Strategic |
|
|
|
|
facilities |
|
in progress |
|
obligations |
|
equipment |
|
inventories |
|
Total |
Cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008 |
|
|
455,069 |
|
|
|
66,534 |
|
|
|
35,000 |
|
|
|
8,035 |
|
|
|
22,085 |
|
|
|
586,723 |
|
Additions |
|
|
|
|
|
|
167,046 |
|
|
|
|
|
|
|
8,017 |
|
|
|
|
|
|
|
175,063 |
|
Transfers |
|
|
162,820 |
|
|
|
(162,820 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Strategic Inventories |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,960 |
|
|
|
3,960 |
|
Assets retirement obligations |
|
|
|
|
|
|
|
|
|
|
7,746 |
|
|
|
|
|
|
|
|
|
|
|
7,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009 |
|
|
617,889 |
|
|
|
70,760 |
|
|
|
42,746 |
|
|
|
16,052 |
|
|
|
26,045 |
|
|
|
773,492 |
|
Additions |
|
|
|
|
|
|
424,196 |
|
|
|
|
|
|
|
13,541 |
|
|
|
|
|
|
|
437,737 |
|
Transfers |
|
|
227,070 |
|
|
|
(227,070 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement |
|
|
(151 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(151 |
) |
Strategic inventories |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(30,177 |
) |
|
|
(30,177 |
) |
Asset retirement obligations |
|
|
|
|
|
|
|
|
|
|
8,785 |
|
|
|
|
|
|
|
|
|
|
|
8,785 |
|
Effect for variation in the
presentation currency |
|
|
617,889 |
|
|
|
70,760 |
|
|
|
42,746 |
|
|
|
16,052 |
|
|
|
26,045 |
|
|
|
773,492 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2010 |
|
|
1,462,697 |
|
|
|
338,495 |
|
|
|
94,277 |
|
|
|
45,645 |
|
|
|
21,913 |
|
|
|
1,963,178 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008 |
|
|
119,800 |
|
|
|
|
|
|
|
7,802 |
|
|
|
3,836 |
|
|
|
|
|
|
|
131,438 |
|
Depreciation and amortization |
|
|
64,926 |
|
|
|
|
|
|
|
4,074 |
|
|
|
2,354 |
|
|
|
|
|
|
|
71,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009 |
|
|
184,726 |
|
|
|
|
|
|
|
11,876 |
|
|
|
6,190 |
|
|
|
|
|
|
|
202,792 |
|
Depreciation and amortization |
|
|
156,907 |
|
|
|
|
|
|
|
11,511 |
|
|
|
5,427 |
|
|
|
|
|
|
|
173,845 |
|
Retirement |
|
|
(60 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(60 |
) |
Effect for variation in the
presentation currency |
|
|
184,726 |
|
|
|
|
|
|
|
11,876 |
|
|
|
6,190 |
|
|
|
|
|
|
|
202,792 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2010 |
|
|
526,299 |
|
|
|
|
|
|
|
35,263 |
|
|
|
17,807 |
|
|
|
|
|
|
|
579,369 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net cost at December 31, 2010 |
|
|
936,398 |
|
|
|
338,495 |
|
|
|
59,014 |
|
|
|
27,838 |
|
|
|
21,913 |
|
|
|
1,383,809 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net cost at December 31, 2009 |
|
|
433,163 |
|
|
|
70,760 |
|
|
|
30,870 |
|
|
|
9,862 |
|
|
|
26,045 |
|
|
|
570,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the years ended December 31, 2010 and 2009, the Company made additions to
production assets and construction in progress for approximately US$101,799 thousands and
US$81,425 thousands (Bs.437,733 thousands and Bs.175,062 thousands), respectively. |
S-84
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
During 2010 and 2009, 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. |
|
|
At December 31, 2010 and 2009, accruals and other payables include US$2,043 thousands and
US$3,603 thousands (Bs.8,782 thousands and Bs.7,745 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, 2010 and 2009, the balance of construction in
progress for investments related to the aforementioned activities amounts to approximately
US$78,755 thousands and US$32,912 (Bs.338,647 thousands and Bs.70,760 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, 2008 |
|
|
19,174 |
|
|
|
41,224 |
|
|
|
|
|
|
|
|
|
|
Change on estimation |
|
|
3,603 |
|
|
|
7,746 |
|
Financial cost |
|
|
1,639 |
|
|
|
3,524 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009 |
|
|
24,416 |
|
|
|
52,494 |
|
|
|
|
|
|
|
|
|
|
Change on estimation |
|
|
2,043 |
|
|
|
8,785 |
|
Financial cost |
|
|
3,339 |
|
|
|
14,358 |
|
Effect for
variation in the presentation currency |
|
|
|
|
|
|
52,494 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010 |
|
|
29,798 |
|
|
|
128,131 |
|
|
|
|
|
|
|
|
|
|
|
|
During 2010, Company management reviewed, based on new information, estimates on
assumptions used for calculating the provision for abandonment costs. |
|
|
At December 31, 2010 and 2009, the variation of the estimation in of the provision for well
abandonment cost of US$2,043 thousands and US$3,603 thousands (Bs.8,782 thousands and Bs.7,745
thousands) is included in the balance of property, plant and equipment (See Note 8). The
Petrodelta, S.A. business plan as of December 31, 2010, contemplates the realization of
hydrocarbons drilling and production activities until the year 2027; therefore, the accrual
for asset retirement obligations was calculated based on the disbursements for this concept
during this period. |
S-85
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
(10) Prepaid Expenses and Other Assets
|
|
Prepaid expenses and other assets comprise the following (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
U.S. Dollars |
|
Bolivars |
Prepaid insurance |
|
|
293 |
|
|
|
458 |
|
|
|
1.260 |
|
|
|
984 |
|
Prepaid services |
|
|
72 |
|
|
|
62 |
|
|
|
310 |
|
|
|
134 |
|
Prepaid rent |
|
|
42 |
|
|
|
39 |
|
|
|
182 |
|
|
|
84 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
407 |
|
|
|
559 |
|
|
|
1,752 |
|
|
|
1,202 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11) Inventories
|
|
A summary of inventories is shown below (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
U.S. Dollars |
|
Bolivars |
Materials and supplies, net |
|
|
30,093 |
|
|
|
33,586 |
|
|
|
129,400 |
|
|
|
72,210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,093 |
|
|
|
33,586 |
|
|
|
129,400 |
|
|
|
72,210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Materials and supplies
classified under other
non-current assets (see
Note 8) |
|
|
5,096 |
|
|
|
12,114 |
|
|
|
21,913 |
|
|
|
26,045 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24,997 |
|
|
|
21,472 |
|
|
|
107,487 |
|
|
|
46,165 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12) Accounts Receivable
|
|
Accounts receivable comprise the following (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
U.S. Dollars |
|
Bolivars |
Related parties (see Note 21) |
