XFRA:NA4 BPZ Resources Inc Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 10-Q

(Mark One)

 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended: June 30, 2012

or

 
o
TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from         to

Commission File Number: 001-12697

BPZ RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)

Texas
 
33-0502730
(State or Other Jurisdiction of Incorporation or Organization)
 
(I.R.S. Employer Identification No.)

580 Westlake Park Blvd., Suite 525
Houston, Texas 77079
(Address of Principal Executive Office)

Registrant’s Telephone Number, Including Area Code: (281) 556-6200

N/A
(Former Name, Former Address and Former Fiscal Year, If Changed Since Last Report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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 x  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer o
 
Accelerated filer x
     
Non-accelerated filer o
 
Smaller reporting company o
(Do not check if a smaller reporting company)
   

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

As of July 31, 2012, there were 116,333,080 shares of common stock, no par value, outstanding.



 
 

 


TABLE OF CONTENTS

PART I
       
Item 1.
Financial Statements
 
3
       
 
Consolidated Balance Sheets
 
3
       
 
Consolidated Statements of Operations
 
4
       
 
Consolidated Statements of Cash Flows
 
5
       
 
Notes to Consolidated Financial Statements
 
6
       
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
28
       
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
 
47
       
Item 4.
Controls and Procedures
 
49
       
PART II
       
Item 1.
Legal Proceedings
 
50
       
Item 1A.
Risk Factors
 
50
       
Item 6.
Exhibits
 
50
       
SIGNATURES
 
 
2

 
 
PART I

Item 1. Financial Statements

BPZ Resources, Inc. and Subsidiaries
Consolidated Balance Sheets
(In thousands)

   
June 30,
2012
   
December 31,
2011
 
   
(Unaudited)
       
ASSETS
           
             
Current assets:
           
Cash and cash equivalents
  $ 97,372     $ 58,172  
Accounts receivable
    4,156       8,174  
Income taxes receivable
    1,363       1,212  
Value added tax receivable
    23,615       24,720  
Inventory
    19,036       16,841  
Prepaid and other current assets
    10,308       4,304  
Total current assets
    155,850       113,423  
                 
Property, equipment and construction in progress, net
    397,799       381,602  
Restricted cash
    5,365       7,865  
Other non-current assets
    6,285       7,527  
Investment in Ecuador property, net
    726       820  
Deferred tax asset
    32,447       26,096  
Total assets
  $ 598,472     $ 537,333  
                 
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
                 
Current liabilities:
               
Accounts payable
  $ 11,069     $ 19,520  
Accrued liabilities
    26,013       19,694  
Other liabilities
    132       1,015  
Accrued interest payable
    5,016       6,064  
Derivative financial instruments
    7       1,096  
Current maturity of long-term debt and capital lease obligations
    19,053       16,854  
Total current liabilities
    61,290       64,243  
Asset retirement obligation
    1,349       1,304  
Derivative financial instruments
    -       950  
Long-term debt and capital lease obligations, net
    347,705       248,384  
Total long-term liabilities
    349,054       250,638  
                 
Commitments and contingencies (Note 18 and 19)
               
                 
Stockholders’ equity:
               
Preferred stock, no par value, 25,000 authorized; none issued and outstanding
    -       -  
Common stock, no par value, 250,000 authorized; 116,319 and 115,910 shares issued and outstanding at June 30, 2012 and December 31, 2011, respectively
    558,705       557,238  
Accumulated deficit
    (370,577 )     (334,786 )
Total stockholders’ equity
    188,128       222,452  
Total liabilities and stockholders’ equity
  $ 598,472     $ 537,333  
 
The accompanying notes are an integral part of these consolidated financial statements.
 
 
3

 

BPZ Resources, Inc. and Subsidiaries
Consolidated Statements of Operations (Unaudited)
(In thousands, except per share data)

   
Three Months
Ended June 30,
   
Six Months
Ended June 30,
 
   
2012
   
2011
   
2012
   
2011
 
                         
Net revenue:
                       
Oil revenue, net
  $ 32,679     $ 35,646     $ 69,154     $ 73,362  
Other revenue
    2       1,293       80       2,282  
                                 
Total net revenue
    32,681       36,939       69,234       75,644  
                                 
Operating and administrative expenses:
                               
Lease operating expense
    12,694       7,521       24,062       18,273  
General and administrative expense
    10,425       9,276       17,556       18,307  
Geological, geophysical and engineering expense
    2,442       1,462       26,732       7,719  
Depreciation, depletion and amortization expense
    11,648       9,231       23,154       19,277  
Standby costs
    1,409       492       2,599       2,821  
Other expense
    756       -       756       -  
                                 
Total operating and administrative expenses
    39,374       27,982       94,859       66,397  
                                 
Operating income (loss)
    (6,693 )     8,957       (25,625 )     9,247  
                                 
Other income (expense):
                               
Loss from investment in Ecuador property, net
    (47 )     (47 )     (94 )     (94 )
Interest expense
    (4,080 )     (4,905 )     (10,290 )     (8,640 )
Loss on extinguishment of debt
    (7,318 )     -       (7,318 )     -  
Gain (loss) on derivatives
    8,407       (321 )     2,039       (4,623 )
Interest income
    7       2       10       233  
Other income (expense)
    (198 )     (14 )     (245 )     192  
                                 
Total other expense, net
    (3,229 )     (5,285 )     (15,898 )     (12,932 )
                                 
Income (loss) before income taxes
    (9,922 )     3,672       (41,523 )     (3,685 )
                                 
Income tax expense (benefit)
    (1,422 )     3,380       (5,732 )     4,116  
                                 
Net income (loss)
  $ (8,500 )   $ 292     $ (35,791 )   $ (7,801 )
                                 
Basic net income (loss) per share
  $ (0.07 )   $ 0.00     $ (0.31 )   $ (0.07 )
Diluted net income (loss) per share
  $ (0.07 )   $ 0.00     $ (0.31 )   $ (0.07 )
                                 
Basic weighted average common shares outstanding
    115,573       115,322       115,543       115,260  
Diluted weighted average common shares outstanding
    115,573       115,776       115,543       115,260  
 
The accompanying notes are an integral part of these consolidated financial statements.
 
 
4

 

BPZ Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows (Unaudited)
(In thousands)
 
 
 
For the Six Months Ended
June 30,
 
   
2012
   
2011
 
             
Cash flows from operating activities:
           
Net loss
  $ (35,791 )   $ (7,801 )
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
               
Stock-based compensation
    1,420       2,364  
Depreciation, depletion and amortization
    23,154       19,277  
Amortization of investment in Ecuador property
    94       94  
Deferred income taxes
    (6,484 )     3,544  
Loss on extinguishment of debt
    7,318       -  
Amortization of discount and deferred financing fees
    4,896       3,768  
Unrealized (gain) loss on derivatives
    (2,039 )     4,623  
Changes in operating assets and liabilities:
               
Decrease in accounts receivable
    4,017       2,851  
Decrease in value added tax receivable
    1,106       4,373  
(Increase) decrease in inventory
    (1,397 )     720  
Increase in other assets
    (3,479 )     (603 )
Increase in income taxes receivable
    (18 )     (1,886 )
Decrease in accounts payable
    (8,451 )     (23,617 )
Increase in accrued liabilities
    915       1,189  
Increase (decrease) in other liabilities
    (883 )     90  
Net cash provided by (used in) operating activities
    (15,622 )     8,986  
                 
Cash flows from investing activities:
               
Property and equipment additions
    (40,284 )     (28,262 )
Increase in restricted cash
    -       (2,563 )
Net cash used in investing activities
    (40,284 )     (30,825 )
                 
Cash flows from financing activities:
               
Borrowings
    141,719       40,000  
Repayments of borrowings
    (44,735 )     (14,629 )
Deferred loan fees
    (1,925 )     (1,526 )
Proceeds from exercise of stock options, net
    -       923  
Proceeds from sale of common stock, net
    47       (5 )
Net cash provided by financing activities
    95,106       24,763  
                 
Net increase in cash and cash equivalents
    39,200       2,924  
Cash and cash equivalents at beginning of period
    58,172       11,752  
Cash and cash equivalents at end of period
  $ 97,372     $ 14,676  
                 
                 
Supplemental cash flow information:
               
Cash paid for:
               
Interest
  $ 13,171     $ 9,104  
Income tax
    653       2,706  
Non — cash items:
               
Depletion allocated to production inventory
    797       293  
Depreciation on support equipment capitalized to construction in progress
    5       132  
Gain on capital lease repayment capitalized to property and equipment
    180       -  
 
The accompanying notes are an integral part of these consolidated financial statements.
 
 
5

 
 
BPZ Resources, Inc. and Subsidiaries
Notes To Consolidated Financial Statements
(Unaudited)

Note 1 - Basis of Presentation and Significant Accounting Policies
 
Organization
 
BPZ Resources, Inc., (together with its subsidiaries, collectively referred to as the “Company” or “BPZ” unless the context requires otherwise) a Texas corporation, is based in Houston, Texas with offices in Lima, Peru and Quito, Ecuador. The Company is focused on the exploration, development and production of oil and natural gas in Peru, and to a lesser extent, Ecuador. The Company also intends to utilize part of its planned future natural gas production as a supply source for the complementary development of a gas-fired power generation facility which is expected to be wholly- or partially-owned by the Company.
 
The Company maintains a subsidiary, BPZ Exploración & Producción S.R.L. (“BPZ E&P”), registered in Peru through its wholly-owned subsidiary BPZ Energy, LLC, a Texas limited liability company, formerly BPZ Energy, Inc. and its subsidiary BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership.  Currently, the Company, through BPZ E&P, has exclusive rights and license contracts for oil and gas exploration and production covering a total of approximately 2.2 million acres, in four blocks, in northwest Peru. The Company’s license contracts cover 100% ownership of the following properties: Block Z-1 (0.6 million acres), Block XIX (0.5 million acres), Block XXII (0.9 million acres) and Block XXIII (0.2 million acres). The Block Z-1 contract was signed in November 2001, the Block XIX contract was signed in December 2003 and the Blocks XXII and XXIII contracts were signed in November 2007. Generally, according to the Organic Hydrocarbon Law No. 26221 and the regulations thereunder (the “Organic Hydrocarbon Law” or “Hydrocarbon Law”), the seven-year term for the exploration phase can be extended in each contract by up to an additional three years to a maximum of ten years. However, specific provisions of each license contract can vary the exploration phase of the contract as established by the Hydrocarbon Law. The license contracts require the Company to conduct specified activities in the respective blocks during each exploration period in the exploration phase. If the exploration activities are successful, the Company may decide to enter the exploitation phase and the total contract term can extend up to 30 years for oil exploration and production and up to 40 years for gas exploration and production. In the event a block contains both oil and gas, as is the case in the Company’s Block Z-1, the 40-year term may apply to oil exploration and production as well.
 
Additionally, through its wholly-owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, the Company owns a 10% non-operating net profits interest in an oil and gas producing property, Block 2, located in the southwest region of Ecuador (the “Santa Elena Property”). The agreement covering the property extends through May 2016.
 
The Company is in the process of developing its Peruvian oil and natural gas reserves.  The Company placed the Corvina field into commercial production in November 2010.  The Company is currently in the process of fabricating a new platform in the Corvina field to further enhance its production profile.  The Company is also in the initial stages of appraising, exploring and developing its potential oil and natural gas reserves from the A platform in the Albacora field of Block Z-1.  The Company began producing from the A-14XD well in December 2009, and began selling oil from the A-14XD well under a well testing program during the second quarter of 2010.  The Company has installed all of the equipment necessary for the reinjection of gas and water at the Albacora platform, completed tie-ins and tested the equipment, and is working on the final environmental permit to start commercial production in Albacora.  In the meantime, the Company has obtained a permit that allows it to flare gas from the A-14XD, A-13E and A-9G wells until December 28, 2012.  Additionally, the Company’s activities in Peru include (i) analysis and evaluation of technical data on its properties, (ii) preparation of the development plans for the properties, (iii) meeting requirements under the license contracts, (iv) procuring equipment for an extended drilling campaign, (v) obtaining all necessary environmental, technical and operating permits, (vi) optimizing current production, (vii) conducting seismic surveys, (viii) and obtaining preliminary engineering and design of the power plant and gas processing and delivery facilities.
 
On April 27, 2012, the Company and Pacific Rubiales Energy Corp. (together with its subsidiaries, collectively “Pacific Rubiales”) executed a Stock Purchase Agreement (“SPA”) under which the Company formed an unincorporated joint venture relationship with Pacific Rubiales to explore and develop the offshore Block Z-1 located in Peru.  Pursuant to the SPA, Pacific Rubiales agreed to pay $150.0 million for a 49% participating interest in Block Z-1 and agreed to fund $185.0 million of the Company’s share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012.  In order to finalize the joint venture, Peruvian governmental approvals are needed to allow Pacific Rubiales to become a party to the Block Z-1 License Contract.  Until the required approvals are obtained, Pacific Rubiales has agreed to provide the Company these and other funds as loans to continue to fund the Company’s Block Z-1 capital and exploratory activities.  See Note 18, “Commitments and Contingencies,” for further information related to the Company’s new joint venture.
 
 
6

 
 
Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements of BPZ Resources, Inc. and its subsidiaries have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP” or “U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. The unaudited consolidated financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented on a basis consistent with the annual audited consolidated financial statements.  All such adjustments are of a normal, recurring nature. All significant transactions between BPZ and its consolidated subsidiaries have been eliminated. Certain prior period amounts have been reclassified to conform to current year presentation. Results of operations for interim periods are not necessarily indicative of the results of operations that may be expected for the entire year. The balance sheet at December 31, 2011 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

Use of Estimates
 
The preparation of the consolidated financial statements in accordance with U.S. GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses in the consolidated financial statements, and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.
 
Estimates of crude oil reserves are the most significant of the Company’s estimates. All of the reserves data in this Form 10-Q are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.
 
Other items subject to estimates and assumptions include the carrying amounts of property and equipment, asset retirement obligations, derivatives and deferred income tax assets. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.  Current credit market conditions combined with volatile commodity prices have resulted in increased uncertainty inherent in such estimates and assumptions.  As future events and their effects cannot be determined accurately, actual results could differ significantly from management’s estimates.

