UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: June 30, 2013

or

☐ 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 ☒ No ☐

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 ☒ No ☐

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 ☐	Accelerated filer ☒
Non-accelerated filer ☐	Smaller reporting company ☐
(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 ☐ No ☒

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, 2013, there were 117,820,355 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	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 4.	Controls and Procedures	48
PART II
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 6.	Exhibits	49
SIGNATURES

2

PART I

Item 1. Financial Statements

BPZ Resources, Inc. and Subsidiaries

Consolidated Balance Sheets 

(In thousands)

 

	June 30, 2013			December 31, 2012
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	103,832		$	83,540
Short-term investments		1,000			-
Accounts receivable		8,621			24,523
Income taxes receivable		1,842			-
Value-added tax receivable		14,817			20,569
Inventory		20,069			19,851
Restricted cash		5,010			25,129
Prepaid and other current assets		11,516			5,734
Total current assets		166,707			179,346
Property, equipment and construction in progress, net		228,239			238,557
Restricted cash		4,109			47,670
Other non-current assets		5,201			5,983
Investment in Ecuador property, net		551			632
Deferred tax asset		57,476			55,242
Total assets	$	462,283		$	527,430
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	40,675		$	21,978
Accrued liabilities		19,154			34,013
Other liabilities		21,556			21,792
Current income taxes payable		-			10,460
Accrued interest payable		4,326			5,234
Derivative financial instruments		358			2,984
Current maturity of long-term debt		17,000			24,046
Total current liabilities		103,069			120,507
Asset retirement obligation		2,822			2,708
Other non-current liabilities		20,755			20,755
Long-term debt, net		180,132			197,160
Total long-term liabilities		203,709			220,623
Commitments and contingencies (Note 19 and 20)
Stockholders’ equity:
Preferred stock, no par value, 25,000 authorized; none issued and outstanding		-			-
Common stock, no par value, 250,000 authorized; 117,813 and 116,932 shares issued and outstanding at June 30, 2013 and December 31, 2012, respectively		561,804			560,175
Accumulated deficit		(406,299	)		(373,875	)
Total stockholders’ equity		155,505			186,300
Total liabilities and stockholders’ equity	$	462,283		$	527,430

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,
	2013			2012			2013			2012
Net revenue:
Oil revenue, net	$	12,776		$	32,679		$	26,057		$	69,154
Other revenue		39			2			70			80
Total net revenue		12,815			32,681			26,127			69,234
Operating and administrative expenses:
Lease operating expense		8,102			12,694			14,775			24,062
General and administrative expense		6,451			9,347			11,926			15,547
Geological, geophysical and engineering expense		746			3,520			1,104			28,741
Depreciation, depletion and amortization expense		7,955			11,648			14,859			23,154
Standby costs		2,225			1,409			3,368			2,599
Other expense		-			756			-			756
Total operating and administrative expenses		25,479			39,374			46,032			94,859
Operating loss		(12,664	)		(6,693	)		(19,905	)		(25,625	)
Other income (expense):
Income (loss) from investment in Ecuador property, net		216			(47	)		169			(94	)
Interest expense, net		(4,280	)		(4,080	)		(8,578	)		(10,290	)
Loss on extinguishment of debt		(3,786	)		(7,318	)		(3,786	)		(7,318	)
Gain on derivatives		1,277			8,407			729			2,039
Interest income		38			7			47			10
Other expense		(818	)		(198	)		(1,147	)		(245	)
Total other expense, net		(7,353	)		(3,229	)		(12,566	)		(15,898	)
Loss before income taxes		(20,017	)		(9,922	)		(32,471	)		(41,523	)
Income tax benefit		(377	)		(1,422	)		(47	)		(5,732	)
Net loss	$	(19,640	)	$	(8,500	)	$	(32,424	)	$	(35,791	)
Basic net loss per share	$	(0.17	)	$	(0.07	)	$	(0.28	)	$	(0.31	)
Diluted net loss per share	$	(0.17	)	$	(0.07	)	$	(0.28	)	$	(0.31	)
Basic weighted average common shares outstanding		115,935			115,573			115,862			115,543
Diluted weighted average common shares outstanding		115,935			115,573			115,862			115,543