|
|
499,313 |
|
|
|
361,137 |
|
|
|
2,147,046 |
|
|
|
776,445 |
|
Current portion of recoverable tax credits
(see Note 7 (k)
and 19) |
|
|
5,381 |
|
|
|
7,169 |
|
|
|
23,139 |
|
|
|
15,413 |
|
Other |
|
|
1,662 |
|
|
|
673 |
|
|
|
7,145 |
|
|
|
1,447 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
506,356 |
|
|
|
368,979 |
|
|
|
2,177,331 |
|
|
|
793,305 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the years ended December 31, 2010 and 2009, the Company offset accounts
receivables and payables between PDVSA and its affiliates, including CVP with the Company in
the amounts approximately of US$281 million and US$419 million, respectively (See Note 21): |
S-86
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
(13) Cash and cash equivalents
|
|
Cash and cash equivalent comprises the following (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
U.S. Dollars |
|
Bolivars |
Cash on hand |
|
|
5 |
|
|
|
3 |
|
|
|
22 |
|
|
|
6 |
|
Cash at banks |
|
|
3,460 |
|
|
|
3,059 |
|
|
|
14,878 |
|
|
|
6,577 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,465 |
|
|
|
3,062 |
|
|
|
14,900 |
|
|
|
6,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14) Equity
|
|
Capital stock |
|
|
|
At December 31, 2010 and 2009, 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$465,000). Capital stock has
been fully subscribed and paid in as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share |
|
|
Type of |
|
Number of |
|
|
|
|
|
|
|
|
|
of |
Shareholders |
|
shares |
|
shares |
|
US$ |
|
Bs. |
|
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 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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. |
S-87
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
During 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 reserves available to pay dividends in the future. Changes in
the deferred tax asset are recorded in appropriation to (transfer from) other reserves. |
|
|
|
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, 2010 and 2009, management has
recorded as equity reserve and amount equal to the balance of deferred tax asset at that date
equivalent to US$58,696 thousands and US$141,245 thousands (Bs.252,394 thousands and
Bs.303,676 thousands) respectively (see Note 7-f), 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, 2010 and 2009, 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,
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 22, 2008, the shareholders resolved to pay dividends of US$181,325 thousands,
equivalent to Bs.389,846 thousands, out of retained earnings as of December 31, 2007. |
|
|
|
On August 28, 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 |
S-88
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
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 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. |
|
|
On August 4, 2010, the shareholders resolved to pay dividends based on retained earnings as
of December 31, 2009 in the amount of US$30,550 thousands (Bs.131,365 thousands). The
dividend approved was paid on October 2010 to HNR Finance for its share in the Company in the
amount of US$12,220 thousands (Bs.52,546 thousands). At December 31, 2010 the portion of the
dividend corresponding to CVP for US$18,330 thousands (Bs.8,819 thousands) is recorded in the statements of
financial position as a dividend payable. |
|
|
In November 2010, the Board of Directors of the Company endorsed a proposal to declare and
distribute dividends for the amount of US$30,550 thousands (Bs.131,365 thousands)
approximately. This dividend is in process of approval by the shareholders of the Company in
order to file the corresponding minute before the Registry of Commerce to proceed to
recognize the liability in the statement of financial position (see Note 24). |
|
|
|
Effect for variation of the exchange rate in the presentation currency |
|
|
The statement of changes in equity expressed in bolivars for the year ended December 31,
2010, includes the following effect originated for the variation of the official exchange
rate when converting the financial statements from U.S. Dollars, (functional currency) to
bolivars (presentation currency), in conformity with IAS 21 (see note 3-b) (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances as of December 31, 2010 |
|
|
|
|
|
|
Bolivars before |
|
Bolivars after |
|
|
|
|
|
|
|
|
translation |
|
translation |
|
Translation |
|
|
U.S. Dollars |
|
adjustment |
|
adjustment |
|
adjustment |
Capital stock |
|
|
6,977 |
|
|
|
15,000 |
|
|
|
30,000 |
|
|
|
15,000 |
|
Shares premium |
|
|
212,451 |
|
|
|
456,770 |
|
|
|
913,540 |
|
|
|
456,770 |
|
Legal reserve and other reserves |
|
|
141,943 |
|
|
|
305,177 |
|
|
|
610,354 |
|
|
|
305,177 |
|
Retained earnings |
|
|
70,729 |
|
|
|
152,068 |
|
|
|
304,136 |
|
|
|
152,068 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
432,100 |
|
|
|
929,015 |
|
|
|
1,858,030 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Translation adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
929,015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At the Board of Director meeting dated 10 March 2011 it was approved the proposal to
submit for consideration to the Shareholders the distribution of the cumulative translation
adjustment account to the different accounts of the equity (See Note 24). |
|
|
Accounts payable comprise the following (in thousands): |
S-89
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
U.S. Dollars |
|
Bolivars |
Trade |
|
|
21,022 |
|
|
|
35,021 |
|
|
|
90,395 |
|
|
|
75,295 |
|
Related parties (see Note 21) |
|
|
31,073 |
|
|
|
70,311 |
|
|
|
133,614 |
|
|
|
151,169 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
52,095 |
|
|
|
105,332 |
|
|
|
224,009 |
|
|
|
226,464 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency and liquidity risk exposure in respect of accounts payable to suppliers
is shown in Note 19. |
(16) |
|
Accruals and Other Payables |
|
|
Accruals and other payables at December 31 comprise the following: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
U.S. Dollars |
|
Bolivars |
Royalties |
|
|
30,842 |
|
|
|
49,277 |
|
|
|
132,621 |
|
|
|
105,945 |
|
Provision for abandonment cost (See Note 9) |
|
|
29,798 |
|