Summary of Significant Accounting Policies

The Company has provided a summary discussion of significant accounting policies, estimates and judgments in Note 1 to the Notes to Consolidated Financial Statements included in its Annual Report on Form 10-K for the year ended December 31, 2011.  These interim financial statements should be read in conjunction with the consolidated audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

Recent Accounting Pronouncements
 
In December 2011, the FASB issued guidance that requires that an entity disclose information about offsetting and related arrangements to enable users of the Company’s financial statements to understand the effect of those arrangements on the Company’s financial position.  The guidance is effective for annual periods beginning on or after January 1, 2013.  The Company is currently evaluating the provisions of this guidance and assessing the impact, if any, it may have on the Company’s financial position and results of operations.

Note 2 — Value Added Tax Receivable

Value-added tax (referred to as “IGV” in Peru) is generally imposed on goods and services at a rate of 18% effective March 2011 and 19% in previous periods.

 
7

 
 
Peru currently has an IGV early recovery program for oil and gas companies during the exploration phase. Under this program, IGV paid on the acquisition of certain goods and services used directly in hydrocarbon exploration activities can be recovered prior to a commercial discovery taking place or the initiation of production and revenue billings. Because the Company has oil sales in the Corvina field which is in commercial production and in the Albacora field under a well testing program, it is no longer eligible for the IGV early recovery program.  Accordingly, the Company is recovering its IGV receivable with IGV payables associated with oil sales under the normal IGV recovery process.
 
Activity related to the Company’s value-added tax receivable for the six months ended June 30, 2012 and the year ended December 31, 2011 is as follows:
 
   
June 30,
2012
   
December 31,
2011
 
   
(in thousands)
 
Value-added tax receivable as of the beginning of the period
  $ 24,720     $ 31,352  
IGV accrued related to expenditures during period
    17,188       28,780  
IGV reduced related to sale of oil during period
    (18,293 )     (35,412 )
Value-added tax receivable as of the end of the period
  $ 23,615     $ 24,720  
 
Note 3 — Inventory
 
Inventories consist primarily of crude oil, tubular goods, accessories and spare parts for production equipment, stated at the lower of average cost or market.
 
The Company maintains crude oil inventories in storage vessels until the inventory quantities are at a sufficient level that the refinery in Talara will accept delivery.  Oil inventory is stated at the lower of average cost or market value. Cost is determined on a weighted average basis based on production costs.

Below is a summary of inventory as of June 30, 2012 and December 31, 2011:
 
   
June 30,
2012
   
December 31,
2011
 
   
(in thousands)
 
Tubular goods, accessories and spare parts
  $ 13,648     $ 13,541  
Crude oil
    5,388       3,300  
Inventory
  $ 19,036     $ 16,841  
 
   
June 30,
2012
   
December 31,
2011
 
Crude oil (barrels)
    64,787       46,105  
Crude oil (cost per barrel)
  $ 83.17     $ 71.57  

 
8

 
 
Note 4 — Prepaid and Other Current Assets and Other Non-Current Assets

Below is a summary of prepaid and other current assets as of June 30, 2012 and December 31, 2011:

   
June 30,
2012
   
December 31,
2011
 
   
(in thousands)
 
Prepaid expenses and other
  $ 3,361     $ 588  
Prepaid insurance
    1,692       961  
Insurance receivable
    755       755  
Restricted cash
    4,500       2,000  
                 
Prepaid and other current assets
  $ 10,308     $ 4,304  
 
“Prepaid and other current assets” are primarily related to prepayments for drilling services, equipment rental, material procurement and deposits that are primarily rent deposits related to the Company’s offices in Houston and Peru. Prepaid insurance consists of premiums related to the Company’s operations as well as general liability and directors’ and officers’ insurance policies. The insurance receivable is related to an incident that occurred in the third quarter of 2011 where, while in the process of moving certain equipment from the A platform in Albacora to the CX-11 platform in Corvina using third parties, certain equipment was damaged.  The Company expects to recover the receivable amount from either the third parties or its insurance carrier.  The restricted cash is related in part to the current portion of the $40.0 million secured debt financing (the “$40.0 million secured debt facility”) entered into by the Company in January of 2011 that requires the Company to establish a $2.0 million debt service reserve account during the first 18-month period.  The restricted cash is also related to the current portion of the $75.0 million secured debt financing (the “$75.0 million secured debt facility”) entered into by the Company in July of 2011 that requires the Company to establish a $2.5 million debt service reserve account during the first 15-month period.  For further information see Note 8, “Restricted Cash and Performance Bonds.”

Below is a summary of other non-current assets as of June 30, 2012 and December 31, 2011:

   
June 30,
2012
   
December 31,
2011
 
   
(in thousands)
 
Debt issue costs, net
  $ 6,285     $ 7,527  
                 
Other non-current assets
  $ 6,285     $ 7,527  
 
“Other non-current assets” consist of direct transaction costs incurred by the Company in connection with its debt raising efforts.  At June 30, 2012 and December 31, 2011, the Company had net debt issue costs of $6.3 million and $7.5 million, respectively.
 
In connection with the prepayment made on the $75.0 million secured debt facility and the amendments to both the $75.0 million secured debt facility and $40.0 million secured debt facility in April 2012, the debt issue costs associated with those agreements were modified in accordance with ASC Topic 470 as follows:
 
 
(1)
Prior to the $40.0 million prepayment on the $75.0 million secured debt facility, the original debt issue costs of $4.4 million had an unamortized balance of $2.8 million. Approximately 53% of the remaining debt issue costs related to the $75.0 million secured debt facility was expensed ($1.5 million) when the Company prepaid 53% of the principal balance in May 2012. In addition, the Company added $1.1 million of debt issue costs incurred with the fourth amendment to the remaining debt issue costs of $1.3 million as the amendment was not considered a substantial modification of debt.  The $2.4 million of debt issue costs will be amortized to expense over the remaining term of the $75.0 million secured debt facility, ending in July 2015, using the effective interest method.
 
 
(2)
Prior to the fourth amendment on the $40.0 million secured debt facility, the original debt issue costs of $1.5 million had an unamortized balance of $0.6 million.  The Company added $0.8 million of debt issue costs incurred with the fourth amendment to the remaining unamortized debt issue costs of $0.6 million as the amendment was not considered a  substantial modification of debt.  The $1.4 million of debt issue costs will be amortized to expense over the remaining term of the $40.0 million secured debt facility, ending in January 2015, using the effective interest method.
 
 
9

 
 
The Company incurred $4.8 million of original debt issue costs associated with $170.9 million of convertible notes due 2015 (the “2015 Convertible Notes”). The debt issue costs are being amortized over the life of the $170.9 million Convertible Notes, using the effective interest method.
 
For the three and six months ended June 30, 2012, the Company amortized into interest expense $0.7 million and $1.6 million, respectively, of debt issue costs.  For the three and six months ended June 30, 2011, the Company amortized into interest expense $0.4 million and $0.9 million, respectively, of debt issue costs.
 
For further information regarding the Company’s debt, see Note 9, “Debt and Capital Lease Obligations.”

Note 5 — Property, Equipment and Construction in Progress

Below is a summary of property, equipment and construction in progress as of June 30, 2012 and December 31, 2011:
 
   
June 30,
2012
   
December 31,
2011
 
   
(in thousands)
 
Construction in progress:
           
Power plant and related equipment
  $ 70,125     $ 66,903  
Platforms and wells
    78,534       48,469  
Pipelines and processing facilities
    26,421       20,089  
Other
    2,708       2,504  
Producing properties (successful efforts method of accounting)
    258,600       258,583  
Producing equipment
    17,143       17,143  
Barge and related equipment
    78,905       78,710  
Office equipment, leasehold improvements and vehicles
    10,897       10,824  
Accumulated depletion, depreciation and amortization
    (145,534 )     (121,623 )
                 
Property, equipment and construction in progress, net
  $ 397,799     $ 381,602  

The Company follows the “successful efforts” method of accounting for its costs of acquisition, exploration and development of oil and gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved developed crude oil reserves on a field-by-field basis.  Certain costs of exploratory wells are capitalized pending determinations that proved reserves have been found.  Exploratory well costs continue to be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If the determination is dependent upon the results of planned additional wells and required capital expenditures to produce the reserves found, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the exploratory well and additional wells are underway or planned.  All costs related to unsuccessful exploratory wells are expensed when such wells are determined to be non-productive.

Exploratory well costs capitalized greater than one year after completion of drilling were $13.0 million as of June 30, 2012, and December 31, 2011.  The exploratory well costs relate to the CX11-16X gas well that was drilled in 2007, which tested sufficient quantities of gas and is currently shut-in until such time as a market is established for selling the gas.  The Company plans to use the gas from the CX11-16X well for its gas-to-power project.  See Note 18, “Commitments and Contingencies” for further information on the gas-to-power project.

During the six months ended June 30, 2012, the Company incurred capital expenditures of approximately $40.3 million associated with its development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of gas-fired power generation of electricity for sale in Peru.

For the six months ended June 30, 2012, the Company incurred approximately $29.6 million related to costs incurred in the design and fabrication of the CX-15 platform and incurred $6.2 million for the development of and equipment for permanent production facilities.

 
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The Company also added approximately $3.2 million of costs to the power plant, which primarily consisted of capitalized interest, and incurred approximately $1.3 million related to other capitalized costs.
 
For the three and six months ended June 30, 2012, capitalized depreciation expense was an immaterial amount, and the Company capitalized $3.7 million and $6.7 million of interest expense, respectively, to construction in progress.  For the same periods in 2011, the Company capitalized $0.1 million of depreciation expense, and $1.7 million and $4.4 million of interest expense, respectively, to construction in progress.
 
For the three and six months ended June 30, 2012, the Company recognized $11.7 million and $23.2 million, respectively, of depreciation, depletion and amortization expense.  For the same periods in 2011, the Company recognized $9.2 million and $19.3 million, respectively, of depreciation, depletion and amortization expense.

Note 6 — Asset Retirement Obligation
 
An obligation related to the future plug and abandonment of the producing oil wells in the Corvina and Albacora fields and the Pampa la Gallina well in Block XIX has been recorded in accordance with the provisions of Accounting Standard Codification (“ASC”) Topic 410, “Asset Retirement and Environmental Obligations.”  ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon the Company’s periodic review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using the Company’s credit-adjusted-risk-free rate. The carrying value of the ARO is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost.
 
Activity related to the Company’s ARO for the six months ended June 30, 2012 and the year ended December 31, 2011 is as follows:

   
June 30,
2012
   
December 31,
2011
 
   
(in thousands)
 
ARO as of the beginning of the period
  $ 1,304     $ 855  
Liabilities incurred during period
    -       680  
Accretion expense
    45       110  
Revisions in estimates during period
    -       (341 )
ARO as of the end of the period
  $ 1,349     $ 1,304  
 
The 2011 revisions in estimates are due to the shift in timing of cash flows associated with expected payment of the ARO liability.  As the expected timing to settle the liabilities was extended in 2011, the present value of the liabilities was decreased and, as a result, the Company reduced both the liability and capitalized asset by approximately $0.3 million in accordance with ASC Topic 410.

Note 7 — Investment in Ecuador Property
 
The Company has a 10% non-operating net profits interest in an oil and gas property in Ecuador (the “Santa Elena Property”).  The Company accounts for this investment under the cost method and records its share of cash received or paid as other income or expense. Since the Company’s investment represents ownership of an oil and gas property, which is a depleting asset, the Company is amortizing the cost of the investment on a straight-line basis over the remaining term of the agreement which expires in May 2016. 
 
 
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Below is a summary reflecting the Company’s loss from the investment in the Ecuador property for the three and six months ended June 30, 2012 and 2011, respectively, and the investment in the Ecuador property at June 30, 2012 and December 31, 2011, respectively.
 
   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2012
   
2011
   
2012
   
2011
 
   
(in thousands)
   
(in thousands)
 
Distributions received from investment in Ecuador property
  $ -     $ -     $ -     $ -  
Amortization of investment in Ecuador property
    (47 )     (47 )     (94 )     (94 )
Loss from investment in Ecuador property, net
  $ (47 )   $ (47 )   $ (94 )   $ (94 )
 
   
June 30,
2012
   
December 31,
2011
 
   
(in thousands)
 
Investment in Ecuador property, net
  $ 726     $ 820  
 
Note 8 — Restricted Cash and Performance Bonds

Below is a summary of restricted cash as of June 30, 2012 and December 31, 2011:

   
June 30,
2012
   
December 31,
2011
 
 
 
(in thousands)
 
Performance bonds totaling $5.6 million for properties in Peru
  $ 3,338     $ 3,338  
Insurance bonds for import duties related to a construction vessel
    814       814  
Performance obligations and commitments for the gas-to power site
    650       650  
Secured letters of credit
    563       563  
$75.0 million secured debt facility
    2,500       2,500  
$40.0 million secured debt facility
    2,000       2,000  
Unsecured performance bond totaling $0.1 million for office lease agreement
    -       -  
Restricted cash
  $ 9,865     $ 9,865  
                 
Current portion of restricted cash as of the end of the period
  $ 4,500     $ 2,000  
                 
Long-term portion of restricted cash as of the end of the period
  $ 5,365     $ 7,865  

The $75.0 million secured debt facility entered into by the Company in July of 2011 required the Company to establish a $2.5 million debt service reserve account during the first 15 months the debt facility is outstanding.  After the first 15-month period, the Company is required to keep a balance in the debt service reserve account equal to the aggregate amount of principal and interest due on the next quarterly repayment date.  The Company expects to make contributions to the debt service reserve account of $0.4 million in 2012 and, thereafter, maintain the next quarterly interest and principal payment within the debt service reserve account.

The $40.0 million secured debt facility entered into by the Company in January of 2011 required the Company to establish a $2.0 million debt service reserve account during the first 18-month period and, thereafter, the Company must maintain a balance in the debt service reserve account equal to the aggregate amount of payments of principal and interest on the $40.0 million secured debt facility due immediately on the succeeding principal repayment date.  The Company expects to make contributions to the debt service reserve account of $2.4 million in 2012 and, thereafter, maintain the next quarterly interest and principal payment within the debt service reserve account.

See Note 4, “Prepaid and Other Current Assets and Other Non-Current Assets” for further information on the current portion of restricted cash.
 
 
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All of the performance and insurance bonds are issued by Peruvian banks and their terms are governed by the corresponding license contracts, customs laws, credit agreements, legal requirements or rental practices.
 