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,
	2013			2012
Cash flows from operating activities:
Net loss	$	(32,424	)	$	(35,791	)
Adjustments to reconcile net loss to net cash used in operating activities:
Stock-based compensation		1,603			1,420
Depreciation, depletion and amortization		14,859			23,154
Amortization of investment in Ecuador property		81			94
Deferred income taxes		(2,602	)		(6,484	)
Loss on extinguishment of debt		3,786			7,318
Amortization of discount and deferred financing fees		5,071			4,896
Unrealized gain on derivatives		(2,626	)		(2,039	)
Loss on retirement of assets		43			-
Changes in operating assets and liabilities:
Decrease in accounts receivable		16,239			4,017
Decrease in value-added tax receivable		5,489			1,106
Increase in inventory		(236	)		(1,397	)
Increase in other assets		(5,770	)		(3,479	)
Increase in income taxes receivable		-			(18	)
Increase (decrease) in accounts payable		18,696			(8,451	)
Increase (decrease) in accrued liabilities		(11,802	)		915
Decrease in income taxes payable		(11,932	)		-
Decrease in other liabilities		(237	)		(883	)
Net cash used in operating activities		(1,762	)		(15,622	)
Cash flows from investing activities:
Property and equipment additions		(5,403	)		(40,284	)
Decrease in restricted cash		63,680			-
Purchase of investment securities		(1,000	)		-
Net cash provided by (used in) investing activities		57,277			(40,284	)
Cash flows from financing activities:
Borrowings		14,545			141,719
Repayments of borrowings		(46,139	)		(44,735	)
Deferred and other loan fees		(3,654	)		(1,925	)
Proceeds from sale of common stock, net		25			47
Net cash provided by (used in) financing activities		(35,223	)		95,106
Net increase in cash and cash equivalents		20,292			39,200
Cash and cash equivalents at beginning of period		83,540			58,172
Cash and cash equivalents at end of period	$	103,832		$	97,372
Supplemental cash flow information:
Cash paid for:
Interest	$	9,404		$	13,171
Income tax		13,785			653
Non — cash items:
Depletion allocated to production inventory		18			797
Depreciation on support equipment capitalized to construction in progress		-			5
Reclassification of property and equipment to accounts receivable and accrued liabilities		952			-
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, and its subsidiary, BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership. Currently, the Company, through BPZ E&P, has license contracts for oil and gas exploration and production covering a total of approximately 2.2 million gross (1.9 million net) acres, in four blocks in northwest Peru. The Company’s license contracts cover ownership of the following properties: 51% working interest in Block Z-1 (0.6 million gross acres), 100% working interest in Block XIX (0.5 million gross acres), 100% working interest in Block XXII (0.9 million gross acres) and 100% working interest in Block XXIII (0.2 million gross 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, this exploration extension is subject to government approval and 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 production and up to 40 years for gas 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 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 license agreement and operating agreement covering the property was extended in May 2013 from May 2016 through December 2029.

The Company is in the process of developing its Peruvian oil and natural gas resources.  The Company entered commercial production for the Block Z-1 in November 2010 and produces and sells oil from the Corvina and Albacora fields under the Company’s current sales contracts. The Company completed the installation of the new CX-15 platform in the Corvina field to continue the development of the field. In July 2013 the Company spudded the first development well from the new CX-15 platform. The Company is also appraising the potential oil and natural gas reserves from the A platform in the Albacora field of Block Z-1.

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 and (viii) obtaining preliminary engineering and design of the power plant and gas processing and delivery facilities.

On December 14, 2012, Perupetro S.A (“Perupetro”), a corporation owned by the Peruvian government empowered to become a party in the contracts for the exploration and/or exploitation of hydrocarbons in order to promote these activities in Peru, approved the terms of the amendment to the Block Z-1 license contract to recognize the sale of a 49% participating interest (“closing”) in offshore Block Z-1 to Pacific Rubiales Energy Corp. (“Pacific Rubiales”). Under the terms of the agreements signed on April 27, 2012, the Company (together with its subsidiaries) formed an unincorporated joint venture relationship with a Pacific Rubiales subsidiary, Pacific Stratus Energy S.A., to explore and develop the offshore Block Z-1 located in Peru. Pursuant to the agreements, 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 (“the carry amount”) from the effective date of the Stock Purchase Agreement (“SPA”), January 1, 2012. On December 30, 2012, the Peruvian Government signed the Supreme Decree for the execution of the amendment to the Block Z-1 license contract.