|
|
24,416 |
|
|
|
128,131 |
|
|
|
52,494 |
|
Provision for retirement benefits |
|
|
8,444 |
|
|
|
9,184 |
|
|
|
36,309 |
|
|
|
19,746 |
|
Endogenous and social development |
|
|
3,922 |
|
|
|
5,728 |
|
|
|
16,865 |
|
|
|
12,315 |
|
Antidrug National Fund |
|
|
7,418 |
|
|
|
6,392 |
|
|
|
31,897 |
|
|
|
13,743 |
|
Science and Technology (LOCTI) |
|
|
4,583 |
|
|
|
|
|
|
|
19,707 |
|
|
|
|
|
Other |
|
|
124,645 |
|
|
|
93,466 |
|
|
|
535,974 |
|
|
|
200,952 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
209,652 |
|
|
|
188,463 |
|
|
|
901,504 |
|
|
|
405,195 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less:
Non-current portion of accruals and other payables |
|
|
38,237 |
|
|
|
33,600 |
|
|
|
164,419 |
|
|
|
72,240 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term portion |
|
|
171,415 |
|
|
|
154,863 |
|
|
|
737,085 |
|
|
|
332,955 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2010 and 2009, included as non-current liabilities: a) U.S.$29.798
thousands and US$24,416 thousands, (Bs.128,129 thousands and Bs.52,492 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 major repairs and no information is available to reasonably determine their
retirement date; and b) US$8.439 thousands and US$9,184 thousands, (Bs.36,286 thousands and
Bs.19,746 thousands), as provision for retirement benefits for personnel assigned to the
Company. Retirement benefits were adjusted during 2009 when PDVSA completed an actuarial study
for their employee pension and retirement plan. At December 31, 2010, PDVSA sent a new
statement for the liability |
S-90
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
according to the actuary report. The Company has analyzed
demographic and financial data, considers that it reasonably reflects the liability for such
concept and adjusted the obligation at the date of the statements of financial position. This
pension and retirement plan covers all PDVSA employees and mixed companies payroll. 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, 2010 and 2009, accruals and other payables include the accruals in
respect of drilling services and infrastructure totaling US$61.231 thousands and US$47,892
thousands (Bs.263,293 thousands and Bs.102,968 thousands), respectively. |
|
|
Below are the movements of accruals and other payables during the year 2010 (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at |
|
|
|
|
|
|
|
|
|
Balance at |
|
|
|
|
|
Long- |
|
|
December |
|
|
|
|
|
|
|
|
|
December |
|
Current |
|
term |
|
|
31, 2009 |
|
Increase |
|
Decrease |
|
31, 2010 |
|
portion |
|
portion |
U.S. Dollars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties |
|
|
49,277 |
|
|
|
217,760 |
|
|
|
(236,195 |
) |
|
|
30,842 |
|
|
|
30,842 |
|
|
|
|
|
Provision for abandonment cost
(See Note 9) |
|
|
24,416 |
|
|
|
5,382 |
|
|
|
|
|
|
|
29,798 |
|
|
|
|
|
|
|
29,798 |
|
Provision for retirement benefits |
|
|
9,184 |
|
|
|
3,852 |
|
|
|
(4,592 |
) |
|
|
8,444 |
|
|
|
5 |
|
|
|
8,439 |
|
Endogenous and social development |
|
|
5,728 |
|
|
|
1,059 |
|
|
|
(2,865 |
) |
|
|
3,922 |
|
|
|
3,922 |
|
|
|
|
|
Antidrug National Fund |
|
|
6,392 |
|
|
|
4,222 |
|
|
|
(3,196 |
) |
|
|
7,418 |
|
|
|
7,418 |
|
|
|
|
|
Science and Technology (LOCTI) |
|
|
|
|
|
|
4,583 |
|
|
|
|
|
|
|
4,583 |
|
|
|
4,583 |
|
|
|
|
|
Other |
|
|
93,466 |
|
|
|
51,833 |
|
|
|
(20,654 |
) |
|
|
124,645 |
|
|
|
124,645 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total accruals and other
payables |
|
|
188,463 |
|
|
|
288,691 |
|
|
|
(267,502 |
) |
|
|
209,652 |
|
|
|
171,415 |
|
|
|
38,237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect for |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
variation in |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at |
|
the |
|
|
|
|
|
|
|
|
|
Balance at |
|
|
|
|
|
|
December |
|
presentation |
|
|
|
|
|
|
|
|
|
December |
|
Current |
|
Long-term |
|
|
31, 2009 |
|
currency |
|
Increase |
|
Decrease |
|
31, 2010 |
|
portion |
|
portion |
Bolivars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties |
|
|
105,945 |
|
|
|
105,945 |
|
|
|
936,369 |
|
|
|
(1,015,638 |
) |
|
|
132,621 |
|
|
|
132,621 |
|
|
|
|
|
Provision for abandonment cost
(See Note 9) |
|
|
52,494 |
|
|
|
52,494 |
|
|
|
23,143 |
|
|
|
|
|
|
|
128,131 |
|
|
|
|
|
|
|
128,131 |
|
Provision for retirement benefits |
|
|
19,746 |
|
|
|
19,746 |
|
|
|
16,563 |
|
|
|
(19,746 |
) |
|
|
36,309 |
|
|
|
21 |
|
|
|
36,288 |
|
Endogenous and social development |
|
|
12,315 |
|
|
|
12,315 |
|
|
|
4,554 |
|
|
|
(12,319 |
) |
|
|
16,865 |
|
|
|
16,865 |
|
|
|
|
|
Antidrug National Fund |
|
|
13,743 |
|
|
|
13,743 |
|
|
|
18,154 |
|
|
|
(13,743 |
) |
|
|
31,897 |
|
|
|
31,897 |
|
|
|
|
|
Science and Technology (LOCTI) |
|
|
|
|
|
|
|
|
|
|
19,707 |
|
|
|
|
|
|
|
19,707 |
|
|
|
19,707 |
|
|
|
|
|
Other |
|
|
200,952 |
|
|
|
200,952 |
|
|
|
222,884 |
|
|
|
(88,814 |
) |
|
|
535,974 |
|
|
|
535,974 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total accruals and other payables |
|
|
405,195 |
|
|
|
405,195 |
|
|
|
1,241,374 |
|
|
|
(1,150,260 |
) |
|
|
901,504 |
|
|
|
737,085 |
|
|
|
164,419 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17) |
|
Operational expenses |
|
|
Below is a summary of operational expenses incurred by the Company (in thousands): |
S-91
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
2010 |
|
2009 |
|
2008 |
|
|
U.S. Dollars |
|
Bolivars |
|
|
|
|
|
Crude and gas operations |
|
|
34,120 |
|
|
|
20,340 |
|
|
|
58,940 |
|
|
|
146,716 |
|
|
|
43,731 |
|
|
|
126,721 |
|
Crude transportation |
|
|
12,220 |
|
|
|
11,120 |
|
|
|
8,630 |
|
|
|
52,546 |
|
|
|
23,908 |
|
|
|
18,555 |
|
Others |
|
|
7,319 |
|
|
|
16,851 |
|
|
|
10,039 |
|
|
|
31,472 |
|
|
|
36,230 |
|
|
|
21,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53,659 |
|
|
|
48,311 |
|
|
|
77,609 |
|
|
|
230,734 |
|
|
|
103,869 |
|
|
|
166,859 |
|
|
|
|
|
|
(18) |
|
Financial income and expenses |
|
|
Financial income and expenses comprised the following (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31st, |
|
|
2010 |
|
2009 |
|
2008 |
|
2010 |
|
2009 |
|
2008 |
|
|
U.S. Dollars |
|
Bolivars |
|
|
|
|
|
Financial income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on variation of exchange rate |
|
|
84,439 |
|
|
|
|
|
|
|
|
|