Note 9 — Debt and Capital Lease Obligations

At June 30, 2012 and December 31, 2011, debt and capital lease obligations consisted of the following:

   
June 30,
2012
   
December 31,
2011
 
   
(in thousands)
 
             
$170.9 million Convertible Notes, 6.5%, due March 2015, net of discount of ($20.9) million at June 30, 2012 and ($24.1) million at December 31, 2011
  $ 150,032     $ 146,781  
$75.0 million Secured Debt Facility, 3-month LIBOR plus 9%, due July 2015
    35,000       75,000  
$40.0 million Secured Debt Facility, 3-month LIBOR plus 8%, due January 2015
    40,000       40,000  
Pacific Rubiales Loans, non interest bearing
    141,719       -  
Capital Lease Obligations
    7       3,457  
      366,758       265,238  
Less: Current maturity of long-term debt and capital lease obligations
    19,053       16,854  
Long-term debt and capital lease obligations, net
  $ 347,705     $ 248,384  
 
$170.9 million Convertible Notes due 2015

During the first quarter of 2010, the Company closed on a private offering for an aggregate of $170.9 million of convertible notes due 2015.  The 2015 Convertible Notes are the Company’s general senior unsecured obligations and rank equally in right of payment with all of the Company’s other existing and future senior unsecured indebtedness.  The 2015 Convertible Notes are effectively subordinate to all of the Company’s secured indebtedness to the extent of the value of the assets collateralizing such indebtedness.  The 2015 Convertible Notes are not guaranteed by the Company’s subsidiaries.

The interest rate on the 2015 Convertible Notes is 6.50% per year with interest payments due on March 1st and September 1st of each year.  The 2015 Convertible Notes mature with repayment of $170.9 million (assuming no conversion) due on March 1, 2015. The initial conversion rate of 148.3856 shares per $1,000 principal amount (equal to an initial conversion price of approximately $6.74 per share of common stock) was adjusted on February 3, 2011 in accordance with the terms of the Indenture. As a result, the conversion rate and conversion price changed to 169.0082 and $5.9169, respectively. Upon conversion, the Company must deliver, at its option, either (1) a number of shares of its common stock determined as set forth in the Indenture, (2) cash, or (3) a combination of cash and shares of its common stock.
 
Holders may convert their 2015 Convertible Notes at their option at any time prior to the close of business on the second business day immediately preceding the maturity date under certain circumstances:
 
(1) during any fiscal quarter (and only during such fiscal quarter) commencing after March 31, 2010, if the last reported sale price of the Company’s common stock is greater than or equal to 130% of the conversion price of the 2015 Convertible Notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter;
 
(2) prior to January 1, 2015, during the five business-day period after any ten consecutive trading-day period in which the trading price of $1,000 principal amount of the 2015 Convertible Notes for each trading day in the measurement period was less than 97% of the product of the last reported sale price of the Company’s common stock and the conversion rate on such trading day;
 
(3) if the 2015 Convertible Notes have been called for redemption; or
 
(4) upon the occurrence of one of a specified number of corporate transactions.  Holders may also convert the 2015 Convertible Notes at their option at any time beginning on February 1, 2015, and ending at the close of business on the second business day immediately preceding the maturity date.
 
 
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On or after February 3, 2013, the Company may redeem for cash all or a portion of the 2015 Convertible Notes at a redemption price of 100% of the principal amount of the notes to be redeemed plus any accrued and unpaid interest to, but not including, the redemption date, plus a “make-whole” payment if: (1) for at least 20 trading days in any consecutive 30 trading days ending within 5 trading days immediately before the date the Company mails the redemption notice, the “last reported sale price” of its common stock exceeded 175% of the conversion price in effect on that trading day, and (2) there is no continuing default with respect to the notes that has not been cured or waived on or before the redemption date.
 
If the Company experiences any one of certain specified types of corporate transactions, holders may require the Company to purchase all or a portion of their 2015 Convertible Notes. Any repurchase of the notes pursuant to these provisions will be for cash at a price equal to 100% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excluding, the purchase date.
 
The indenture agreement contains customary terms and covenants and events of default, the occurrence and continuation of which could result in the acceleration of amounts due under the 2015 Convertible Notes.
 
Net proceeds from the sale of the 2015 Convertible Notes, after deducting the discounts and commissions and any offering expenses payable by the Company, were approximately $164.9 million.  The initial purchaser received commissions of approximately $5.5 million in connection with the sale and the Company incurred approximately $0.6 million of direct expenses in connection with the offering.  The Company used the net proceeds for general corporate purposes, including capital expenditures and working capital, reduction or refinancing of debt, and other corporate obligations.
 
The Company accounts for the 2015 Convertible Notes in accordance with ASC Topic 470, “Debt”, as it pertains to accounting for convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement).  Under the accounting guidance, convertible debt instruments that may be settled entirely or partially in cash upon conversion are required to be separated into liability and equity components, with the liability component amount determined in a manner that reflects the issuer’s non-convertible debt borrowing rate. The value assigned to the liability component is determined by measuring the fair value of a similar liability that does not have an equity conversion feature. The value assigned to the equity component is determined by deducting the fair value of the liability component from the initial proceeds. The excess of the principal amount of the liability component over its carrying amount (the non-cash discount) is amortized to interest cost using the effective interest method over the term of the debt agreement.  In addition, transaction costs incurred that directly relate to the issuance of convertible debt instruments must be allocated to the liability and equity components in proportion to the allocation of proceeds and accounted for as debt issuance costs and equity issuance costs, respectively.
 
The Company estimated its non-convertible borrowing rate at the date of issuance of the 2015 Convertible Notes to be 12%. The 12% non-convertible borrowing rate represented the borrowing rate of similar companies with the same credit quality as the Company and was obtained through a quote from the initial purchaser. Using the income method and discounting the principal and interest payments of the 2015 Convertible Notes using the 12% non-convertible borrowing rate, the Company estimated the fair value of the $170.9 million 2015 Convertible Notes to be approximately $136.3 million with the discount being approximately $34.6 million. The discount is being amortized as non-cash interest expense over the life of the notes using the effective interest method. In addition, the Company allocated approximately $4.8 million of the $6.1 million of fees and commissions as debt issue costs that are being amortized as non-cash interest expense over the life of the notes using the effective interest method. The remaining $1.3 million of fees and commissions were treated as transaction costs associated with the equity component. The Company estimated the remaining cash payments including interest payments related to the 2015 Convertible Notes, assuming no conversion, for 2012, 2013, 2014 and 2015 to be approximately $5.5 million, $11.1 million, $11.1 million and $176.5 million, respectively. The Company evaluated the 2015 Convertible Notes agreement for potential embedded derivatives, noting that the conversion feature and make-whole provisions did not meet the embedded derivative criteria as set forth in ASC Topic 815, “Derivatives and Hedging”. Therefore, no additional amounts have been recorded for those items.
 
As of June 30, 2012, the net amount of $150.0 million includes the $170.9 million of principal reduced by $20.9 million of the remaining unamortized discount. The net amount of the equity component is $33.3 million, which includes the initial discount of $34.6 million reduced by $1.3 million of direct transaction costs. The remaining unamortized discount of $20.9 million will be amortized into interest expense, using the effective interest method, over the remaining life of the loan agreement, whose term expires in March 2015.  At June 30, 2012, using the conversion rate of 169.0082 shares per $1,000 principal amount of the 2015 Convertible Notes, if the $170.9 million of principal were converted into shares of common stock, the notes would convert into approximately 28.9 million shares of common stock.  As of June 30, 2012, there is no excess if-converted value to the holders of the 2015 Convertible Notes as the price of the Company’s common stock at June 30, 2012, $2.53 per share, is less than the conversion price.
 
 
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For the three and six months ended June 30, 2012, the annual effective interest rate on the 2015 Convertible Notes, including the amortization of debt issue costs, was approximately 12.6%.
 
For the three and six months ended June 30, 2012, the amount of interest expense related to the 2015 Convertible Notes was $4.7 million and $9.3 million, respectively, disregarding capitalized interest considerations, and includes $2.8 million and $5.6 million, respectively, of interest expense related to the contractual interest coupon, $1.6 million and $3.2 million, respectively, of non-cash interest expense related to the amortization of the discount and $0.3 million and $0.5 million, respectively, of interest expense related to the amortization of debt issue costs.
 
For the three and six months ended June 30, 2011, the amount of interest expense related to the 2015 Convertible Notes was $4.5 million and $8.9 million, respectively, disregarding capitalized interest considerations, and includes $2.8 million and $5.6 million, respectively, of interest expense related to the contractual interest coupon, $1.5 million and $2.9 million, respectively, of non-cash interest expense related to the amortization of the discount and $0.2 million and $0.4 million, respectively, of interest expense related to the amortization of debt issue costs.
 
$75 Million Secured Debt Facility

On July 6, 2011, the Company and its subsidiaries entered into a credit agreement with Credit Suisse and other parties (collectively the “lenders”), where the lenders agreed to provide a $75.0 million secured debt facility in two loan tranches to the Company’s subsidiary, BPZ E&P.  The full amount available under the $75.0 million secured debt facility was drawn down by the Company on July 7, 2011. In April 2012, the Company and the lenders amended the terms of the $75.0 million secured debt facility and in May 2012, the Company prepaid $40.0 million of the principal balance of the $75.0 million secured debt facility.

Proceeds from the $75.0 million secured debt facility were utilized to pay certain fees and expenses under the $75.0 million secured debt facility, to fund a debt service reserve account under the $75.0 million secured debt facility, to reimburse certain affiliates of BPZ E&P for up to $14.0 million of capital and exploratory expenditures incurred by them in connection with the development of Block Z-1 and up to $6.0 million of capital and exploratory expenditures incurred by them in connection with the development in Block XIX in northwest Peru, and to finance BPZ E&P’s capital and exploratory expenditures in connection with the development of Block Z-1.

As a result of the prepayment and amendment during the second quarter of 2012, the Company incurred $5.8 million of fees and prepayment penalties and $1.1 million of debt issue costs. The $5.8 million in fees and prepayment penalties were recognized as a “Loss on extinguishment of debt” in the consolidated statement of operations, 25% was paid at the time of the amendment and prepayment and 25% will be paid at the time of each of the next three quarterly interest payment dates ending in January 2013. Approximately $1.5 million of the remaining $2.8 million of unamortized debt issue costs associated with the initial loan was expensed as a “Loss on extinguishment of debt” in the consolidated statement of operations when the Company prepaid $40.0 million of principal.  The $1.1 million of new debt issue costs was combined with the remaining $1.3 million of unamortized debt issue costs and will be amortized over the amended term, ending in July 2015, using the effective interest method.  For further information on debt issue costs see Note 4, “Prepaid and Other Current Assets and Other Non-Current Assets.”
 
The $75.0 million secured debt facility, as amended, provides for ongoing fees payable by BPZ E&P to the lenders, including  an administration fee of 0.50% of the principal amount outstanding and a performance based arranger fee (the “Performance Based Arranger Fee”) whose amount is determined by the change in the price of Brent crude oil at inception of the loans and the price at each principal repayment date in accordance with the original loan principal repayment dates, subject to a 12% ceiling of the original principal amount borrowed.    For further information on the Performance Based Arranger Fee, see Note 10, “Derivative Financial Instruments” and Note 12, “Fair Value Measurements and Disclosures.”

The $75.0 million secured debt facility required the Company to establish a $2.5 million debt service reserve account during the first 15 months the debt facility is outstanding.  For further information regarding the debt service reserve account and its requirements, see Note 8, “Restricted Cash and Performance Bonds.”

The $75.0 million secured debt facility is secured by (i) 51% of BPZ E&P’s Block Z-1 property on the northwest coast of Peru, (ii) 51% of the wellhead oil production of Block Z-1, (iii) 51% of BPZ E&P’s rights, title and interests under the Block Z-1 License Contract, as amended and assigned, with Perupetro S.A. (“Perupetro”), a private law state company engaged in the refining, transportation, distribution and trading of petroleum products to meet Peru’s domestic energy needs, (iv) a collection account (including BPZ E&P’s deposits and investments), (v) 51% of BPZ E&P’s right, title and interests under current and future contracts in connection with the sale of crude oil and/or gas produced and sold at Block Z-1, together with related receivables, (vi)  BPZ E&P’s Capital Stock, (vii) a debt service reserve account, and (viii) certain other property that is subject to a lien in favor of Credit Suisse. The Company and its subsidiary, BPZ Energy LLC, also agreed to unconditionally guarantee the remaining portion of the $75.0 million secured debt facility.
 
 
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The amendment to the $75.0 million secured debt facility extended the maturity of the facility to July 2015, with revised principal repayments due in quarterly installments that range from $2.0 million to $4.5 million commencing in January 2013 and extending through July 2015.  The $75.0 million secured debt facility has an annual interest rate of the three month LIBOR rate plus 9%.  Interest is due and payable at the end of every three month period after the commencement of the loan.

The $75.0 million secured debt facility, as amended, contains covenants that limit the Company’s ability to, among other things, incur additional debt other than the Pacific Rubiales loans, create certain liens, enter into transactions with affiliates, pay dividends on or repurchase stock of the Company or its subsidiaries, or sell assets other than to Pacific Rubiales or merge with another entity.  In addition, the Company must complete certain projects in the Corvina and Albacora offshore fields in Block Z-1 by certain scheduled dates.  The $75.0 million secured debt faciity amended also contains customary financial covenants, including (i) a maximum consolidated leverage ratio, (2) minimum consolidated interest coverage ratio, (iii) a maximum capitalization ratio, (iv) a minimum oil production quota per quarter, (v) a minimum debt service coverage ratio, (vi) a minimum proved developed producing reserves coverage ratio, (vii) a maximum indebtedness, and (viii) a minimum liquidity ratio. The Company was in compliance with these financial covenants at June 30, 2012.

The $75.0 million secured debt facility, as amended, provides for events of default customary for facilities of this type, the occurrence and continuation of which could result in the acceleration of amounts due under the facility. In addition, the $75.0 million secured debt facility provides that BPZ E&P has the right, at any time, to prepay the loans in whole, but not in part, subject to certain conditions and sets forth certain conditions for mandatory prepayments of the loan.

As of June 30, 2012 the Company estimated the remaining cash payments related to the $75.0 million secured debt facility, as amended and excluding potential payments for the Performance Based Arranger Fee but including interest payments, for the year ended December 31, 2012, 2013, 2014 and 2015 to be approximately $1.7 million, $12.7 million, $14.1 million and $14.2 million, respectively.
 
$40.0 Million Secured Debt Facility
 
In January 2011, the Company, through its subsidiaries, completed a credit agreement with Credit Suisse where Credit Suisse provided a $40.0 million secured debt facility to the Company’s power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L.  On April 27, 2012, the Company and its subsidiaries, Empresa Eléctrica Nueva Esperanza S.R.L. and BPZ E&P, entered into a fourth amendment to the $40.0 million secured debt facility with Credit Suisse.
 