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, 2012 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, 2012.

The transfer of a 49% participating interest in Block Z-1 to Pacific Rubiales was effective on December 14, 2012 and the entitlement to crude oil production and sharing of joint operating expenditures from that day forward was allocated to each partner. At closing, the sharing of any production or joint operating expenditures prior to that date for 2012 was treated by the parties as an adjustment to the carry amount under the SPA.

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.

Reclassification 

Certain reclassifications have been made to the 2012 consolidated financial statements to conform to the 2013 presentation. These reclassifications were not material to the accompanying consolidated financial statements.

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, 2012. 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, 2012.

Recent Accounting Pronouncements 

On August 22, 2012, the Securities and Exchange Commission (“SEC”) adopted rules mandated by the Dodd-Frank Act requiring entities who file reports with the SEC and commercially develop oil, natural gas or liquids (“resource extraction issuers”) to disclose certain payments made to the U.S. government and foreign governments. The rules provided guidance on the types of payments and information about payments that must be disclosed. The rules required a resource extraction issuer to disclose the information annually by filing a new form with the SEC (Form SD) no later than 150 days after the end of its fiscal year. A resource extraction issuer would have been required to comply with the new rules for fiscal years ending after September 30, 2013. As a result, beginning in 2014, the rules would have required the Company to annually provide information about the type and total amount of payments made for each project related to the commercial development of oil, natural gas, or minerals, and the type and total amount of payments made to each government. There would have been no impact on the Company's financial position and results of operations, but the new rules would have required additional disclosures in future filings.

7

However, on July 2, 2013, the District Court for the District of Columbia vacated the SEC’s rule requiring resource extraction issuers to disclose payments made to the U.S. government and foreign governments and has ordered the SEC to conduct further proceedings before enacting a new rule. The SEC may appeal the decision to the Circuit Court of Appeals for the District of Columbia. It is not yet entirely clear if the SEC will ultimately be required to rewrite the rule, or when a final rule will be effective. While the result of the decision is that the SEC’s rule requiring resource extraction issuers to disclose payments made to the U.S. government and foreign governments is no longer effective, a rule in some form must be promulgated by the SEC to implement, though the information that is ultimately required to be made public may be more limited.

Note 2 — Divestiture

On April 27, 2012, the Company and Pacific Rubiales (together with its subsidiaries) 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 were needed to allow Pacific Rubiales to become a party to the Block Z-1 License Contract. Until the required approvals were obtained, Pacific Rubiales provided the Company a $65.0 million down payment on the purchase price and other funds which the Company initially accounted for as loans to continue to fund the Company’s Block Z-1 capital and exploratory activities. These amounts were reflected as long-term debt prior to closing the transaction.

On December 14, 2012, Perupetro approved the terms of the amendment to the Block Z-1 license contract to recognize the sale of a 49% participating interest in offshore Block Z-1 to Pacific Rubiales. The Company and Pacific Rubiales waived and modified certain contract conditions in order to close the transaction. On December 30, 2012, the Peruvian Government signed the Supreme Decree for the execution of the amendment to the Block Z-1 license contract.

At closing, Pacific Rubiales exchanged certain 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. Proceeds of $150.0 million (less transaction costs of $5.7 million) less the net book value of the assets resulted in a gain on the sale that was recognized as a component of operating and administrative expenses in connection with the closing of $26.9 million. Due to certain tax benefits resulting from the sale, the after tax gain was $31.1 million.

The transaction provided for an adjustment based upon the collection of revenues ($56.1 million) and the payment of expenses ($32.6 million) and income taxes ($5.2 million) attributable to the properties that took place after an effective date of January 1, 2012 and prior to the closing date which was December 14, 2012. These amounts were considered settled by adjusting down by $18.3 million the unused portion of the agreed carry amount of $185.0 million by Pacific Rubiales for the Company’s share of capital and exploratory expenditures in Block Z-1. The June 30, 2013 and December 31, 2012 carry amounts were $112.0 million and $126.3 million, respectively.