|
|
363,088 |
|
|
|
|
|
|
|
|
|
Other financial income |
|
|
9 |
|
|
|
3 |
|
|
|
268 |
|
|
|
38 |
|
|
|
7 |
|
|
|
577 |
|
|
|
|
|
|
|
|
|
84,448 |
|
|
|
3 |
|
|
|
268 |
|
|
|
363,126 |
|
|
|
7 |
|
|
|
577 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustment to net realizable value on
financial assets (See Note 7-k) |
|
|
3,951 |
|
|
|
1,792 |
|
|
|
|
|
|
|
16,989 |
|
|
|
3,853 |
|
|
|
|
|
Financial cost transferred from related party |
|
|
19,475 |
|
|
|
|
|
|
|
|
|
|
|
83,742 |
|
|
|
|
|
|
|
|
|
Financial cost on provision for asset
retirement obligations (See Note 9) |
|
|
3,339 |
|
|
|
1,639 |
|
|
|
2,344 |
|
|
|
14,358 |
|
|
|
3,524 |
|
|
|
5,040 |
|
Other financial expenses |
|
|
2 |
|
|
|
8 |
|
|
|
27 |
|
|
|
9 |
|
|
|
17 |
|
|
|
58 |
|
|
|
|
|
|
|
|
|
26,767 |
|
|
|
3,439 |
|
|
|
2,371 |
|
|
|
115,098 |
|
|
|
7,394 |
|
|
|
5,098 |
|
|
|
|
|
|
|
|
Gain on variation of exchange rate: |
|
|
On January 8, 2010, the Ministry of Finance and BCV published Exchange Agreement No. 14, in
the Official Gazette No. 39.342, which went into effect January 11, 2010. This Exchange
Agreement modified the official exchange rate for the purchase and sale of foreign currency
denominated in U.S. Dollars. Therefore, all transactions and balances in Bolivars were
converted to U.S. Dollars as per the new exchange rate, resulting in a net gain for the
variation effect in the |
S-92
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
exchange rate due to the fact of maintaining a net liability monetary position in bolivars at
the date when the variation of the exchange rate went into effect (see Note 4) |
|
|
|
Financial cost transferred from related party |
|
|
In accordance with Foreign Exchange Agreement 9, published in Official Gazette 38,318, dated
November 21, 2005, currencies from the export of hydrocarbons that the Company sells PDVSA,
must be sold to the BCV, except for those to be used at activities performed by PDVSA pursuant
to the Amendment to the BCV Law, which compels the Company to sell to the BCV only the cash
flows in currencies, other than local currencies, required to meet its obligations in
bolivars. As of January 11, 2010, payment of those transactions with the BCV was made at the
exchange rates of Bs.4.2893 and Bs.2.5935 per U.S. Dollar, in conformity with the rates
established by the BCV for payment of sale transactions under the Foreign Exchange Agreement
14 (See Note 4). During the year 2010, the average exchange rate on those transactions was
Bs.3.61 per U.S. Dollar, because of this PDVSA had recorded a financial expense for the
difference between this average exchange rate and the official exchange rate. |
|
|
As a result of PDVSA paying, with resources from the sale of crude and gas, in local and
foreign currency the liabilities of the Company for the services incurred as well as payroll
related obligations assigned by PDVSA (See Note 21), during the year ended December 31, 2010
the Company recorded US$19,475 thousands (Bs.83,743 thousands) corresponding to its share for
the difference in the average exchange rate mentioned before of Bs.3.61 and the official
exchange rate of Bs.4.30 (See Note 4). |
(19) |
|
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, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
U.S. Dollars |
|
Bolivars |
|
|
|
|
|
Accounts receivable (Note 12) |
|
|
499,313 |
|
|
|
361,137 |
|
|
|
2,147,046 |
|
|
|
776,445 |
|
Recoverable tax credits (See Note 7) |
|
|
13,453 |
|
|
|
17,922 |
|
|
|
57,849 |
|
|
|
38,532 |
|
Accounts receivable other (See Note 12) |
|
|
1,662 |
|
|
|
673 |
|
|
|
7,147 |
|
|
|
1,447 |
|
Cash and cash equivalents |
|
|
3,465 |
|
|
|
3,062 |
|
|
|
14,900 |
|
|
|
6,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
517,893 |
|
|
|
382,794 |
|
|
|
2,226,942 |
|
|
|
823,007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S-93
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
Aging of the account receivables are shown below (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
U.S. Dollars |
|
Bolivars |
|
|
|
|
|
Under 30 days |
|
|
206,410 |
|
|
|
136,755 |
|
|
|
887,563 |
|
|
|
294,023 |
|
Between 31 and 180 days |
|
|
260,375 |
|
|
|
113,666 |
|
|
|
1,119,613 |
|
|
|
244,382 |
|
Between 180 days and one year |
|
|
32,528 |
|
|
|
109,186 |
|
|
|
139,870 |
|
|
|
234,750 |
|
More than one year |
|
|
|
|
|
|
1,530 |
|
|
|
|
|
|
|
3,290 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
499,313 |
|
|
|
361,137 |
|
|
|
2,147,046 |
|
|
|
776,445 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity of financial liabilities, including estimated interest payments and excluding the
impact of offset agreements, is shown below (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contractual cash |
|
|
|
Book value |
flows |
6 months or less |
|
|
Non-derivative financial liabilities |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
|
|
|
|
|
U.S. Dollars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable to
suppliers (See Note 15) |
|
|
21,022 |
|
|
|
35,021 |
|
|
|
21,022 |
|
|
|
35,021 |
|
|
|
21,022 |
|
|
|
35,021 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bolivars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable to
suppliers (See Note 15) |
|
|
90,395 |
|
|
|
75,295 |
|
|
|
90,395 |
|
|
|
75,295 |
|
|
|
90,395 |
|
|
|
75,295 |
|
|
|
|
|
|
|
|
|
|
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 statements of financial position (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
Monetary assets: |
|
|
|
|
|
|
|
|
Bolivars |
|
|
86,991 |
|
|
|
391,383 |
|
|
|
|
|
|
|
|
|
|
|
|
|
86,991 |
|
|
|
391,383 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Monetary liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bolivars |
|
|
1,423,259 |
|
|
|
691,588 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,423,259 |
|
|
|
691,588 |
|
|
|
|
|
|
|
|
|
|
Net monetary liability position |
|
|
(1,336,268 |
) |
|
|
(300,205 |
) |
|
|
|
|
|
|
|
|
|
S-94
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
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, |
|
|
2010 |
|
2009 |
Exchange rate at year end (Bs./US$1) |
|
|
4.30 |
|
|
|
2.15 |
|
|
|
|
|
|
|
|
|
|
Average exchange rate for the year (Bs./US$1) |
|
|
4.30 |
|
|
|
2.15 |
|
|
|
|
|
|
|
|
|
|