Proceeds from the $40.0 million secured debt facility were utilized to meet the Company’s 2011 capital expenditure budget, to finance its exploration and development work programs, and to reduce other debt obligations.

As a result of the amendment entered into during the second quarter of 2012, the Company incurred $0.8 million of debt issue costs.  The $0.8 million of new debt issue costs was combined with the remaining $0.6 million of unamortized debt issue costs and will be amortized over the amended term, ending in January 2015, using the effective interest method.  For further information on debt issue costs, see Note 4, “Prepaid and Other Current Assets and Other Non-Current Assets.”
 
The $40.0 million secured debt facility, as amended, provides for ongoing fees payable to Credit Suisse including a performance based arranger fee (the “Performance Based Arranger Fee”) whose amount is determined by the change in the price of Brent crude oil at inception of the loan and the price at each principal repayment date in accordance with the original loan principal repayment dates, subject to a 18% ceiling of the original principal amount borrowed.    For further information on the Performance Based Arranger Fee, see Note 10, “Derivative Financial Instruments” and Note 12, “Fair Value Measurements and Disclosures.”
 
The $40.0 million secured debt facility is secured, in part, by three LM6000 gas-fired packaged power units (approximately $70.0 million) that were purchased by the Company from GE through its power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L. The $40.0 million secured debt financing is also secured by certain other equipment and property pledged in favor of Credit Suisse and Credit Suisse International. The Company and its subsidiary, BPZ E&P, also agreed to unconditionally guarantee the $40.0 million secured debt facility on an unsecured basis. 
 
The $40.0 million secured debt facility requires the Company to establish and maintain a debt service reserve account during the term of the facility. For further information regarding the debt service reserve account and its requirements, see Note 8, “Restricted Cash and Performance Bonds.”
 
 
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The amendment to the $40.0 million secured debt facility extended the maturity of the facility to January 2015, with revised principal repayments due in quarterly installments of $3.6 million commencing in July 2012 and extending through January 2015.  The $40.0 million secured debt facility has a revised annual interest rate of the three month LIBOR rate plus 8%.  Interest is due and payable at the end of every three month period after the commencement of the loan.
 
The amended $40.0 million secured debt facility subjects the Company to various financial covenants calculated as of the last day of each quarter, including a maximum leverage ratio, a minimum consolidated interest coverage ratio, a maximum consolidated capitalization ratio and minimum oil production quota per quarter. The Company was in compliance with these financial covenants at June 30, 2012.
 
The $40.0 million secured debt facility provides for events of default customary for facilities of this type, the occurrence and continuation of which could result in the acceleration of amounts due under the facility. In addition, the $40.0 million secured debt facility provides for a mandatory repayment of the loans if the Company secures financing for its gas-to-power project.
  
As of June 30, 2012, the Company estimated the remaining cash payments related to the $40.0 million secured debt facility, excluding the potential payments for the Performance Based Arranger Fee, but including interest payments, for the year ended December 31, 2012, 2013, 2014 and 2015 to be approximately $8.9 million, $16.9 million, $15.6 million and $3.7 million, respectively.
 
Pacific Rubiales Loans
 
On April 27, 2012, the Company and Pacific Rubiales executed a SPA where the Company formed an unincorporated joint venture relationship with Pacific Rubiales to explore and develop the offshore Block Z-1 located in Peru.  Pursuant to the SPA, Pacific Rubiales agreed to pay $150.0 million for a 49% participating interest in Block Z-1 and agreed to fund $185.0 million of the Company’s share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012 (together, the “Pacific Rubiales Loans”).

In order to finalize the joint venture, Peruvian governmental approvals are needed to allow Pacific Rubiales to become a party to the Block Z-1 License Contract.  Until the required approvals are obtained, Pacific Rubiales has agreed to provide the Company certain loans to continue to fund the Company’s Block Z-1 capital and exploratory activities.  Except in the event of a termination of the joint venture, the loans will not accrue interest.  During the period from April 27, 2012 through June 30, 2012, the Company obtained an initial loan of $65.0 million and additional loans of $76.7 million for capital and exploratory activities.
 
The Pacific Rubiales Loans  are secured by (i) 49% of BPZ E&P’s Block Z-1 property on the northwest coast of Peru, (ii) 49% of the wellhead oil production of Block Z-1, (iii) 49% of BPZ E&P’s rights, title and interests under the Block Z-1 License Contract, as amended and restated, with Perupetro, a private law state company engaged in the refining, transportation, distribution and trading of petroleum products to meet Peru’s domestic energy needs, (iv) 49% of BPZ E&P’s right, title and interests under current and future contracts in connection with the sale of crude oil and/or gas produced and sold at Block Z-1, together with related receivables  and (v) certain other property that is subject to a lien in favor of Pacific Rubiales.

At closing, after the proper approvals are obtained, the Company expects Pacific Rubiales to exchange these loans along with an additional $85.0 million, plus any other amounts due to the Company or from the Company under the SPA, for the interests and assets obtained from the Company under the SPA and under the Block Z-1 License Contract.  If the SPA is terminated and certain provisions regarding fault of the parties do not apply, the $65.0 million paid and any amounts advanced to the Company for capital and exploratory expenditures will be converted into an interest bearing loan, accruing interest after the termination date at the rate of three month LIBOR plus 9%.  The Company shall be obligated to repay such amounts together with a termination value, calculated pursuant to the SPA, to Pacific Rubiales in accordance with the repayment schedule as specified in the SPA.  While the loans to Credit Suisse are outstanding, principal payments for the Pacific Rubiales Loans are $4.0 million per quarter until the loans are repaid.  After the loans with Credit Suisse are repaid, quarterly principal payments for the Pacific Rubiales Loans are approximately $10 million until the loans are repaid.

Capital Leases

The Company is party to several capital lease agreements, as more fully described in its Form 10-K for the year ended December 31, 2011.  In the past, the Company generally entered into capital lease agreements in order to secure marine vessels to support its operations in Peru and to obtain furniture and fixtures for its offices located in Houston and Peru. The current contractual terms of the capital lease agreement is three years and the effective interest rate is 17.6%.
 
 
17

 

In May 2012, the Company exercised the third year purchase option for $3.0 million and purchased the marine vessels, Namoku and the Nu’uanu, at which point titles to the vessels were transferred to the Company.

Interest Expense

The following table is a summary of interest expense for the three and six months ended June 30, 2012 and 2011:
 
   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2012
   
2011
   
2012
   
2011
 
   
(in thousands)
   
(in thousands)
 
Interest expense
  $ 7,840     $ 6,617     $ 17,022     $ 13,072  
Capitalized interest expense
    (3,760 )     (1,712 )     (6,732 )     (4,432 )
Interest expense, net
  $ 4,080     $ 4,905     $ 10,290     $ 8,640  

Note 10 — Derivative Financial Instruments

Objective and Strategies for Using Derivative Instruments:

In connection with the $40.0 million secured debt facility and the $75.0 million secured debt facility, the Company and Credit Suisse agreed that a portion of the arranger fee would be based on the performance of oil prices and be payable at each of the principal repayment dates.  The fee is calculated by multiplying the original principal payment amount by the change in oil prices from the loan origination date and the oil price at each original principal repayment date. Additionally, the fee is capped at 18% of the $40.0 million secured debt facility and 12% of the $75.0 million secured debt facility.  The Performance Based Arranger Fee is being accounted for as an embedded financing derivative under ASC Topic 815, “Derivatives and Hedging” and, accordingly, is being recorded at fair value with any mark-to-market changes in value reflected as gain or loss on derivatives in the accompanying consolidated statements of operations.
 
Derivative Financial Instruments Not Designated as Hedging Instruments
Amount of (Gain) Loss on Derivative Instruments Recognized in Income

   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2012
   
2011
   
2012
   
2011
 
   
(in thousands)
   
(in thousands)
 
Realized derivative (gain) loss
  $ -     $ -     $ -     $ -  
Unrealized derivative (gain) loss
    (8,407 )     321       (2,039 )     4,623  
Total (gain) loss on derivative financial instruments
  $ (8,407 )   $ 321     $ (2,039 )   $ 4,623  
 
See Note 12, “Fair Value Measurements and Disclosures,” for a discussion of methods and assumptions used to estimate the fair values of the Company’s derivative instruments.

Note 11 — Stockholders’ Equity

The Company has 25,000,000 shares of preferred stock, no par value, and 250,000,000 shares of common stock, no par value, authorized for issuance.

 
18

 
 
Potentially Dilutive Securities

Basic earnings (loss) per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings (loss) per share of common stock may include the effect of the Company’s shares issuable under a convertible debt agreement, outstanding stock options or shares of restricted stock, except in periods in which there is a net loss. The following table summarizes the calculation of basic and diluted earnings (loss) per share:

   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2012
   
2011
   
2012
   
2011
 
   
(in thousands, except per share data)
 
 
                       
Net income (loss)
  $ (8,500 )   $ 292     $ (35,791 )   $ (7,801 )
                                 
Shares:
                               
Basic weighted average common shares outstanding
    115,573       115,322       115,543       115,260  
                                 
Incremental shares from assumed conversion of dilutive share based awards
    -       454       -       -  
                                 
Diluted weighted average common shares outstanding
    115,573       115,776       115,543       115,260  
Excluded share based awards (1)
    6,256       5,222       6,256       5,676  
Excluded convertible debt shares (1)
    28,890       28,890       28,890       28,890  
                                 
Basic net income (loss) per share
  $ (0.07 )   $ 0.00     $ (0.31 )   $ (0.07 )
Diluted net income (loss) per share
  $ (0.07 )   $ 0.00     $ (0.31 )   $ (0.07 )
 
(1) Inclusion of the shares for these awards would have had an antidilutive effect.
 
Stock Option and Restricted Stock Plans
 
The Company has in effect the 2007 Long-Term Incentive Compensation Plan, as amended in 2010 to increase the number of shares available (the “2007 LTIP”), and the 2007 Directors’ Compensation Incentive Plan (the “Directors’ Plan”). The 2007 LTIP and the Directors’ Plan provide for awards of options, stock appreciation rights, restricted stock, restricted stock units, performance awards, other stock-based awards and cash-based awards to any of the Company’s officers, employees, consultants, and employees of certain of the Company’s affiliates, as well as non-employee directors. The number of shares authorized under the amended 2007 LTIP and Directors’ Plan is 8.0 million and 2.5 million, respectively. As of June 30, 2012, approximately 2.8 million shares remain available for future grants under the 2007 LTIP and 0.7 million shares remain available for future grants under the Directors’ Plan.
 
 
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The following table summarizes stock-based compensation costs recognized under ASC Topic 718, “Stock Compensation,” for the three and six months ended June 30, 2012 and 2011, respectively, and are generally included in “general and administrative expense” in the accompanying consolidated statements of operations:
 
   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2012
   
2011
   
2012
   
2011
 
   
(in thousands)
   
(in thousands)
 
Employee stock—based compensation costs
  $ 661     $ 736     $ 1,137     $ 1,652  
Director stock—based compensation costs
    32       422       265       712  
Employee stock purchase plan costs
    7       -       18       -  
    $ 700     $ 1,158     $ 1,420     $ 2,364  
 
Restricted Stock Awards and Performance Shares

On April 1, 2012, the Company’s Board of Directors awarded 293,112 shares of restricted stock to officers and other key employees under the Company’s 2007 LTIP.  The restricted stock awards generally vest on the second anniversary of the grant date. For the six months ended June 30, 2012, the weighted average grant date fair value per share of the restricted stock granted was $4.00.

On April 1, 2012, the Company awarded its non-employee directors a total of 109,125 shares of restricted stock under the Directors’ Plan.  The restricted stock awards generally vest on the second anniversary of the grant date.  For the six months ended June 30, 2012, the weighted average grant date fair value per share of the restricted stock granted was $4.00.

Stock Options

On April 1, 2012, the Company’s Board of Directors awarded officers and other key employees a total of 478,473 options to purchase the Company’s common stock under the Company’s 2007 LTIP.  These options generally vest in equal annual installments over a three-year period from the grant date.

On April 1, 2012, the Company awarded its non-employee directors a total of 96,140 options to purchase the Company’s common stock under the Directors’ Plan.  These options generally vest in equal annual installments over a two-year period from the grant date.

For the six months ended June 30, 2012, the weighted average exercise price per share of the options awards granted was $4.00 and the weighted average fair value per share of the options awards granted was $2.50.

Employee Stock Purchase Plan

The employee stock purchase plan, which was approved by the shareholders on June 24, 2011, provides eligible employees the opportunity to acquire shares of BPZ Resources, Inc. common stock at a discount through payroll deductions. Employees are allowed to purchase up to 2,500 shares in any one offering period (not longer than twenty-seven months), within IRS limitations and plan rules.  The offering period means each period of time which common stock is offered to participants. Unless otherwise determined by the compensation committee, a new offering period shall commence on the first day of each calendar quarter.  Generally, the purchase price for stock acquired under the plan is the lower of 85% (subject to compensation committee adjustment) of the fair market value of the common stock on the grant date or the fair market value of the common stock on the investment date. Under this plan, 2,000,000 common shares were reserved for issuance and purchase by eligible employees.  Activity under this plan began in the first quarter of 2012.  On April 3, 2012, 17,309 shares were issued to employees at a price of $2.74 per share.  At June 30, 2012, 1,982,691 shares were available for issuance.  On July 3, 2012, 14,244 shares were issued to employees at a price of $2.15 per share.

 
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Note 12 Fair Value Measurements and Disclosures

The Company records certain of its assets and liabilities on the balance sheet at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). A three-level valuation hierarchy has been established to allow readers to understand the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

·   
Level 1 —
Fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities.
     
·   
Level 2 —
Fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.
     
·   
Level 3 —
Fair value measurements which use unobservable inputs.

The following describes the valuation methodologies the Company uses for its fair value measurements.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Cash and Cash Equivalents

Cash and cash equivalents include all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value because of the short maturity of these instruments.

Accounts Receivable, Accounts Payables and Accrued Liabilities

Accounts receivable, Accounts payable and Accrued liabilities are considered to be representative of their respective fair values due to the short-term maturity of these instruments.

Restricted Cash
 
Restricted cash includes all cash balances which are classified as current or long-term because they are associated with the Company’s debt or long-term assets.  The carrying amount approximates fair value because the nature of the restricted cash balance is the same as cash.  The fair value of restricted cash is measured using Level 1 inputs within the three-level valuation hierarchy.
 