At June 30, 2013 and December 31, 2012, the Company reflected $19.9 million as other current liabilities and $20.8 million as other non-current liabilities for exploratory expenditures related to Block Z-1 under funding by Pacific Rubiales of the exploratory expenditures in Block Z-1 incurred in 2012. This amount will be settled by the Company and Pacific Rubiales under the terms of the SPA.

Note 3 — Receivables, Accounts Payable and Accrued Liabilities

Accounts Receivable

The Company’s accounts receivable amounts include receivables from oil sales. Also included in accounts receivable are amounts due from the Company’s joint venture partner. The June 30, 2013 and December 31, 2012 accounts receivable amounts were $8.6 million and $24.5 million, respectively. At June 30, 2013 and December 31, 2012, accounts receivable included $4.4 million and $15.9 million, respectively, from the Company’s joint venture partner.

8

Income Taxes Receivable and Current Income Taxes Payable

The Company’s June 30, 2013 and December 31, 2012 income tax receivable amounts were $1.8 million and none, respectively. The June 30, 2013 and December 31, 2012 current income taxes payable amounts were none and $10.5 million, respectively.

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 was 19% in previous periods.

The Company is recovering its IGV receivable with IGV payables associated with oil sales under the normal IGV recovery process.

Under the SPA and carry agreement entered into with Pacific Rubiales related to the sale of a 49% participating interest in Block Z-1, Pacific Rubiales funded the IGV incurred for 100% of the capital and exploratory expenditures of Block Z-1. Upon closing of the transaction, the IGV balance related to this funding was transferred to Pacific Rubiales along with their respective share of assets. See Note-2, “Divestiture.”

Activity related to the Company’s value-added tax receivable for the six months ended June 30, 2013 and the year ended December 31, 2012 is as follows:

 

	June 30, 2013			December 31, 2012
	(in thousands)
Value-added tax receivable as of the beginning of the period	$	21,784		$	24,720
IGV accrued related to expenditures during period		7,445			67,846
IGV reduced related to sale of oil during period		(12,934	)		(46,586	)
IGV related to the sale of a 49% participating interest in Block Z-1		-			(24,196	)
Value-added tax receivable as of the end of the period	$	16,295		$	21,784
Current portion of value-added tax receivable as of the end of the period	$	14,817		$	20,569
Long-term portion of value-added tax receivable as of the end of the period	$	1,478		$	1,215

See Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets” for further information on the long-term portion of the value-added tax receivable.

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consist mainly of accounts payable and accrued liabilities related to costs for which goods and services have been received in support of the Company’s oil and gas operations, including drilling operations, seismic, lease operating costs, and amounts payable to the Company’s joint venture partner.

The June 30, 2013 and December 31, 2012 accounts payable amounts were $40.7 million and $22.0 million, respectively. At June 30, 2013 and December 31, 2012, accounts payable included $35.5 million and $4.4 million, respectively, due to the Company’s joint venture partner.    

The June 30, 2013 and December 31, 2012 accrued liabilities amounts were $19.2 million and $34.0 million, respectively.

Note 4 — 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 to make a delivery to the refinery in Talara, Peru.  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.

9

Below is a summary of inventory as of June 30, 2013 and December 31, 2012:

	June 30, 2013		December 31, 2012
	(in thousands)
Tubular goods, accessories and spare parts	$	18,709	$	18,343
Crude oil		1,360		1,508
Inventory	$	20,069	$	19,851

	June 30, 2013		December 31, 2012
Crude oil (barrels)		17,020		17,876
Crude oil (cost per barrel)	$	79.93	$	84.34

Note 5 — Prepaid and Other Current Assets and Other Non-Current Assets

Below is a summary of prepaid and other current assets as of June 30, 2013 and December 31, 2012:

	June 30, 2013		December 31, 2012
	(in thousands)
Prepaid expenses and other	$	9,734	$	4,538
Prepaid insurance		1,027		441
Insurance receivable		755		755
Prepaid and other current assets	$	11,516	$	5,734

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.