Interannual increase in the CPI (%) |
|
|
27.18 |
|
|
|
25.06 |
|
|
|
|
|
|
|
|
|
|
|
|
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): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
December 31, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
Book |
|
Fair |
|
Book |
|
Fair |
|
Book |
|
|
|
|
|
Book |
|
Fair |
|
|
value |
|
value |
|
value |
|
value |
|
value |
|
Fair value |
|
value |
|
value |
|
|
U.S. Dollars |
|
Bolivars |
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
499,313 |
|
|
|
499,313 |
|
|
|
361,137 |
|
|
|
361,137 |
|
|
|
2,147,046 |
|
|
|
2,147,046 |
|
|
|
776,445 |
|
|
|
776,445 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recoverable tax credits |
|
|
17,404 |
|
|
|
13,453 |
|
|
|
19,714 |
|
|
|
17,922 |
|
|
|
74,837 |
|
|
|
57,849 |
|
|
|
38,532 |
|
|
|
38,532 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable other |
|
|
1,662 |
|
|
|
1,662 |
|
|
|
673 |
|
|
|
673 |
|
|
|
7,147 |
|
|
|
7,147 |
|
|
|
1,448 |
|
|
|
1,448 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
3,465 |
|
|
|
3,465 |
|
|
|
3,062 |
|
|
|
3,062 |
|
|
|
14,900 |
|
|
|
14,900 |
|
|
|
6,583 |
|
|
|
6,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable to suppliers |
|
|
21,022 |
|
|
|
21,022 |
|
|
|
35,021 |
|
|
|
35,021 |
|
|
|
90,395 |
|
|
|
90,395 |
|
|
|
75,295 |
|
|
|
75,295 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other liabilities (included in
accruals and other payables) |
|
|
171,415 |
|
|
|
171,415 |
|
|
|
154,863 |
|
|
|
154,863 |
|
|
|
737,085 |
|
|
|
737,085 |
|
|
|
332,955 |
|
|
|
332,955 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts and dividends
payables to shareholders and
related companies |
|
|
49,403 |
|
|
|
49,403 |
|
|
|
101,437 |
|
|
|
101,437 |
|
|
|
212,433 |
|
|
|
212,433 |
|
|
|
218,090 |
|
|
|
218,090 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20) |
|
Commitments and Contingencies |
|
|
At December 31, 2010 and 2009 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. |
S-95
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
Compliance with Environmental Regulations |
|
|
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. |
|
|
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. |
(21) |
|
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, |
|
|
2010 |
|
2009 |
|
2008 |
|
2010 |
|
2009 |
|
2008 |
|
|
Dólares |
|
Bolívares |
Activities for the year: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas sales |
|
|
607,586 |
|
|
|
458,251 |
|
|
|
474,619 |
|
|
|
2,612,621 |
|
|
|
985,240 |
|
|
|
1,020,431 |
|
|
|
|
|
|
Operating expenses |
|
|
17,544 |
|
|
|
35,442 |
|
|
|
21,298 |
|
|
|
75,439 |
|
|
|
76,200 |
|
|
|
45,791 |
|
|
|
|
|
|
General, administrative and selling
expenses |
|
|
3,868 |
|
|
|
6,589 |
|
|
|
3,506 |
|
|
|
16,632 |
|
|
|
14,167 |
|
|
|
7,538 |
|
|
|
|
|
|
Royalties (See Note 7) |
|
|
183,076 |
|
|
|
137,925 |
|
|
|
149,605 |
|
|
|
787,227 |
|
|
|
296,539 |
|
|
|
321,651 |
|
|
|
|
|
|
Reimbursement of expenses |
|
|
235,634 |
|
|
|
149,058 |
|
|
|
272,852 |
|
|
|
1,013,326 |
|
|
|
320,475 |
|
|
|
586,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at the end of the year: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
(See Note 12) |
|
|
499,313 |
|
|
|
361,137 |
|
|
|
257,292 |
|
|
|
2,147,049 |
|
|
|
776,445 |
|
|
|
553,178 |
|
|
|
|
|
|
Dividends paid to Shareholders (See Note 14) |
|
|
43,346 |
|
|
|
|
|
|
|
20,750 |
|
|
|
186,388 |
|
|
|
|
|
|
|
44,612 |
|
|
|
|
|
|
Accounts payable to Shareholder B(See Note 15) |
|
|
1,499 |
|
|
|
4,060 |
|
|
|
2,327 |
|
|
|
6,446 |
|
|
|
8,729 |
|
|
|
5,003 |
|
|
|
|
|
|
Dividends payable- Shareholder A
(See Note
14) |
|
|
18,330 |
|
|
|
31,126 |
|
|
|
|
|
|
|
78,819 |
|
|
|
66,921 |
|
|
|
|
|
|
|
|
|
|
Accounts payable to PDVSA (See Note 15) |
|
|
29,574 |
|
|
|
66,251 |
|
|
|
78,241 |
|
|
|
127,168 |
|
|
|
142,440 |
|
|
|
168,218 |
|
|
|
|
|
|
S-96
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
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. |
|
|
|
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 US$70.57, US$57.62 and US$84.52 per
barrel for the year ended December 31, 2010, 2009 and 2008, respectively. |
|
|
|
During the years ended December 31, 2010, 2009 and 2008, the Company sold crude oil and
natural gas to PDVSA Petróleo for US$607,586 thousands, US$458,251 thousands and US$474,619
thousands (Bs.2,612,621 thousands, Bs.985,239 thousands and Bs.1,020,431 thousands),
respectively, included in the statements of comprehensive income under Income. At December
31, 2010, 2009 and 2008, the statement of financial position includes US$499.313 thousands,
US$361,137 thousands and US$257,292 thousands (Bs.2,147,049 thousands, Bs.776,445 thousands
and Bs.553,178 thousands) of accounts receivable in this connection. |
|
|
|
During 2010, 2009 and 2008, PDVSA Petróleo charged Petrodelta, S.A. US$246 million, US$278
million and US$370 million (Bs.1,197 million, Bs.561 million and Bs.798 million),
respectively, for labor and other costs, taxes, royalties, cash advances, dividends, included
in general, administrative and selling expenses and operational 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, 2010 and 2009, 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 11, 2008, it was resolved to offset receivables
and payables with PDVSA and its affiliates for the amount if US$329.3 million (Bs.708
million). 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. |
|
|
|
In February 26, 2009, July 3, 2009 and December 4, 2009, the Companys Board of Directors
approved the offsetting of accounts payable to PDVSA and its affiliates, including CVP, for
royalties, taxes and operation expenditures in the amount of US$206.2 million, US$94.7
million and US$118.2 million (Bs.443.3 million, Bs.203.7 million and Bs.254.1 millions)
respectively, against the receivable from PDVSA and its affiliates, including CVP, for oil
and gas deliveries. |
S-97
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
In June 10, 2010, the Companys Board of Directors approved the offsetting of accounts
payable to PDVSA and its affiliates, including CVP, for 2010 royalties, taxes and operation
expenditures in the amount of US$40 million (Bs.172 million) against the receivable from