 
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Derivative Financial Instruments   

The Company’s derivative financial instruments consist of variable financing arranger fee payments that are dependent on the change in oil prices from the loan origination date of the Company’s $40.0 million secured debt facility, the $75.0 million secured debt facility and the oil price on each repayment date. The Company estimates the fair value of these payments based on published forward commodity price curves at each financial reporting date. The discount rate used to discount the associated cash flows is based on the Company’s credit-adjusted risk-free rate. For further information regarding the Company’s derivatives, see Note 10, “Derivative Financial Instruments.”

Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows:

     
Fair Value Measurements Using:
 
 
Balance Sheet
Location
 
Quoted
Prices in
Active
Markets
(Level 1)
   
Significant
Other
Observable
Inputs
(Level 2)
   
Significant
Unobservable
Inputs
(Level 3)
 
June 30, 2012
   
(in thousands)
 
                     
Financial Liabilities
   
 
   
 
       
Derivative Financial Instruments
Current Liabilities
  $ -     $ 7     $ -  
 
Noncurrent Liabilities
    -       -       -  
      $ -     $ 7     $ -  
 
December 31, 2011
                         
                           
Financial Liabilities
                         
Derivative Financial Instruments
Current Liabilities
  $ -     $ 1,096     $ -  
 
Noncurrent Liabilities
    -       950       -  
      $ -     $ 2,046     $ -  
 
Additional Fair Value Disclosures

Debt with Variable Interest Rates

The fair value of the Company’s $75.0 million secured debt facility, $40.0 million secured debt facility and Pacific Rubiales Loans in the event of a termination of the joint venture, at June 30, 2012, approximates the carrying value because the interest rates are based on floating rates identified by reference to market rates, and because the interest rates charged are at rates at which the Company could borrow under similar terms.  The floating rate debt is considered to be a Level 2 measurement on the fair value hierarchy.
 
Debt with Fixed Interest Rates

The fair value information regarding the Company’s fixed rate debt at June 30, 2012 and December 31, 2011 is as follows:

   
June 30,
2012
   
December 31,
2011
 
                         
   
Carrying Amount
   
Fair Value (2)
   
Carrying Amount
   
Fair Value (2)
 
   
(in thousands)
   
(in thousands)
 
$170.9 million Convertible Notes, 6.5%, due March 2015, net of discount of ($20.9) million at June 30, 2012 and ($24.1) million at December 31, 2011 (1)
  $ 150,032     $ 138,164     $ 146,781     $ 140,460  
 

(1)
Excludes obligations under capital lease arrangements and variable rate debt.
 
 
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(2)
The Company estimated the fair value of the $170.9 million 2015 Convertible Notes to be approximately $138.2 million and $140.5 million at June 30, 2012 and December 31, 2011, respectively, based on observed market prices for the same or similar types of debt issues.  The fair value of the $170.9 million 2015 Convertible Notes is considered to be a Level 1 measurement on the fair value hierarchy.
 
Note 13 Oil Revenue
 
At June 30, 2012, the Company had developed nine wells in the Corvina field and four wells in the Albacora field.  Of these wells, eight wells were producing oil, three wells were producing oil intermittently, one well was being used for gas injection and the remaining well was being used for water reinjection.   
 
The Company’s revenues are reported net of royalties owed to the government of Peru. Royalties are assessed by Perupetro, as stipulated in the Block Z-1 License Contract based on production. However, their calculation is based on the past five-day average basket of crude oils prices, before the crude oil delivery date, as opposed to the price the Company receives for oil which is based on the prior two-week average of a blend of crude oil prices before the crude oil delivery date. For the three and six months ended June 30, 2012, the revenues received by the Company are net of royalty costs of approximately 5% of gross revenues or $1.7 million and $3.8 million, respectively.  For the same periods of 2011, the revenues received by the Company are net of royalty costs of approximately 5% of gross revenues or $1.9 million and $3.9 million, respectively.

Note 14 Other Expense

For the three and six months ended June 30, 2012, the Company reported $0.8 million of abandonment charges in the Consolidated Statements of Operations as “Other expense.”  The Company accrued $0.8 million of abandonment costs related to a platform in the Piedra Redonda field in Block Z-1, as it is obligated to ensure the platform does not cause a threat to marine vessels operating in the area or marine wildlife. The $0.8 charge is in addition to amounts recorded previously related to the platform abandonment costs in the Piedra Redonda field in the third quarter of 2010.  There were no similar expenses incurred by the Company in 2011.
 
Note 15 Standby Costs
 
During 2011, the Company suspended drilling operations until it completes its seismic data acquisition program and fabrication and installation of the new drilling platform in Block Z-1, which is scheduled for the second half of 2012.  The Petrex-18 rig that was rented to another operator in 2011 was returned to the Company in January 2012 and is currently on standby. The contract for the Petrex-18 rig expires in December 2013.  As a result, for the three and six months ending June 30, 2012, the Company incurred $1.4 million and $2.6 million, respectively, in standby rig costs for the Petrex-18 rig.  The contract for the Petrex-09 rig that was used in the Corvina field and which contributed to standby costs in 2011 expired in January 2012, at which time the rig was returned.  For the three and six months ended June 30, 2011, the Company incurred $0.5 million and $2.3 million, respectively, in standby rig costs.  Additionally, the Company incurred $0.5 million of allocated expenses associated with drilling operations for the six months ended June 30, 2011. 
 
 
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Note 16 — Income Tax

The following is a summary of income (loss) before income taxes and income tax expense (benefit) for the three and six months ended June 30, 2012 and June 30, 2011:

   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2012
   
2011
   
2012
   
2011
 
Income (loss) before income taxes:
 
(in thousands)
   
(in thousands)
 
United States
  $ 446     $ (5,692 )   $ (8,345 )   $ (13,119 )
Foreign
    (10,368 )     9,364       (33,178 )     9,434  
 
  $ (9,922 )   $ 3,672     $ (41,523 )   $ (3,685 )
 
                               
                                 
Income tax expense (benefit):
                               
United States
  $ 569     $ 814     $ 979     $ 1,397  
Foreign
    (1,991 )     2,566       (6,711 )     2,719  
 
  $ (1,422 )   $ 3,380     $ (5,732 )   $ 4,116  

The Company has recognized a gross deferred tax asset related to net operating loss carryforwards attributable to the United States, before application of the valuation allowances.  The Company has a valuation allowance for the full amount of the domestic net deferred tax asset, as it believes, based on the weight of available evidence, that it is more likely than not that the deferred tax asset will not be realized prior to the expiration of net operating loss carryforwards in various amounts through 2031. Furthermore, because the Company has no operations within the U.S. taxing jurisdiction, it is likely that sufficient generation of revenue to offset the Company’s deferred tax asset is remote.

The difference from the 22% statutory rate provided for under the Block Z-1 License Contract is due to other Peruvian operations that have a different statutory tax rate, certain expenses which are not deductible in Peru and a change in the timing of when certain expenses are deductible.

Estimated interest and penalties related to potential underpayment on unrecognized tax benefits, if any, are classified as a component of tax expense in the Consolidated Statement of Operations.  The Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the three and six months ended June 30, 2012 or 2011, respectively.  The Company did not have any uncertain tax positions generated from unrecognized tax benefits resulting from differences between positions taken in tax returns and amounts recognized in the financial statements as of June 30, 2012 or December 31, 2011.
 
Note 17 — Business Segment Information
 
The Company determines and discloses its segments in accordance with ASC Topic 280, “Segment Reporting” (“ASC Topic 280”), which uses a “management” approach for determining segments. The management approach designates the internal organization that is used by management for making operating decisions and assessing parlance as the source of the Company’s reportable segments. ASC Topic 280 also requires disclosures about products or services, geographic areas, and major customers. The Company’s management reporting structure provided for only one segment for the three and six months ended June 30, 2012 and 2011, respectively. Accordingly, no separate segment information is presented. In addition, the Company operates only in Peru and has only one customer for its oil production, the Peruvian national oil company, Petroleos del Peru – PETROPERU S.A. (“Petroperu”).  The majority of the Company’s long-lived assets are located in Peru. Management does not consider its investment in Ecuador as a separate business segment.

 
24

 

Note 18 — Commitments and Contingencies
 
Extended Well Testing Program
 
The Company began producing oil under well-testing permits from the Albacora field in December 2009.  During the first half of 2012, the Peruvian Ministry of Energy and Mines (MEM) granted an extension of the gas flaring permit for the Company's Albacora field operations through December 28, 2012, allowing oil production testing to continue until it receives the required environmental permit for gas injection.  In addition, the Company’s request was granted by the General Directorate of Hydrocarbons (“DGH”) to permit testing on the A-12F well to allow a determination to be made whether to use this well as either a gas injector or oil producer.

With respect to any additional Extended Well Test (“EWT”) and gas flaring permits that are requested, the Company can give no assurance that the DGH or the Ministry of Energy and Mines will grant approval of any current or future permits requested by the Company. 
 
Profit Sharing
 
The Constitution of Peru and Legislative Decree Nos. 677 and 892 give employees working in private companies engaged in activities generating income as defined by the Income Tax Law the right to share in the company’s profits.  According to Article 3 of the United Nations International Standard Industrial Classification, BPZ E&P’s tax category is classified under the “mining companies” section, which sets the rate at 8%. However, in Peru, the Hydrocarbon Law states, and the Supreme Court ruled, that hydrocarbons are not related to mining activities. Hydrocarbons are included under “Companies Performing Other Activities”, thus Oil and Gas Companies pay profit sharing at a rate of 5%. The 5% of income is determined by calculating a percentage of the Company’s Peruvian subsidiaries’ annual total revenues subject to income tax less the expenses required to produce revenue or maintain the source of revenues. The benefit granted by the law to employees is calculated on the basis of “income subject to taxation” per the Peruvian tax code, and not based on income (loss) before income taxes as reported under GAAP. For the three and six months ended June 30, 2012 and June 30, 2011, respectively, profit sharing expense was not material to the Company as the Company’s Peruvian subsidiaries did not have a material amount of “income subject to taxation” per the Peruvian tax code as a result of the Company declaring commercial production in the Corvina field in 2010, which allowed certain exploration and development costs to be deductible in 2012 and 2011 that were not deductible in previous years.  The Company is subject to profit sharing expense in any year its Peruvian subsidiaries are profitable according to the Peruvian tax laws.
 
Gas-to-Power Project Financing
 
The gas-to-power project entails the planned installation of an approximately 10-mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and the building of an approximately 135 megawatt (“MW”) simple-cycle electric generating plant.  The power plant site is located adjacent to an existing substation and power transmission lines, which after the Peruvian government completes their expansion, are expected to be capable of handling up to 420 MW of power. The existing substation and transmission lines are owned and operated by third parties.
 
The Company currently estimates the gas-to-power project will cost approximately $153.5 million, excluding working capital and 18% value-added tax which will be recovered via future revenue billings. The $153.5 million includes $133.5 million for the estimated cost of the power plant and $20.0 million for the estimated cost of the construction of the natural gas pipeline. While the Company has held initial discussions with several potential joint venture partners for the gas-to-power project, in an attempt to secure additional financing and other resources for the project, the Company has not entered into any definitive agreements with a potential partner. In the event the Company is able to identify and reach an agreement with a potential joint venture partner, it may only retain a minority position in the project. However, the Company, along with its Block Z-1 partner, Pacific Rubiales, expects to retain the responsibility for the construction of the pipeline as well as retain ownership of the pipeline. If the Company is unable to identify and reach an agreement with a potential joint venture partner for the gas-to-power project, it may move the project forward to completion without a partner. The Company has obtained certain permits and is in the process of obtaining additional permits to move the project forward.
 
Contracts for CX-15 Platform at the Corvina Field
 
In the third quarter of 2011, Soluciones Energeticas S.R.L., a subsidiary of the Company, finalized contracts with a third party located in China to fabricate, mobilize and install a platform at the Corvina field in offshore Block Z-1. The estimated total project cost of the CX-15 project, including all production and compression equipment, is now expected to be approximately $77.0 million.  The Company has guaranteed payment of the platform contracts.
 
 
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Block Z-1 Transaction
 
On April 27, 2012, the Company and Pacific Rubiales executed a SPA under which the Company formed an unincorporated joint venture relationship with Pacific Rubiales to explore and develop the offshore Block Z-1 located in Peru.  Pursuant to the SPA, Pacific Rubiales agreed to pay $150.0 million for a 49% participating interest in Block Z-1 and agreed to fund $185.0 million of the Company’s share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012.
 
In order to finalize the joint venture, Peruvian governmental approvals are needed to allow Pacific Rubiales to become a party to the Block Z-1 License Contract. Until the required approvals are obtained, Pacific Rubiales has agreed to provide the Company financing in the form of loans to continue to fund the Company’s Block Z-1 capital and exploratory activities. Except in the event of a termination of the joint venture, the loans will not accrue interest.  During the period from April 27, 2012 through June 30, 2012, the Company obtained an initial loan of $65.0 million and additional loans of $76.7 million for capital and exploratory activities.  For further information regarding the Company’s debt, see Note 9, “Debt and Capital Lease Obligations.”
 
At closing, after the Peruvian governmental approvals are obtained, the Company expects Pacific Rubiales to exchange these loans along with an additional $85.0 million, plus any other amounts due to the Company or from the Company under the SPA, for the interests and assets obtained from the Company under the SPA and under the Block Z-1 License Contract.  If, among certain other events, the Peruvian government does not approve Pacific Rubiales to become a party to the license contract, the SPA will terminate.  If the SPA is terminated and certain provisions regarding fault of the parties do not apply, the $65.0 million paid and any amounts advanced to the Company for capital and exploratory expenditures will be converted into an interest bearing loan, accruing interest after the termination date at the rate of three month LIBOR plus 9%.  The Company shall be obligated to repay such amounts together with a termination value, calculated pursuant to the SPA, to Pacific Rubiales in accordance with the repayment schedule as specified in the SPA.  At closing, operating revenues and expenses will also be allocated to each partner’s respective participating interest.
 
In addition to the SPA, the Company, through its subsidiaries, entered into a related Joint Operating Agreement (“JOA”) and various other agreements which define the parties’ respective rights and obligations with respect to their operations under the license contract, pending necessary Peruvian government approvals.  These other agreements will be ratified by the parties at a closing to occur after receipt of the necessary approval.  The JOA governs other legal, technical, and operational rights and obligations of the parties with respect to the joint operations of Block Z-1.   Under terms of the JOA, BPZ E&P will be the operator of the Block Z-1 License Contract and will retain a 51% participating interest, while Pacific Rubiales assumes a 49% participating interest. After closing, Pacific Rubiales will manage the technical and operational duties in Block Z-1 under a services contract with BPZ E&P. BPZ E&P will carry out administrative, regulatory, government and community related duties. The JOA will continue for the term of the license contract and thereafter until all decommissioning obligations under the license contract have been satisfied.
 