Below is a summary of other non-current assets as of June 30, 2013 and December 31, 2012:

	June 30, 2013		December 31, 2012
	(in thousands)
Debt issue costs, net	$	3,723	$	4,768
Value-added tax receivable		1,478		1,215
Other non-current assets	$	5,201	$	5,983

Debt issue costs, net consist of direct transaction costs incurred by the Company in connection with its debt raising efforts less the amortization of the debt issuance costs to date.

In May 2013, the Company prepaid the remaining principal balance on the $75.0 million secured debt facility and amended and restated the $40.0 million secured debt facility (which had been repaid by scheduled principal repayments to $25.5 million) by increasing the facility size and borrowing an additional $14.5 million. In 2012, the Company prepaid $40.0 million on the $75.0 million secured debt facility and amended both the $75.0 million secured debt facility and $40.0 million secured debt facility. The debt issue costs associated with those agreements were modified in accordance with Accounting Standard Codification (“ASC”) Topic 470 as follows:

(1) Prior to the May 2012 $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 were 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. In May 2013, the Company prepaid the remaining principal balance on the $75.0 million secured debt facility and, accordingly, expensed the remaining $1.4 million of unamortized debt issue costs.

10

(2) Prior to the May 2013 amendment and restatement of the $40.0 million secured debt facility, there were $0.6 million of unamortized debt issue costs. In the amendment and restatement of the $40.0 million secured debt facility (which had been repaid by scheduled principal repayments to $25.5 million) associated with the increase in the facility size and borrowing an additional $14.5 million, the Company added $1.8 million of debt issue costs incurred to the remaining unamortized debt issue costs of $0.6 million. The amendment and restatement 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 $40.0 million secured debt facility, ending in January 2015, using the effective interest method.

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 2015 Convertible Notes, using the effective interest method.

The following table is the amount of debt issue costs amortized into interest expense for the three and six months ended June 30, 2013 and 2012:

 

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Amortization of debt issue costs	$	740	$	736	$	1,418	$	1,645
	$	740	$	736	$	1,418	$	1,645

For further information regarding the Company’s debt, see Note-10, “Debt.”

At June 30, 2013 and December 31, 2012, the Company classified $1.5 million and $1.2 million, respectively, of its value-added tax receivable balance as a long-term asset as it believed it would take longer than one year to receive the benefit of this portion of the value-added tax receivable. For further information see Note-3, “Receivables, Accounts Payable and Accrued Liabilities.”

Note 6 — Property, Equipment and Construction in Progress

Below is a summary of property, equipment and construction in progress as of June 30, 2013 and December 31, 2012:

	June 30, 2013			December 31, 2012
	(in thousands)
Construction in progress:
Power plant and related equipment	$	78,198		$	73,958
Platforms and wells		15,158			15,611
Pipelines and processing facilities		3,015			11,784
Other		1,869			1,689
Producing properties (successful efforts method of accounting)		141,219			141,219
Producing equipment		36,770			27,758
Barge and related equipment		53,525			53,425
Office equipment, leasehold improvements and vehicles		9,309			9,249
Accumulated depletion, depreciation and amortization		(110,824	)		(96,136	)
Property, equipment and construction in progress, net	$	228,239		$	238,557

11

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 the additional wells are underway or planned. All costs related to unsuccessful exploratory wells are expensed when such wells are determined to be non-productive.

In January 2013, the Company made a change in estimate in depreciating producing equipment. The Company changed to the unit-of-production method from a straight-line five-year life of calculating depreciation because it more accurately matches the costs of production equipment to the Company’s oil production. If the Company had continued using a straight-line five-year life, depreciation, depletion and amortization expense would have been $0.3 and $0.5 million higher, respectively, for the three and six months ended June 30, 2013.

The property, equipment and construction in progress, net amounts at June 30, 2013 and December 31, 2012 reflect the sale of a 49% participating interest in Block Z-1.

Exploratory well costs capitalized greater than one year after completion of drilling were $6.6 million as of June 30, 2013, and December 31, 2012. 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-19, “Commitments and Contingencies” for further information on the gas-to-power project.