PDVSA and its affiliates, including CVP, for 2010 oil and gas deliveries. |
|
|
|
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 (See Note 24). |
(22) |
|
Collective Labor Agreement |
|
|
On January 20, 2010 the Collective Labor Agreement was signed, valid for the period from
October 1, 2009 thru October 1, 2011, 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
Collective Labor Agreement establishes 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-time bonus of Bs. 8.000 which has no effect in the severance benefits
of employees. |
|
|
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. |
(23) |
|
Laws, Resolutions and Legal Contributions |
|
a) |
|
Laws enacted under the Enabling Law |
|
|
|
|
On December 17, 2010, the National Assembly approved the Law Authorizing the President of
the Republic to issue Decree-Laws. The Enabling law was published in the extraordinary
Official Gazette No. 6.009 and covers a range of areas for a term of 18 months after
publication thereof. Under this law, the authorization encompasses areas involving the
transformation of government institutions, popular participation, as well as economic,
social, financial, tax and energy matters. |
S-98
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
b) |
|
Foreign Exchange Agreement 18 |
|
|
|
|
On June 4, 2010, Official Gazette 39,439 was published containing Foreign Exchange
Agreement 18, which establishes that the BCV will be in charge of regulating the terms and
conditions for the negotiation, in local currency, and through the system accorded for
that purpose, of securities of the Bolivarian Republic of Venezuela, its decentralized
entities or any other issuing body, whether they are issued or to be issued in foreign
currency. |
|
|
c) |
|
Ruling 001-2010 by National Antidrugs Office (Oficina Nacional Antidrogas or ONA) |
|
|
|
|
On February 11, 2010, Official Gazette 39,366 was published containing Ruling
001-2010, which establishes standards for the admissible discounts to the expense set
forth under LOCTICSEP and its Regulation for payment corresponding to fiscal years 2006,
2007 and 2008. This ruling establishes that only the following payments made by taxpayers
during fiscal years 2006, 2007 and 2008 may be subject to rebates: |
|
|
|
Conduction of projects for comprehensive social prevention and development. |
|
|
|
|
Expenses under non-reimbursable technical assistance agreements. |
|
|
|
|
Funding or performance of activities under comprehensive social prevention. |
|
d) |
|
Foreign Exchange Agreement 15 |
|
|
|
|
On January 27, 2010, as a result of a material error, Foreign Exchange Agreement 15 was
republished in Official Gazette 39,355, originally published in Official Gazette 39,349
dated January 19, 2010. This agreement contains new provisions and guidelines
complementing the multiple exchange rate system created under Foreign Exchange Agreement
14 (See Note 4). The most relevant aspects of this agreement follow: |
|
|
|
As to the Value Added Tax (VAT), imports of goods and services are subject to
the exchange rate of Bs.2.60 per U.S. Dollar, for the food, health, education,
machinery and equipment and science and technology sectors; Bs.4.30 per U.S. Dollar
will be used for other sectors. With regards to exports of goods and services, the
applicable exchange rate is Bs.4.2893 per U.S. Dollar. |
|
|
|
|
In relation to customs, the applicable exchange rate is Bs.2.60 per U.S. Dollar
for imports corresponding to the food, health, education, machinery and equipment
and science and technology sectors; and Bs.4.30 per U.S. Dollar for all other
imports. |
|
e) |
|
Organic Law Reserving for the State Assets and Services Related to Primary
Hydrocarbons Activities |
|
|
|
|
On May 7, 2009, Official Gazette No. 39,173 was published containing the Organic Law
Reserving for the State Assets and Services Related to Primary Hydrocarbons Activities,
which reserves for the Republic, as a result of its strategic condition, assets and
services |
S-99
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
associated with the primary activities established under Organic Hydrocarbons Law to be
performed by PDVSA or any of its subsidiaries. |
|
f) |
|
Organic Law on Science and Technology and Innovation (LOCTI) |
|
|
|
|
On December 2010, the Partial Amendment to the Organic Law on Science and Technology and
Innovation (LOCTI) was published. This amendment establishes that legal or private or
publicly owned entities, domiciled in the Bolivarian Republic of Venezuela or abroad,
performing economic activities within the national territory are under the obligation of
paying on an annual basis an established percentage of their gross income from the
previous year, in respect to their business area, as follows: |
|
|
|
One percent for privately owned enterprises operating in business areas subject
to the Organic Law on Hydrocarbons and Gaseous Hydrocarbons, including mining,
processing and distribution activities. |
|
|
|
|
Half percent for publicly owned companies if the business pursued is one of
those listed in the Organic Law on Hydrocarbons and Gaseous Hydrocarbons including
mining, processing and distribution activities. |
|
|
|
|
Half percent for any other business activity. |
|
|
|
As of December 31, 2010, CVP sent instructions to the Company to record its share
according to the law for its obligation corresponding to the year ended December 2010
only. The provision recorded in the statements of financial position corresponding to the
year ended December 31, 2010 amounts to US$4,583 thousands (Bs.19,705 thousands). For the
year ended December 31, 2009 the Company received instructions from its shareholder CVP to
grant exemption from paying the contribution since it will be PDVSA who will file on a
consolidated basis the contribution established in this Law. Therefore, the Company has
not make any provision in relation to the contribution corresponding to the year ended
December 31, 2009, |
|
|
g) |
|
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 |
S-100
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
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. |
|
|
h) |
|
Antidrug Organic Law (LOD) |
|
|
|
|
On September 15, 2010, the Antidrug Organic Law was published in Official Gazette No.