Note 19 — Legal Proceeding
 
Navy Tanker Litigation
 
On October 24, 2007, Tecnomarine SAC, a contractor to BPZ E&P, entered into two short-term agreements with the Peruvian Navy’s commercial branch to charter two small tankers for use in the Company’s offshore oil production operation.  On January 30, 2008, one of the tankers, the Supe, sank after catching fire. Neither of the Peruvian governmental agencies charged with investigating the incident found fault with Tecnomarine SAC or the Company’s subsidiary, BPZ E&P.  A lawsuit was nonetheless filed on December 18, 2008 in the 152nd Judicial District Court of Harris County, Texas by two crewmembers and the family and estate of two deceased sailors injured in the incident, claiming negligence and gross negligence on the part of BPZ Resources, Inc. and BPZ Energy, LLC, parent entities of BPZ E&P, that were not parties to the charter agreement and were not involved in the operations.
 
On May 8, 2012, the 152nd Judicial District Court of Harris County, Texas dismissed Plaintiffs’ lawsuit against BPZ Resources, Inc. and BPZ Energy, LLC granting defendants’ motion to dismiss on the basis of forum non conveniens.  The order is conditioned upon the Peruvian Courts accepting jurisdiction over the matter.
 
Based on the Company’s assessment of the available facts, including the fact that none of the Peruvian government-sanctioned investigations into the Supe incident found fault on the part of Tecnomarine or BPZ E&P, the Company does not believe the outcome of the legal proceeding will have a material adverse effect on its financial condition, results of operations or cash flows. The Company will continue to vigorously defend this action in the Peruvian Courts but cautions that there is inherent risk in litigation, which is difficult to quantify, especially at the early stage of litigation proceedings. In any event, the Company believes that any monetary damages arising from the incident would be adequately covered by its insurance policies, after a customary deductible.
 
 
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From time to time, the Company may become a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, the Company is not currently a party to any proceeding that it believes could have a potential material adverse effect on its financial condition, results of operations or cash flows.
 
Additionally, the Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

Note 20 — Subsequent Events

The $75.0 million secured debt facility was amended on July 30, 2012, to extend the date for receiving the environmental permit to allow commissioning of the permanent production facilities and entering into commercial production at the Albacora field from July 31, 2012 to November 30, 2012.
 
 
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

You should read the following discussion and analysis together with our consolidated financial statements and notes thereto and the discussion contained in Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations,”  Item 7A., “Quantitative and Qualitative Disclosures About Market Risk” included in our Annual Report on Form 10-K as updated in Part I, Item 3., of this Quarterly Report on Form 10-Q for the period ended June 30, 2012 and Item 1A.,“Risk Factors,” included in our Annual Report on Form 10-K for the year ended December 31, 2011, as updated in Part II, Item 1A, of the Quarterly Report on Form 10-Q for the period ended March 31, 2012.

           The following information contains forward-looking statements that involve risks, uncertainties and assumptions.  Should one or more of these risks or uncertainties materialize, our actual results may differ from those expressed or implied by the forward-looking statements.  See “Disclosure Regarding Forward-Looking Statements” below.  Also, see “Cautionary Statement Regarding Certain Information Releases” below for material related to the release of certain information.
 
BPZ Resources, Inc., a Texas corporation, is based in Houston, Texas with offices in Lima, Peru and Quito, Ecuador. We are focused on the exploration, development and production of oil and natural gas in Peru and to a lesser extent Ecuador. We also intend to utilize part of our planned future natural gas production as a supply source for the complementary development of a gas-fired power generation facility in Peru which we expect to wholly- or partially-own.
 
We maintain a subsidiary, BPZ Exploración & Producción S.R.L. (“BPZ E&P”),  registered in Peru through our subsidiary BPZ Energy, LLC, a Texas limited liability company,  and our wholly-owned subsidiary BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership.  Currently, we, through BPZ E&P, have exclusive rights and license contracts for oil and gas exploration and production covering a total of approximately 2.2 million acres, in four blocks, in northwest Peru. Our license contracts cover 100% ownership of the following properties: Block Z-1 (0.6 million acres), Block XIX (0.5 million acres), Block XXII (0.9 million acres) and Block XXIII (0.2 million acres). The Block Z-1 contract was signed in November 2001, the Block XIX contract was signed in December 2003 and the Blocks XXII and XXIII contracts were signed in November 2007.  Generally, according to the Organic Hydrocarbon Law No. 26221 and the regulations thereunder (the “Organic Hydrocarbon Law” or “Hydrocarbon Law”), the seven-year term for the exploration phase can be extended in each contract by an additional three years up to a maximum of ten years. However, specific provisions of each license contract can vary the exploration phase of the contract as established by the Hydrocarbon Law.  The license contracts require us to conduct specified activities in the respective blocks during each exploration period in the exploration phase. If the exploration activities are successful, we may decide to enter the exploitation phase and our total contract term can extend up to 30 years for oil exploration and production and up to 40 years for gas exploration and production.  In the event a block contains both oil and gas, as is the case in our Block Z-1, the 40-year term may apply to oil exploration and production as well.
 
Additionally, through our wholly-owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, we own a 10% non-operating net profits interest in an oil and gas producing property, Block 2, located in the southwest region of Ecuador (the “Santa Elena Property”). The agreement covering the property extends through May 2016.
 
On April 27, 2012, we and Pacific Rubiales Energy Corp. (together with its subsidiaries, collectively “Pacific Rubiales”) executed a Stock Purchase Agreement (“SPA”) under which we formed an unincorporated joint venture relationship with Pacific Rubiales to explore and develop the offshore Block Z-1 located in Peru.  Pursuant to the SPA, Pacific Rubiales agreed to pay $150.0 million for a 49% participating interest in Block Z-1 and agreed to fund $185.0 million of our share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012.   In order to finalize the joint venture, Peruvian governmental approvals are needed to allow Pacific Rubiales to become a party to the Block Z-1 License Contract.  Until the required approvals are obtained, Pacific Rubiales has agreed to provide us these and other funds as loans to continue to fund our Block Z-1 capital and exploratory activities.  See Block Z-1 Transaction below for additional details on the joint venture.
 
 We are in the process of developing our Peruvian oil and natural gas reserves.  We placed the Corvina field into commercial production in November 2010.  We are currently in the process of fabricating a new platform for installation in the Corvina field to continue the development of the Corvina field.  We are also in the initial stages of exploring, appraising and developing our potential oil and natural gas reserves from the A platform in the Albacora field of Block Z-1.  We began producing from the A-14XD well in December 2009 and began selling oil from the A-14XD well under a well testing program during the second quarter of 2010.  We have installed all of the equipment necessary for the reinjection of gas and water at the Albacora platform, completed tie-ins and tested the equipment, and are working on the final environmental permit to allow us to commission the equipment to start up injection in Albacora.  In the meantime, we have obtained a permit that allows us to flare gas from the A-14XD, A-13E and A-9G wells through December 28, 2012.  From the time we began producing from the CX-11 platform in the Corvina field in November 2007 and the Albacora field in December 2009, through June 30, 2012, we have produced approximately 5.4 MMBbls of oil.
 
 
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At December 31, 2011, we had estimated net proved oil reserves of 34.7 MMBbls, of which 27.8 MMBbls were in the Corvina field and 6.9 MMBbls were from the Albacora field. Both fields are located in Block Z-1 offshore of northwest Peru.  Of our total proved reserves, 6.6 MMBbls (19.0%) are classified as proved developed reserves, which includes both proved developed producing and proved developed non-producing reserves, consisting of 12 wells, and 28.1 MMBbls (81.0%) are classified as proved undeveloped reserves.  The process of estimating oil and natural gas reserves is complex and requires many assumptions that may turn out to be inaccurate. 
 
Our current activities and related planning are focused on the following objectives:
 
·
Optimizing oil production in the Corvina field in Block Z-1 that is now in commercial production;
 
·
Completing fabrication of a new drilling and production platform (the CX-15) to be installed in September 2012 to continue development in the Corvina field;
 
·
Planning an offshore drilling campaign to begin once the installation of the CX-15 platform is complete;
 
·
Conducting a three dimensional (“3-D”) seismic survey in Block Z-1 to assess the viability of further exploration and development activity within the block;
 
·
Commissioning permanent production and injection facilities on the Albacora platform for gas and water injection;
 
·
Continuing acquisition, processing and interpretation of seismic data both onshore and offshore to better understand the characteristic and potential of our properties;
 
·
Planning an on-shore drilling campaign to explore and appraise our properties and meet our applicable license requirements;
 
·
 
Identifying potential partners for our other operations; and
 
·
Continuing development of our gas-to-power project to monetize our natural gas reserves, which we have identified in Corvina, but for which no market has yet been secured and related financing has yet to be obtained.
 
Our activities in Peru also include analysis and evaluation of technical data on our properties, preparation of the development plans for the properties, meeting requirements under the license contracts, procuring equipment for an extended drilling campaign, obtaining all necessary environmental, technical and operating permits, optimizing current production and obtaining preliminary engineering and design of the power plant and gas processing facilities.
 
Our Business Plan
 
Our business plan is to enhance shareholder value through application of our knowledge of our targeted areas in Peru and to leverage management’s experience with the local suppliers and regulatory authorities to effectively and efficiently (i) identify and quantify the potential value of our oil and gas holdings in Peru; (ii) develop and increase production and cash flows from our identified holdings; (iii) create an additional revenue stream through implementation of our gas market strategy; and (iv) bring working interest partners into some or all of our Peruvian blocks to facilitate the exploration and development of these blocks.
 
Our focus is to reappraise and develop properties that we control under license agreements in northwest Peru that have been explored by other companies that have reservoirs that appear to contain commercially productive quantities of oil and gas, as well as other areas that have geological formations that we believe potentially contain commercial amounts of hydrocarbons.
 
Our management team has extensive engineering, geological, geophysical, technical and operational experience and extensive knowledge of oil and gas operations throughout Latin America and, in particular, Peru.
 
 
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Two of the four blocks (Block Z-1 and Block XXIII) contain structures drilled by previous operators who encountered hydrocarbons. However, at the time the wells were drilled, the operators did not consider it economically feasible to produce those hydrocarbons.  Having tested oil in our offshore Block Z-1 in our first wells in the Corvina field in 2007, and our first well in Albacora in December 2009, we are initially focusing on development of the proved oil reserves in those two fields.  In June 2011, we drilled our first onshore well in Block XIX. The well tests yielded low rates of oil to surface with high water content of low-salinity.  In December 2011, we determined that this well had no further utility and therefore, declared the well a dry hole.  We are planning to acquire additional seismic data before considering further drilling activity in this block.
 
In the near term, management is focused on completing the fabrication of and installing the new platform, the CX-15, as well as obtaining related permits to allow continued development of the Corvina field, conducting a 3-D seismic survey in Block Z-1 to optimize our future activities in that location, obtaining appropriate financing for our exploration and development programs and maximizing the value of the acreage we hold for exploration.  To help achieve this last objective, we have hired a financial advisor, Credit Suisse Securities (USA) LLC, to assist us in pursuing joint venture partnerships and/or, farm-outs for some or all of our assets and to assist in identifying and evaluating options for financing our operations in northwest Peru.
 
In June 2011, we announced the start of a process to identify and select a potential partner for our offshore Block Z-1.  In April 2012, we announced the formation of an unincorporated joint venture, subject to certain closing conditions and approvals, with Pacific Rubiales to explore and develop offshore Block Z-1 in Peru.   See Block Z-1 Transaction below for additional details on the joint venture.
 
The data room for Blocks XIX and XXIII is now open, with Credit Suisse Securities (USA) LLC managing the formal process to find a joint venture partner for these onshore blocks.  Interested partners have been invited to begin reviewing the data.  The two blocks comprise over 800,000 acres and hold both oil and gas potential, with Block XXIII bordering the northern part of the prolific Talara oil fields.

In addition, our business plan includes a gas-to-power project as part of our overall gas marketing strategy, which entails the installation of a 10-mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and the building of an approximately 135 megawatt (“MW”) simple cycle electric generating plant. The proposed power plant site is located adjacent to an existing substation and power transmission lines which, with certain upgrades, are expected to be capable of handling up to 420 MW of power. We currently plan to wholly- or partially-own this power generation facility. The gas-to-power project is planned to generate a revenue stream by creating a market for the gas discovered in our Corvina field that is currently shut-in or being reinjected.  This project has not yet been financed and we continue to consider the best alternatives for the project. Meanwhile, we have obtained certain permits and are in the process of obtaining additional permits to move the project forward.
 
Extended Well Testing Program
 
We began producing oil under well-testing permits from the Albacora field in December 2009.  During the first half of 2012, the Peruvian Ministry of Energy and Mines (MEM) granted an extension of the gas flaring permit for the our Albacora field operations through December 28, 2012, allowing oil production testing to continue until we receive the required environmental permit for gas injection.  In addition, our request was granted by the General Directorate of Hydrocarbons (“DGH”) to permit testing on the A-12F well to allow a determination to be made whether to use this well as either a gas injector or oil producer.

With respect to any additional Extended Well Test (“EWT”) and gas flaring permits that are requested, we can give no assurance that the DGH or the Ministry of Energy and Mines will grant approval of any current or future permits requested by us. 

Oil Development

 General
 
We plan to conduct additional drilling activities based in part on an ongoing assessment of economic efficiencies, license contract requirements, likely success and logistical issues such as scheduling, required maintenance and replacement of equipment.  This assessment could result in increased emphasis and activities on a given prospect and conversely, could result in decreased emphasis on a given prospect for a period of time.  In particular, we will assess allocation of our current resources among the Corvina, Albacora, and other Block Z-1 prospects and certain onshore prospects as they develop, along with our gas-to-power project.

 
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Seismic Data Acquisition
 
Seismic acquisition activity is 80% complete in Block Z-1.  A second boat is being contracted to enable seismic acquisition of certain remaining areas given that the CGGVeritas Vantage vessel was unable to safely navigate the restricted waters between the platforms and shore due to high fishing vessel traffic and unusual currents.  Bids have been received for processing the seismic data acquired to date.  Fugro Seismic Services was selected to process the 3-D seismic data for Block Z-1.  Processing the 3-D seismic began in the last week of June.  The 3-D seismic acquisition on the remaining areas of Block Z-1 is expected to recommence in August, with completion expected in the fourth quarter of 2012.
 