During the six months ended June 30, 2013, the Company incurred capital expenditures of approximately $5.4 million primarily associated with its development of gas-fired power generation of electricity for sale in Peru.

The capital expenditures added were approximately $4.2 million of costs to the power plant, which primarily consisted of capitalized interest of $3.9 million, and approximately $1.2 million related to other capitalized costs, which included capitalized interest of $1.1 million and $0.1 million of information technology investment.

The transfer of a 49% participating interest in Block Z-1 to Pacific Rubiales was effective on December 14, 2012. Pursuant to the carry agreement, Pacific Rubiales provided funding for capital expenditures for Block Z-1 of $20.8 million for the six months ended June 30, 2013. These capital expenditures were primarily related to the costs incurred in the design, fabrication, installation and pipeline connections related to the CX-15 platform of approximately $11.2 million and approximately $6.4 million related to the CX-15 development drilling program.

The following table is the amount of interest expense and depreciation expense capitalized to construction in progress for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Interest expense capitalized	$	2,372	$	3,760	$	4,991	$	6,732
Depreciation expense capitalized		-		3	$	-	$	5

Note 7 — 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 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.

12

Activity related to the Company’s ARO for the six months ended June 30, 2013 and the year ended December 31, 2012 is as follows:

	June 30, 2013		December 31, 2012
	(in thousands)
ARO as of the beginning of the period	$	2,708	$	1,304
Liabilities settled during period		-		(2,093	)
Accretion expense		114		89
Revisions in estimates during period		-		3,408
ARO as of the end of the period	$	2,822	$	2,708

The 2012 revisions in estimates are due to the shift in timing of cash flows associated with expected payment of the ARO liability.  As the Company revised the estimated costs in 2012, the present value of the liabilities was adjusted and, as a result, the Company adjusted both the liability and capitalized asset by approximately $3.4 million, in accordance with ASC Topic 410.

Liabilities settled in 2012 include $2.1 million related to the sale of a 49% participating interest in Block Z-1.

Note 8 — Investment in Ecuador Property

The Company has a 10% non-operating net profits interest in 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 December 2029.

Below is a summary reflecting the Company’s income (loss) from the investment in the Ecuador property for the three and six months ended June 30, 2013 and 2012, respectively, and the investment in the Ecuador property at June 30, 2013 and December 31, 2012, respectively.

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)
Distributions received from investment in Ecuador property	$	250		$	-		$	250		$	-
Amortization of investment in Ecuador property		(34	)		(47	)		(81	)		(94	)
Income (loss) from investment in Ecuador property, net	$	216		$	(47	)	$	169		$	(94	)

	June 30, 2013		December 31, 2012
	(in thousands)
Investment in Ecuador property, net	$	551	$	632

13

Note 9 — Restricted Cash and Performance Bonds

Below is a summary of restricted cash as of June 30, 2013 and December 31, 2012:

	June 30, 2013		December 31, 2012
	(in thousands)
Performance bonds totaling $5.7 million for properties in Peru	$	3,460	$	3,338
Insurance bonds for import duties related to a construction vessel		-		825
Performance obligations and commitments for the gas-to power site		650		650
Secured letters of credit		250		259
$75.0 million secured debt facility		-		35,000
$40.0 million secured debt facility		4,759		32,727
Unsecured performance bond totaling $0.2 million for office lease agreement		-		-
Restricted cash	$	9,119	$	72,799
Current portion of restricted cash as of the end of the period	$	5,010	$	25,129
Long-term portion of restricted cash as of the end of the period	$	4,109	$	47,670

The $75.0 million secured debt facility entered into by the Company in July 2011 required the Company to establish a $2.5 million debt service reserve account during the first 15 months the debt facility was outstanding.  After the first 15-month period, the Company was 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 requirement was subsequently amended subject to the closing of the sale of a 49% participating interest in Block Z-1 to require the funding of the debt service reserve account related to the $75.0 million secured debt facility in the amount of outstanding principal. The remaining principal balance related to the $75.0 million secured debt facility was repaid in May 2013 utilizing the funds in the debt service reserve account related to this debt facility, bringing both the current and non-current balances to zero at June 30, 2013. The restricted cash related to the current and non-current portion of the $75.0 million secured debt financing was $9.5 million and $25.5 million, respectively, at December 31, 2012.