39,510. The LOD eliminates the Law on Narcotic and Psychotropic Substances (LOCTISEP) and
its partial regulation published June 5, 1996 under Official Gazette No. 35,986. Among the
significant changes are: |
|
- |
|
Taxable base is changed, previously considered base on net profit and now
establishes as taxable base current period operating income. |
|
|
- |
|
Filing and payment of tribute is extended from 15 calendar days of the
following taxable period, to 60 calendar days from the closing corresponding taxable
period. |
|
|
- |
|
In relation to sanctions, the law establishes: 1) failure to comply the
contribution of 1%, a penalty equivalent to double the amount due, if re-occur the
penalty will be 3 times the corresponding contribution due, and 2) for not complying
the special contribution of 2%, same penalty, before was 60,000 tax units or
suspension of business activities during 1 year in case of re-occurrence. |
|
|
- |
|
In the prior law, donations made by persons or companies in favor of plans
and programs established by the government in relation to drugs matter and approved
by ONA, can be deducted for income tax purposes, previously approved by public
document. In the new law, this last aspect is eliminated as a requisite for
proceeding to deduct from income tax purposes. |
|
|
- |
|
Incorporates an obligation by government agencies and institutions, as well
as public and private companies that employ more than 50 workers, to provide labor to
rehabilitated persons, under the programs of social inclusions. |
|
i) |
|
Law on Narcotic and Psychotropic Substances (LOCTISEP) |
|
|
|
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. |
|
|
|
|
On May 31, 2006, the National Anti-Drug Agency (ONA) published an extension to the process
for starting to make contributions according to the Law; therefore as of December 31, 2009
and 2008 no contribution has been made for this concept. |
|
|
|
|
In July 1, 2009, Presidential Decree No.6.776 was published in Official Gazette No. 39,211
where Partial Regulation of LOCTISEP was enacted, with the purpose to define and establish |
S-101
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
the guidelines, mechanism, modalities, forms and opportunities in which legal entities,
public and private as mentioned in the Articles No.96 and No.97 of the Law, comply with
the obligation to fund ONA the contributions established. |
|
|
|
|
In December 29, 2009 providence 007-2009 and 008-2009 were published in Official Gazette
No. 39,336 whereas the National Anti-Drug Agency (ONA) establishes norms and procedures to
collect, control and audit 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, 2010 and 2009,
the Company recorded an expense of approximately US$4,813 thousands and US$3,336 thousands
(Bs.20,697 thousands and Bs.7,173 thousands), respectively, in this connection, included
net in the statements of comprehensive income for each year under general and
administrative expenses. 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. |
|
a) |
|
During February 2011, CVP sent instructions to the Company to transfer the
expense originated from the sale of foreign currency to the BCV by PDVSA for the
difference in the average exchange rate of Bs.3.61 and the official exchange rate of
Bs.4.30 (See Note 18). |
|
|
b) |
|
During February 2011, the Company following instructions from its shareholder
CVP proceeded to offset accounts receivables and payables between PDVSA and its
affiliates, including CVP with the Company outstanding as of December 31, 2009 at the
exchange rate prevailing as of this date, resulting in a netting of US$46 million
(Bs.101 million). Additionally, in the same month and year, CVP sent instructions again
to the Company to proceed and offset accounts receivables and payables between PDVSA
and its affiliates, including CVP with the Company outstanding as of December 31, 2010,
resulting in a netting of US$195 million (Bs.838 million). Both nettings have been
recorded in the month of December of 2010, and are included in the statements of
financial position as of December 31, 2010 and approved by the Board of Directors of
the Company on February 23, 2011. |
|
|
c) |
|
On February 23, 2011, providence No. 0001-2011 was published in the Official
Gazette No. 39.622, establishing that labor matters related to Projects for Integral
Prevention on Drug Consumption must be presented to the National Antidrug Fund (FONA).
The providence also establishes timing and guidelines for responsible entities. |
(25) |
|
Subsequent Events after the Date of Independent Accountants Opinion |
|
a) |
|
On February 24, 2011, providence No. SNAT/2011-0009 from the National
Integrated Service on Tributes and Customs Administration (SENIAT) was published in
Official |
S-102
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
Gazette No. 39,623 in which the current tax unit value was adjusted from Bs.65 to
Bs.76. |
|
|
b) |
|
At the Board of Director meeting dated 10 March 2011 it was approved the
proposal to submit for consideration to the Shareholders the distribution of the
cumulative translation adjustment account to the different accounts of the equity.
The following table shows the amounts at December 31, 2010 of different components
of equity with the distribution of the translation adjustment once the shareholders
of the Company have approved it: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances as of December 31, 2010 |
|
|
|
|
|
|
|
Bolivars |
|
|
|
|
|
|
|
|
|
|
|
|
|
before |
|
|
Bolivars after |
|
|
|
|
|
|
|
|
|
|
translation |
|
|
translation |
|
|
Translation |
|
|
|
U.S. Dollars |
|
|
adjustment |
|
|
adjustment |
|
|
adjustment |
|
Capital stock |
|
|
6,977 |
|
|
|
15,000 |
|
|
|
30,000 |
|
|
|
15,000 |
|
Share premium |
|
|
212,451 |
|
|
|
456,770 |
|
|
|
913,539 |
|
|
|
456,769 |
|
Legal reserve and other reserves |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Legal reserve |
|
|
698 |
|
|
|
1,500 |
|
|
|
3,000 |
|
|
|
1,500 |
|
Deferred tax equity reserve |
|
|
58,696 |
|
|
|
252,394 |
|
|
|
252,394 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59,394 |
|
|
|
253,894 |
|
|
|
255,394 |
|
|
|
1,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable retained earnings
at December 31, 2009 |
|
|
122,728 |
|
|
|
71,984 |
|
|
|
527,730 |
|
|
|
455,746 |
|
Total comprehensive income for
the year 2010 |
|
|
77,683 |
|
|
|
334,035 |
|
|
|
334,035 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
200,411 |
|
|
|
406,019 |
|
|
|
861,765 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity |
|
|
479,233 |
|
|
|
1,131,683 |
|
|
|
2,060,698 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Translation adjustment not allocated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
929,015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
c) |
|
On March 10, 2011, 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. |
(26) |
|
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. |
S-103
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
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. |
|
|
|
It is important to mention an increase for the year 2010 on extensions and discoveries of oil
and gas proved reserves. The increase is due to a new revision to Petrodletas Business Plan
for the period 2011-2027 elaborated for the year ended December 31, 2010. The new revision
take into account a Base Case for Development with a much lower risk and a greater potential
in reserves to be develop compared to the prior Business Plan and the reason lies in the
success obtained from the wells testing and drilling programs executed during the period
2008-2010 in the new fields Temblador and El Salto. |
|
|
|
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 |
|
|
2010 |
|
2009 |
|
2008 |
Proved developed and undeveloped reserves of
conventional crude oil at January 1 |
|
|
206.823 |
|
|
|
214,658 |
|
|
|
220,163 |
|
Revisions |
|
|
|
|
|
|
|
|
|
|
|
|
Expansions and discoveries |
|
|
313.058 |
|
|
|
|
|
|
|
|
|
Production |
|
|
(8,561 |
) |
|
|
(7,835 |
) |
|
|
(5,505 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves of
conventional crude oil at December 31 |
|
|
511.320 |
|
|
|
206.823 |
|
|
|
214.658 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves of conventional crude oil at
December 31 (included on the previous amount) |
|
|
52.705 |
|
|
|
54.110 |
|
|
|
47.298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2010, 2009 and 2008, certified reserves assigned to the Company amounted
to 511.320 thousands, 206,823 thousands and 214.658 thousand barrels, respectively.