Block Z-1
 
Block Z-1 Transaction

On April 27, 2012, we and Pacific Rubiales executed a SPA under which we formed an unincorporated joint venture relationship with Pacific Rubiales to explore and develop the offshore Block Z-1 located in Peru.  Pursuant to the SPA, Pacific Rubiales agreed to pay $150.0 million for a 49% participating interest in Block Z-1 and agreed to fund $185.0 million of our share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012.
 
In order to finalize the joint venture, Peruvian governmental approvals are needed to allow Pacific Rubiales to become a party to the Block Z-1 License Contract. Until the required approvals are obtained, Pacific Rubiales has agreed to provide us financing in the form of loans to continue to fund our Block Z-1 capital and exploratory activities. Except in the event of a termination, the loans will not accrue interest.  During the period from April 27, 2012 through June 30, 2012, we obtained an initial loan of $65.0 million and additional loans of $76.7 million for capital and exploratory activities.  For further information regarding our debt, see Note 9, “Debt and Capital Lease Obligations.”

At closing, after the Peruvian governmental approvals are obtained, we expect Pacific Rubiales to exchange these loans along with an additional $85.0 million, plus any other amounts due to us or from us under the SPA, for the interests and assets obtained from us under the SPA and under the Block Z-1 License Contract.  If, among certain other events, the Peruvian government does not approve Pacific Rubiales to become a party to the license contract, the SPA will terminate.  If the SPA is terminated and certain provisions regarding fault of the parties do not apply, the $65.0 million paid and any amounts advanced to us for capital and exploratory expenditures will be converted into an interest bearing loan, accruing interest after the termination date at the rate of three month LIBOR plus 9%.  We shall be obligated to repay such amounts together with a termination value, calculated pursuant to the SPA, to Pacific Rubiales in accordance with the repayment schedule as specified in the SPA.  At closing, operating revenues and expenses will also be allocated to each partner’s respective participating interest.
 
In addition to the SPA, we, through our subsidiaries, entered into a related Joint Operating Agreement (“JOA”) and various other agreements which define the parties’ respective rights and obligations with respect to their operations under the license contract, pending necessary Peruvian government approvals.  These other agreements will be ratified by the parties at a closing to occur after receipt of necessary approval.  The JOA governs other legal, technical, and operational rights and obligations of the parties with respect to the joint operations of Block Z-1.   Under terms of the JOA, BPZ E&P will be the operator of the Block Z-1 License Contract and will retain a 51% participating interest, while Pacific Rubiales assumes a 49% participating interest. After closing Pacific Rubiales will manage the technical and operational duties in Block Z-1 under a services contract with BPZ E&P. BPZ E&P will carry out administrative, regulatory, government and community related duties. The JOA will continue for the term of the license contract and thereafter until all decommissioning obligations under the license contract have been satisfied.
 
Corvina Field
 
We originally began producing oil from the CX-11 platform, located in the Corvina field within the offshore Block Z-1 in northwest Peru, under a well testing program that started on November 1, 2007.  The Corvina field was placed into commercial production on November 30, 2010.  The Corvina field consists of approximately 47,000 acres in water depths of less than 300 feet.  In West Corvina, which consists of 3,500 acres, we have completed a total of nine oil wells, the CX11-23D, the CX11-22D, the CX11-17D, the CX11-19D, the CX11-15D, the CX11-21XD, the CX11-20XD, the CX11-18XD and the CX11-14D wells, some of which are currently being used as gas injection and/or water injection wells.  Produced oil is kept in production inventory until such time that it is delivered to the refinery.  The oil is delivered by vessel to storage tanks at the refinery in Talara, owned by the Peruvian national oil company, Petroleos del Peru – PETROPERU S.A. (“Petroperu”), which is located 70 miles south of the platform.    
 
 
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In the first six months of 2012, the Corvina gas cap reinjection program has shown positive results.  This gas cap reinjection program has been combined with ongoing artificial lift measures at both fields to optimize our oil production.  Corvina's CX-11 platform will undergo a new six-well workover program at an estimated cost of $12 million to optimize production. The workover program, among other objectives, is intended to correct a mechanical problem in one of the two active CX-11 gas reinjection wells that is affecting the performance of two oil producing wells. This mechanical problem started in early July 2012, and has reduced the field's production to approximately 2,000 bopd. This workover program will begin in early August 2012 as the contracted workover rig is currently being mobilized to the CX-11 platform.
 
Fabrication of the new CX-15 platform has been completed in the Wison Nantong yard in China. As previously announced the CX-15 platform has 24 drilling slots and comes with all of the required production and reinjection equipment. Additional ancillary equipment is being shipped to Peru for installation at Corvina, as planned.
 
Load out of the new CX-15 platform is expected to begin at the end of July 2012, after arrival of the Norwegian flagged Osprey transport vessel, part of the Offshore Heavy Transport Company fleet. Load out is expected to take up to 10 days, with the Osprey expected to sail out with the CX-15 platform the week of August 5, 2012. It is estimated that the Osprey will take about four to five weeks to arrive offshore Peru, which would then allow for the CX-15 platform installation in the second half of September 2012. The corresponding drilling and operational permit is expected to be obtained prior to mobilizing the contracted drilling rig into the CX-15 platform, with commencement of the new drilling campaign scheduled for October 2012.

Further, we are working on obtaining and installing a Lease Automatic Custody Transfer (“LACT”) unit at the Corvina field to meet the agreed date to comply with applicable regulations.  We expect to obtain and install the LACT unit in early 2013.
 
Albacora Field

The Albacora field is located in the northern part of our offshore Block Z-1 in northwest Peru.  The current area of interest within the Albacora field is a mapped structure of approximately 7,500 acres and is located in water depths of less than 200 feet. We have been producing oil from the Albacora field since December 2009.  Exploratory drilling at the Albacora field was suspended following the results of the A-17 well in 2010, and returning to development is contingent upon the results of the 3D seismic survey in the Z-1 block.

Installation of the Albacora gas and water reinjection equipment was completed and the equipment was ready for reinjection start up early in the first quarter of 2012.  We completed tie-ins and tested the equipment, and are working on the final environmental permit to allow for commissioning of equipment to start use of the permanent facilities at Albacora.  In the interim, we have received permits to flare gas until December 28, 2012.
 
Block XIX
 
We have received approval from Perupetro S.A. (“Perupetro”) to conduct a limited 3-D seismic survey as part of our minimum work commitment for the fourth exploration period to further evaluate future drilling locations.  An environmental assessment is currently being prepared to obtain an environmental permit for the additional seismic work.
 
Block XXII

As a result of the 2-D seismic survey completed in 2011, three prospects and one lead have been defined.  Evaluation continues and we expect to develop a detailed assessment of each prospect in order to define their technical merit and risk to determine their exploration potential.

We have notified Perupetro that the commitment for the second exploration period will be the drilling of one well.  The timing of the actual drilling will depend on approval of the environmental permit, which is currently being prepared, and subsequent receipt of the necessary ancillary permits.  Drilling on Block XXII is expected no earlier than 2013.

 
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Block XXIII
 
We have begun the process to obtain environmental permits for the potential drilling of several prospects identified by the 2-D and 3-D seismic data acquired in 2011 on Block XXIII.  Drilling on Block XXIII is expected no earlier than 2013.
 
Gas-to-Power Project
 
Our gas-to-power project entails the planned installation of an approximately 10-mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and a 135 megawatt (“MW”) net simple-cycle power generation facility.  The proposed power plant site is located adjacent to an existing substation near Zorritos and a 220 kilovolt transmission line which, after the Peruvian government completes its expansion, is expected to be capable of handling up to 420 MW of power.  The existing substation and transmission lines are owned and operated by third parties.
 
In order to support our proposed electric generation project, we commissioned an independent power market analysis for the region. The Peruvian electricity market is deregulated and power is transported through an interconnected national grid managed by the Committee for Economic Dispatching of Electricity (“COES”).  Based on this study, we believe we will be able to sell, under contract, economic quantities of electricity from the initial 135 MW power plant.  The market study also indicates that there may be future opportunities for us to generate and sell significantly greater volumes of power into the Peruvian and possibly Ecuadorian power markets.  Accordingly, the revenues from the natural gas delivered to the power plant will be derived from the sale of electricity.
 
We currently estimate the gas-to-power project will cost approximately $153.5 million, excluding working capital and 18% value-added tax which will be recovered via future revenue billings.  The $153.5 million includes $133.5 million for the estimated cost of the power plant and $20.0 million for the natural gas pipeline.  While we have held initial discussions with several potential joint venture partners for the gas-to-power project, in an attempt to secure additional financing and other resources for the project, we have not entered into any definitive agreements with a potential partner.  In the event we are able to identify and reach an agreement with a potential joint venture partner, we may only retain a minority position in the project.  However, we, along with our Block Z-1 partner, expect to retain the responsibility for the construction and ownership of the pipeline. If we are unable to identify and reach an agreement with a potential joint venture partner for the gas-to-power project, we may move the project forward to completion without a partner.  We have obtained certain permits and are in the process of obtaining additional permits to move the project forward.
 
Financing Activities
 
$75.0 Million Secured Debt Facility
 
In April 2012, we, through our subsidiaries, entered into an amendment of the $75.0 million secured debt financing (the “$75.0 million secured debt facility”) with Credit Suisse.  Pursuant to the amendment, we made a $40.0 million voluntary principal prepayment, together with accrued and unpaid interest, of the $75.0 million secured debt facility. In connection with the prepayment, we incurred a prepayment fee of $5.8 million payable in four equal installments, the first of which was paid on the prepayment date and the remaining of which will be paid on the specified interest payment dates in July 2012, October 2012 and January 2013.  The amendment to the $75.0 million secured debt facility also extended the maturity of the facility to July 2015, with revised principal repayments due in quarterly installments that range from $2.0 million to $4.5 million commencing in January 2013 and extending through July 2015. 
 
$40.0 Million Secured Debt Facility
 
Also, in April 2012, we, through our subsidiaries, entered into an amendment to the $40.0 million secured debt financing (the “$40.0 million secured debt facility”) with Credit Suisse.  The amendment sets a revised principal repayment schedule such that we are scheduled to repay the outstanding principal amount of each loan in eleven consecutive quarterly installments on the respective payment dates beginning in July 2012, thereby extending the maturity to January 2015.  The $40.0 million secured debt facility has a revised annual interest rate of the three month LIBOR rate plus 8%.

Pacific Rubiales Loans
 
In order to finalize the joint venture, Peruvian governmental approvals are needed to allow Pacific Rubiales to become a party to the Block Z-1 License Contract.  Until the required approvals are obtained, Pacific Rubiales has agreed to provide financing to us in the form of loans to continue to fund our Block Z-1 capital and exploratory activities.  Except in the event of a termination of the unincorporated joint venture arrangement, the loans will not accrue interest.  During the period from April 27, 2012 through June 30, 2012, we obtained an initial loan of $65.0 million and additional loans of $76.7 million for capital and exploratory activities.  For further information regarding debt, see Note 9, “Debt and Capital Lease Obligations.”
 
 
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Results of Operations

The following table sets forth revenues and operating expenses for the three and six months ended June 30, 2012 and 2011:

   
Three Months Ended
June 30,
         
Six Months Ended
June 30,
       
   
2012
   
2011
   
Increase/ (Decrease)
   
2012
   
2011
   
Increase/ (Decrease)
 
Net sales volume:    
(in thousands except per bbl information)
             
(in thousands except per bbl information)
         
Oil (MBbls)
    324       336       (12 )     658       731       (73 )
                                                 
Net revenue:
                                               
Oil revenue, net
  $ 32,679     $ 35,646     $ (2,967 )   $ 69,154     $ 73,362     $ (4,208 )
Other revenue
    2       1,293       (1,291 )     80       2,282       (2,202 )
Total net revenue
    32,681       36,939       (4,258 )     69,234       75,644       (6,410 )
                                                 
Average sales price (approximately):                                                
Oil (per Bbl)
  $ 101.00     $ 106.12     $ (5.12 )   $ 105.14     $ 100.41     $ 4.73  
                                                 
Operating and administrative expenses:                                                
Lease operating expense
    12,694       7,521       5,173       24,062       18,273       5,789  
General and administrative expense
    10,425       9,276       1,149       17,556       18,307       (751 )
Geological, geophysical and engineering expense
    2,442       1,462       980       26,732       7,719       19,013  
Depreciation, depletion and amortization expense
    11,648       9,231       2,417       23,154       19,277       3,877  
Standby costs
    1,409       492       917       2,599       2,821       (222 )
Other expense
    756       -       756       756       -       756  
Total operating and administrative expenses
  $ 39,374     $ 27,982     $ 11,392     $ 94,859     $ 66,397     $ 28,462  
                                                 
Operating income (loss)
  $ (6,693 )   $ 8,957     $ (15,650 )   $ (25,625 )   $ 9,247     $ (34,872 )
 
Net Oil Revenue
 
On November 30, 2010, we placed the Corvina field into commercial production. Prior to that time all oil sales were from oil produced under the Peruvian well testing regulations.  Additionally, all oil sales from the Albacora field were from oil produced under Peruvian well testing regulations.

For the three months ended June 30, 2012, our net oil revenue decreased by $2.9 million to $32.7 million from $35.6 million for the same period in 2011.  The decrease in net oil revenue is due to a decrease in the amount of oil sold of 12 MBbls, and by a decrease of $5.12, or 4.8%, in the average per barrel sales price received.

For the six months ended June 30, 2012, our net oil revenue decreased by $4.2 million to $69.2 million from $73.4 million for the same period in 2011.  The decrease in net oil revenue is due to a decrease in the amount of oil sold of 73 MBbls, partially offset by an increase of $4.73, or 4.7%, in the average per barrel sales price received.

The price/volume analysis of our sales revenues for the three and six months ended June 30, 2012 compared to the three and six months ended June 30, 2011 is as follows:

   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
(in thousands)
 
2011 Oil revenue, net
  $ 35,646     $ 73,362  
Changes associated with sales volumes
    (1,310 )     (7,318 )
Changes associated with prices
    (1,657 )     3,110  
2012 Oil revenue, net
  $ 32,679     $ 69,154  
 
For the three months ended June 30, 2012, we had consistent oil production from eight producing wells and intermittent production from three wells.  During the same period in 2011, we had consistent oil production from five producing wells and intermittent production from one well.  Total oil production for the three months ended June 30, 2012 was 323 MBbls compared to 377 MBbls for the same period in 2011.  Total sales for the three months ended June 30, 2012 were 324 MBbls compared to 336 MBbls for the same period in 2011.
 