The $40.0 million secured debt facility entered into by the Company in January 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 have maintained 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 requirement was amended subject to the closing of the sale of a 49% participating interest in Block Z-1 to require the funding of the debt service reserve account related to the $40.0 million secured debt facility in the amount of outstanding principal. The requirement was subsequently changed when the Company amended and restated the $40.0 million secured debt facility in May 2013 to maintaining 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 restricted cash related to the current and non-current portion of the $40.0 million secured debt financing was $4.8 million and none, respectively, at June 30, 2013. The restricted cash related to the current and non-current portion of the $40.0 million secured debt financing was $14.5 million and $18.2 million, respectively, at December 31, 2012.

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.

14

Note 10 — Debt

At June 30, 2013 and December 31, 2012, debt consisted of the following:

	June 30, 2013		December 31, 2012
	(in thousands)
$170.9 million Convertible Notes, 6.5%, due March 2015, net of discount of ($13.8) million at June 30, 2013 and ($17.4) million at December 31, 2012	$	157,132	$	153,479
$75.0 million Secured Debt Facility, 3-month LIBOR plus 9%, due July 2015		-		35,000
$40.0 million Secured Debt Facility, 3-month LIBOR plus 8%, due January 2015		40,000		32,727
		197,132		221,206
Less: Current maturity of long-term debt		17,000		24,046
Long-term debt, net	$	180,132	$	197,160

$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 Notesis 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 any of the following 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.

As of 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.

15

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 following table is the estimated remaining cash payments including interest payments related to the 2015 Convertible Notes, assuming no conversion (in thousands):

Year
2013	$	5,556
2014		11,111
2015		176,493
Total estimated remaining cash payments related to the 2015 Convertible Notes	$	193,160

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, 2013, the net amount of $157.1 million includes the $170.9 million of principal reduced by $13.8 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 $13.8 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, 2013, 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, 2013, 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, 2013, $1.79 per share, is less than the conversion price.

16

For the three and six months ended June 30, 2013, the annual effective interest rate on the 2015 Convertible Notes, including the amortization of debt issue costs, was approximately 12.6%.

The following table is the amount of interest expense related to the 2015 Convertible Notes, disregarding capitalized interest considerations, for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Interest expense related to the contractual interest coupon	$	2,777	$	2,777	$	5,555	$	5,555
Amortization of debt discount expense		1,862		1,656		3,653		3,251
Amortization of debt issue costs		250		238		495		473
Interest expense related to the 2015 Convertible Notes	$	4,889	$	4,671	$	9,703	$	9,279

$75.0 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. In May 2013, the Company prepaid the remaining 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 of the remaining principal balance during the second quarter of 2013, the Company incurred $2.4 million of fees and a prepayment premium. The $2.4 million in fees and prepayment premium were recognized as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations. Approximately $1.4 million representing the remaining unamortized debt issue costs loan was expensed as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations when the Company prepaid the remaining principal. For further information on debt issue costs see Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets.”

As a result of the prepayment and amendment during the second quarter of 2012, the Company incurred $5.8 million of fees and a prepayment premium and $1.1 million of debt issue costs. The $5.8 million in fees and prepayment premium were recognized as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations, of which 25% was paid at the time of the amendment and prepayment and 25% was 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. For further information on debt issue costs see Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets.”

The $75.0 million secured debt facility, as amended, provides for an ongoing fee through July 2014 payable by BPZ E&P to the lenders, of the 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-11, “Derivative Financial Instruments” and Note-13, “Fair Value Measurements and Disclosures.”

17

$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. In May 2013, the Company amended and restated the $40.0 million secured debt facility (which had been repaid by scheduled principal repayments to $25.5 million) by increasing the facility size and borrowing an additional $14.5 million.    

In 2013, the $14.5 million of proceeds from the amended and restated $40.0 million secured debt facility will be utilized to meet the Company’s 2013 capital, exploration and development work programs as well as general corporate purposes. In 2011, the proceeds from the $40.0 million secured debt facility were utilized to meet the Company’s 2011 capital, exploration and development work programs, and to reduce other debt obligations.