|
S-104
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
Production for the year ended December 31, 2010, 2009 and 2008 was 8.561 thousands, 7.835
thousands and 5.505 thousand barrels. |
|
(b) |
|
Natural Gas Reserves (in millions of cubic feet) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31 |
|
|
2010 |
|
2009 |
|
2008 |
Proved developed and undeveloped reserves of natural
gas at January 1 |
|
|
266.292 |
|
|
|
273,281 |
|
|
|
283,981 |
|
Revisions |
|
|
|
|
|
|
(2,592 |
) |
|
|
|
|
Expansions and discoveries |
|
|
284.792 |
|
|
|
|
|
|
|
|
|
Production |
|
|
(2,204 |
) |
|
|
(4,397 |
) |
|
|
(10,700 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves of natural
gas at December 31 |
|
|
548.880 |
|
|
|
266,292 |
|
|
|
273,281 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves of natural
gas at December 31 (included on the previous amount) |
|
|
10,350 |
|
|
|
25,641 |
|
|
|
32,630 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas production is shown on the basis of actual volumes before the extraction of
liquefiable hydrocarbons. |
|
|
|
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 the year 2010. 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 |
|
|
2010 |
|
2009 |
|
2008 |
|
2010 |
|
2009 |
|
2008 |
|
|
|
|
|
Development costs |
|
|
93,640 |
|
|
|
83,141 |
|
|
|
53,576 |
|
|
|
402,652 |
|
|
|
178,753 |
|
|
|
115,188 |
|
|
|
|
|
|
Total costs
incurred from
development
activities |
|
|
93,640 |
|
|
|
83,141 |
|
|
|
53,576 |
|
|
|
402,652 |
|
|
|
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): |
S-105
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional Crude |
|
|
U.S. Dollars |
|
Bolivars |
|
|
2010 |
|
2009 |
|
2008 |
|
2010 |
|
2009 |
|
2008 |
|
|
|
|
|
Assets used in production |
|
|
362,087 |
|
|
|
307,272 |
|
|
|
227,939 |
|
|
|
1,556,974 |
|
|
|
660,635 |
|
|
|
490,069 |
|
|
|
|
|
|
Equipment and facilities |
|
|
10,615 |
|
|
|
7,466 |
|
|
|
3,737 |
|
|
|
45,645 |
|
|
|
16,052 |
|
|
|
8,035 |
|
|
|
|
|
|
|
|
|
372,702 |
|
|
|
314,738 |
|
|
|
231,676 |
|
|
|
1,602,619 |
|
|
|
676,687 |
|
|
|
498,104 |
|
|
|
|
|
|
Accumulated Depletion,
depreciation
and amortization |
|
|
(134,737 |
) |
|
|
(94,322 |
) |
|
|
(61,134 |
) |
|
|
(579,369 |
) |
|
|
(202,792 |
) |
|
|
(131,438 |
) |
|
|
|
|
|
Construction in progress |
|
|
78,755 |
|
|
|
32,912 |
|
|
|
30,946 |
|
|
|
338,646 |
|
|
|
70,760 |
|
|
|
66,534 |
|
|
|
|
|
|
|
|
|
|
|
Total net costs
capitalized as assets |
|
|
316,720 |
|
|
|
253,328 |
|
|
|
201,488 |
|
|
|
1,361,896 |
|
|
|
544,655 |
|
|
|
433,200 |
|
|
|
|
|
|
|
|
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 |
|
|
2010 |
|
2009 |
|
2008 |
|
2010 |
|
2009 |
|
2008 |
|
|
|
|
|
Net production income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
607.586 |
|
|
|
458.251 |
|
|
|
474.619 |
|
|
|
2.612.621 |
|
|
|
985.240 |
|
|
|
1.020.431 |
|
Production costs |
|
|
(69.872 |
) |
|
|
(59.152 |
) |
|
|
(84.314 |
) |
|
|
(300,450 |
) |
|
|
(127.177 |
) |
|
|
(181.275 |
) |
Royalties |
|
|
(218.819 |
) |
|
|
(157.681 |
) |
|
|
(225.167 |
) |
|
|
(940.922 |
) |
|
|
(339.014 |
) |
|
|
(484.109 |
) |
Depletion, depreciation
and
amortization |
|
|
(39.166 |
) |
|
|
(32.571 |
) |
|
|
(24.778 |
) |
|
|
(168,414 |
) |
|
|
(70.028 |
) |
|
|
(53.273 |
) |
|
|
|
|
|
|
|
|
|
|
Results of operation
before income Tax |
|
|
279,729 |
|
|
|
208,847 |
|
|
|
0140,360 |
|
|
|
1,202,835 |
|
|
|
449,021 |
|
|
|
301,774 |
|
|
|
|
|
|
Income tax |
|
|
(189.780 |
) |
|
|
(105.868 |
) |
|
|
(69.374 |
) |
|
|
(816.054 |
) |
|
|
(227.616 |
) |
|
|
(149.154 |
) |
|
|
|
|
|
|
|
|
|
|
Results production operation |
|
|
89.949 |
|
|
|
102.979 |
|
|
|
70.986 |
|
|
|
386,781 |
|
|
|
221.405 |
|
|
|
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. |
S-106
PETRODELTA, S.A.
(Subsidiary owned in a 60% by Corporación Venezolana del Petróleo, S.A.)
Notes to the financial statements
December 31, 2010 and 2009
|
|
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 |
|
|
2010 |
2009 |
2008 |
|
2010 |
2009 |
2008 |
|
|
Dólares |
|
Bolívares |
Average sale price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil per barrel |
|
|
70.57 |
|
|
|
57.62 |
|
|
|
84.52 |
|
|
|
303.46 |
|
|
|
123.88 |
|
|
|
181.72 |
|
|
|
|
|
|
|
|
|
|
|
Natural gas per barrel |
|
|
1.54 |
|
|
|
1.54 |
|
|
|
1.54 |
|
|
|
6.62 |
|
|
|
3.31 |
|
|
|
3.31 |
|
|
|
|
|
|
|
|
|
|
|
Average production cost per BOE |
|
|
7.83 |
|
|
|
6,90 |
|
|
|
11.57 |
|
|
|
33.65 |
|
|
|
14.84 |
|
|
|
24.88 |
|
|
|
|
|
|
S-107