 
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For the six months ended June 30, 2012, we had consistent oil production from eight producing wells and intermittent production from three wells.  During the same period in 2011, we had consistent oil production from five producing wells and intermittent production from one well.  Total oil production for the six months ended June 30, 2012 was 676 MBbls compared to 752 MBbls for the same period in 2011.  Total sales for the six months ended June 30, 2012 were 658 MBbls compared to 731 MBbls for the same period in 2011.

The decrease in oil production is due to higher than expected decline rates in oil production in the Corvina field, partially offset by higher oil production from the Albacora field.

The revenues above are reported net of royalties owed to the government of Peru.  Royalties are assessed by Perupetro as stipulated in the Block Z-1 License Contract based on production levels.  However, the royalty calculation is based on the prior five-day average of a blend of crude oil prices before the crude oil delivery date, as opposed to the price we receive for oil which is based on the prior two-week average of a blend of crude oil prices before the crude oil delivery date.  For both the three and six months ended June 30, 2012, the revenues we received are net of royalty costs of approximately 5% of gross revenues or $1.7 million and $3.8 million, respectively.  For the same periods in 2011, the revenues we received are net of royalty costs of approximately 5% of gross revenues or $1.9 million and $3.9 million, respectively.
 
Other Revenue
 
During 2011, another operator chartered two of our support vessels, the BPZ-02 and Don Fernando, for a one-year term.  The operator chartering the vessels returned the Don Fernando in September 2011 and the BPZ-02 in January 2012.  For the three and six months ended June 30, 2012, we recognized an immaterial amount and $0.1 million, respectively, of other revenue associated with the chartering of those vessels.  For the three and six months ended June 30, 2011, we recognized $1.3 million and $2.3 million, respectively, of other revenue associated with the chartering of those vessels.

Lease Operating Expense

Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities, as well as crude oil transportation.  These costs include, among others, workover expenses, maintenance and repair expenses, operator fees, processing fees, insurance and transportation expenses.
 
For the three months ended June 30, 2012, lease operating expenses increased by $5.2 million to $12.7 million ($39.24 per Bbl) from $7.5 million ($22.39 per Bbl) for the same period in 2011.  The increase in the lease operating expenses is due to increased repair and maintenance expenses of $2.4 million, increased contract services of $1.1 million, increased equipment rental expense of $0.5 million, increased salaries expense of $0.3 million, increased fuel costs of $0.2 million and increased other lease operating expenses of $0.7 million.

For the six months ended June 30, 2012, lease operating expenses increased by $5.8 million to $24.1 million ($36.58 per Bbl) from $18.3 million ($25.01 per Bbl) for the same period in 2011.  The increase in the lease operating expenses is due to increased repair and maintenance expenses of $3.4 million, increased contract services of $1.7 million, increased equipment rental expense of $0.8 million, increased fuel costs of $0.5 million, increased salaries expense of $0.5 million and increased other lease operating expenses of $0.7 million.  Partially offsetting these increases to expense are decreases in the lease operating costs associated with oil inventory of $1.8 million.

The following details the significant items contributing to the increase of $5.2 million for the three months ended June 30, 2012 compared to June 30, 2011, and the increase of $5.8 million for the six months ended June 30, 2012 compared to June 30, 2011 of lease operating expenses:
 
Repairs and maintenance: For the three months ended June 30, 2012, repairs and maintenance expense increased $2.4 million compared to the same period in the prior year.  The reason for the increase in repairs and maintenance expense is primarily due to increased platform maintenance, crane maintenance services and support vessel services in the second quarter of 2012 compared to the same period in 2011.
 
For the six months ended June 30, 2012, repairs and maintenance expense increased $3.4 million compared to the same period in the prior year.  The reason for the increase in repairs and maintenance expense is primarily due to increased platform maintenance, crane maintenance services and support vessel services in the first six months of 2012 compared to the same period in 2011.
 
 
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Contract services: For the three months ended June 30, 2012, we had the necessary equipment and production facilities at both the Corvina CX-11 platform and Albacora A-platform to process the oil produced from those fields.  However in the fourth quarter of 2011, we rented hydraulic jet pumps to stimulate and assist oil production in both the Corvina and Albacora fields and continued to use these services in the second quarter of 2012. As a result, contract service costs have increased $1.1 million for the quarter ended June 30, 2012.

For the six months ended June 30, 2012, we had the necessary equipment and production facilities at both the Corvina CX-11 platform and Albacora A-platform to process the oil produced from those fields.  However in the fourth quarter of 2011, we rented hydraulic jet pumps to stimulate and assist oil production in both the Corvina and Albacora fields and continued to use these services in the first six months of 2012. As a result, contract service costs have increased $1.7 million for the six months ended June 30, 2012.
 
Transfers of costs to/from oil inventory: During the six months ended June 30, 2012, approximately $1.3 million of oil inventory costs were removed from lease operating expense as we produced more oil (676 MBbls), than we sold (658 MBbls), resulting in a buildup of oil inventory due to the timing of oil delivered to the refinery.  In the same period in 2011, approximately $0.5 million of oil inventory costs were added to our lease operating expense as we sold the remaining Albacora oil that had higher costs associated with those specific inventory barrels as they required salt content treatment in order to meet sales specifications.  Therefore, there is a net decrease from the first six months in 2012 versus the same period in 2011 in lease operating expense of $1.8 million as a result of the transfers of oil inventory costs between the two periods.

General and Administrative Expense

General and administrative expenses are overhead-related expenses, including employee compensation, legal, consulting and accounting fees, insurance, and investor relations expenses.

For the three months ended June 30, 2012, general and administrative expenses increased by $1.1 million to $10.4 million from $9.3 million for the same period in 2011.  Stock-based compensation expense, a subset of general and administrative expenses, decreased by $0.5 million to $0.7 million for the three months ended June 30, 2012 from $1.2 million for the same period in 2011.  The decrease in stock-based compensation expense is due to the vesting of the majority of awards granted in 2008, which were granted at times when the grant date fair value of the awards was higher due to the then higher price of our common stock.  As a result, our stock-based compensation expense declined since a majority of these older awards vested prior to the second quarter of 2012 and these are not contributing as much expense as compared to the same period in 2011.  Other general and administrative expenses increased $1.6 million to $9.7 million from $8.1 million for the same period in 2011.  The $1.6 million increase is due to higher third party costs primarily related to the Block Z-1 transaction of $1.1 million and higher non-income taxes of $0.7 million, partially offset by other lower general and administrative expenses in 2012 of $0.2 million.

For the six months ended June 30, 2012, general and administrative expenses decreased by $0.8 million to $17.5 million from $18.3 million for the same period in 2011.  Stock-based compensation expense, a subset of general and administrative expenses, decreased by $1.0 million to $1.4 million for the six months ended June 30, 2012 from $2.4 million for the same period in 2011.  The decrease in stock-based compensation expense is due to the vesting of the majority of awards granted in 2008, which were granted at times when the grant date fair value of the awards was higher due to the then higher price of our common stock.  As a result, our stock-based compensation expense declined since a majority of these older awards vested prior to the first half of 2012 and these are not contributing as much expense as compared to the same period in 2011.  Other general and administrative expenses increased $0.2 million to $16.1 million from $15.9 million for the same period in 2011.  The $0.2 million increase is due to higher third party costs primarily related to the Block Z-1 transaction of $1.1 million and higher non-income taxes of $0.5 million, partially offset by lower salary and related costs of $1.4 million.

 
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Geological, Geophysical and Engineering Expense

Geological, geophysical and engineering expenses include laboratory, environmental and seismic acquisition related expenses.  For the three months ended June 30, 2012, geological, geophysical and engineering expenses increased $0.9 million to $2.4 million compared to $1.5 million for the same period in 2011.  The increase is due to increased seismic acquisition activity associated with our seismic data acquisition plan for Block Z-1 in 2012, compared to our seismic data acquisition plan for Block XXII and Block XXIII in 2011.

For the six months ended June 30, 2012, geological, geophysical and engineering expenses increased $19.0 million to $26.7 million compared to $7.7 million for the same period in 2011.  The increase is due to increased seismic acquisition activity associated with our seismic data acquisition plan for Block Z-1 in 2012, compared to our seismic data acquisition plan for Block XXII and Block XXIII in 2011.

Depreciation, Depletion and Amortization Expense

For the three months ended June 30, 2012, depreciation, depletion and amortization expense increased $2.5 million to $11.7 million from $9.2 million for the same period in 2011.  For the six months ended June 30, 2012, depreciation, depletion and amortization expense increased $3.9 million to $23.2 million from $19.3 million for the same period in 2011.

For the three months ended June 30, 2012, depletion expense increased $1.9 million to $8.2 million from $6.3 million during the same period in 2011 due primarily to a lower reserve base in the Corvina and Albacora fields in 2012.  For the six months ended June 30, 2012, depletion expense increased $2.8 million to $16.3 million from $13.5 million during the same period in 2011 due primarily to a lower reserve base in the Corvina and Albacora fields in 2012.

For the three months ended June 30, 2012, depreciation expense increased $0.6 million to $3.5 million compared to $2.9 million for the same period in 2011 due to increased production equipment and general equipment added toward the end of 2011.   For the six months ended June 30, 2012, depreciation expense increased $1.1 million to $6.9 million compared to $5.8 million for the same period in 2011 due to increased production equipment and general equipment added toward the end of 2011.
 
Standby Costs
 
During 2011, we suspended drilling operations until we complete our seismic data acquisition program and fabrication and installation of the new drilling platform in Block Z-1, which is scheduled for the second half of 2012.  The Petrex-18 rig that was rented to another operator in 2011 was returned to us in January 2012 and is currently on standby.  The contract for the Petrex-18 rig expires in December 2013.  As a result, for the three and six months ending June 30, 2012, we incurred $1.4 million and $2.6 million, respectively, in standby rig costs for the Petrex-18 rig.  The contract for the Petrex-09 rig that was used in the Corvina field and which contributed to standby costs in 2011 expired in January 2012 at which time the rig was returned.  For the three and six months ended June 30, 2011, we incurred $0.5 million and $2.3 million, respectively, in standby rig costs.  Additionally, we incurred $0.5 million of allocated expenses associated with drilling operations for the six months ended June 30, 2011.
 
Other Expense
 
For the three and six months ended June 30, 2012, we reported $0.8 million of abandonment charges in the Consolidated Statements of Operations as “Other expense.”  We accrued $0.8 million of abandonment costs related to a platform in the Piedra Redonda field in Block Z-1, as we are obligated to ensure the platform does not cause a threat to marine vessels operating in the area or marine wildlife. The $0.8 charge is in addition to amounts recorded previously related to the platform abandonment costs in the Piedra Redonda field in the third quarter of 2010.  There were no similar expenses incurred by us in 2011.

Other Income (Expense)

Other income (expense) includes non-operating income items.  These items include interest expense and income, loss on the extinguishment of debt, gains or losses on foreign currency transactions, income and amortization related to the investment in our Ecuador property as well as gains or losses on derivative financial instruments.  For the three months ended June 30, 2012, total other expense decreased $2.1 million to $3.2 million compared to $5.3 million during the same period in 2011.  For the six months ended June 30, 2012, total other expense increased $3.0 million to $15.9 million compared to $12.9 million during the same period in 2011.  The change is due primarily to the following:
 
Interest expense: For the three months ended June 30, 2012, we recognized approximately $4.1 million of net interest expense, which includes $7.8 million of interest expense reduced by $3.7 million of capitalized interest expense.  For the same period in 2011, we recognized $4.9 million in net interest expense which included $6.6 million of interest expense reduced by $1.7 million of capitalized interest.  The decrease of $0.8 million in net interest expense is due to more capitalization of interest for the three month period ended June 30, 2012 compared to the same period in 2011.
 
 
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For the six months ended June 30, 2012, we recognized approximately $10.3 million of net interest expense, which includes $17.0 million of interest expense reduced by $6.7 million of capitalized interest expense.  For the same period in 2011, we recognized $8.6 million in net interest expense which included $13.0 million of interest expense reduced by $4.4 million of capitalized interest.  The increase of $1.7 million in net interest expense for the six month period ended June 30, 2012, compared to the same period in 2011, is due to higher debt outstanding in 2012 compared to the same period in 2011, partially offset by higher capitalized interest expense for the six month period ended June 30, 2012, compared to the same period in 2011.
 
Loss on extinguishment of debt: As a result of the prepayment and amendment to the $75.0 secured debt facility during the second quarter of 2012, we incurred $5.8 million of fees and prepayment penalties and $1.1 million of debt issue costs. The $5.8 million in fees and prepayment penalties were recognized as a “Loss on extinguishment of debt” in the consolidated statement of operations, 25% was paid at the time of the amendment and prepayment and 25% will be paid at the time of each of the next three quarterly interest payment dates ending in January 2013. Approximately $1.5 million of the remaining $2.8 million of unamortized debt issue costs associated with the initial loan was expensed as a “Loss on extinguishment of debt” in the consolidated statement of operations when we prepaid $40.0 million of principal.  For the three and six months ended June 30, 2012, we reported $7.3 million as a loss on extinguishment of debt.
 
Gain (loss) on derivatives: In connection with obtaining the $40.0 million and $75.0 million secured debt facilities in January and July 2011, respectively, we entered into Performance Based Arranger Fees that we are accounting for as embedded derivatives.  As a result of the fair value measurement at June 30, 2012 and 2011, the gain associated with the embedded derivatives increased $8.7 million to a $8.4 million gain for the three months ended June 30, 2012 from a $0.3 million loss for the same period in 2011, and increased $6.6 million to a $2.0 million gain for the six months ended June 30, 2012 from a $4.6 million loss for the same period in 2011.  The reason for the increase in the gain associated with derivatives is the decrease in oil prices during the three and six months ended June 30, 2012 compared to the same periods in 2011.

Income Taxes

The following is a summary of income (loss) before income taxes and income tax expense (benefit) for the three and six months ended June 30, 2012 and June 30, 2011:

   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2012
   
2011
   
2012
   
2011
 
Income (loss) before income taxes:
 
(in thousands)
   
(in thousands)
 
United States
  $ 446     $ (5,692 )   $ (8,345 )   $ (13,119 )
Foreign
    (10,368 )     9,364       (33,178 )     9,434  
 
  $ (9,922 )   $ 3,672     $ (41,523 )   $ (3,685 )
 
                               
                                 
Income tax expense (benefit):
                               
United States
  $ 569     $ 814     $ 979     $ 1,397  
Foreign
    (1,991 )     2,566       (6,711 )     2,719  
 
  $ (1,422 )   $ 3,380     $ (5,732 )