In May 2013, as a result of amending and restating the $40.0 million secured debt facility (which had been repaid by scheduled principal repayments to $25.5 million) by increasing the facility size and borrowing an additional $14.5 million, the Company added $1.8 million of debt issue costs. The $1.8 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 remaining term, ending in January 2015, using the effective interest method. For further information on debt issue costs, see Note-5, “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 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-11, “Derivative Financial Instruments” and Note-13, “Fair Value Measurements and Disclosures.”

The $40.0 million secured debt facility is secured by three LM6000 gas-fired packaged power units (approximately $53.0 million) that were purchased by the Company from GE through its power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L. and the associated debt service reserve account. 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. At June 30, 2013 the debt service reserve account maintained a balance 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. For further information regarding the debt service reserve account and its requirements, see Note-9, “Restricted Cash and Performance Bonds.”

The amended and restated $40.0 million secured debt facility matures in January 2015, with revised principal repayments due in quarterly installments of $4.0 million to $9.0 million commencing in July 2013 and extending through January 2015.  The $40.0 million secured debt facility has an annual interest rate of the three month LIBOR rate plus 8%. Interest is due and payable quarterly.

The amended and restated $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 consolidated leverage ratio, a maximum net consolidated 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 revised financial covenants at June 30, 2013.

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.

18

The following table is the estimated remaining cash payments related to the $40.0 million secured debt facility, as amended and restated, and excluding potential payments for the Performance Based Arranger Fee but including interest payments (in thousands).

Year
2013	$	9,574
2014		25,069
2015		9,186
Total estimated remaining cash payments related to the $40.0 million secured debt facility	$	43,829

Interest Expense

The following table is a summary of interest expense for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)
Interest expense	$	6,652		$	7,840		$	13,569		$	17,022
Capitalized interest expense		(2,372	)		(3,760	)		(4,991	)		(6,732	)
Interest expense, net	$	4,280		$	4,080		$	8,578		$	10,290

Note 11 — 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,
	2013			2012		2013			2012
	(in thousands)					(in thousands)
Realized derivative gain (loss)	$	(497	)	$	-	$	(1,897	)	$	-
Unrealized derivative gain (loss)		1,774			8,407		2,626			2,039
Total gain (loss) on derivative financial instruments	$	1,277		$	8,407	$	729		$	2,039

See Note-13, “Fair Value Measurements and Disclosures,” for a discussion of methods and assumptions used to estimate the fair values of the Company’s derivative instruments.

19

Note 12 — 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.

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,
	2013			2012			2013			2012
	(in thousands, except per share data)
Net loss	$	(19,640	)	$	(8,500	)	$	(32,424	)	$	(35,791	)
Shares:
Basic weighted average common shares outstanding		115,935			115,573			115,862			115,543
Incremental shares from assumed conversion of dilutive share based awards		-			-			-			-
Diluted weighted average common shares outstanding		115,935			115,573			115,862			115,543
Excluded share based awards (1)		8,140			6,256			8,140			6,256
Excluded convertible debt shares (1)		28,890			28,890			28,890			28,890
Basic net loss per share	$	(0.17	)	$	(0.07	)	$	(0.28	)	$	(0.31	)
Diluted net loss per share	$	(0.17	)	$	(0.07	)	$	(0.28	)	$	(0.31	)

(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, 2013, approximately 0.8 million shares remain available for future grants under the 2007 LTIP and 0.5 million shares remain available for future grants under the Directors’ Plan.

20

The following table summarizes stock-based compensation costs recognized under ASC Topic 718, “Stock Compensation,” for the three and six months ended June 30, 2013 and 2012, respectively, and are included in “General and administrative expense” on the Consolidated Statements of Operations:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Employee stock—based compensation costs	$	763	$	661	$	1,304	$	1,137
Director stock—based compensation costs		155		32		293		265
Employee stock purchase plan costs		3		7		6		18
	$	921	$	700	$	1,603	$	1,420

Restricted Stock Awards and Performance Shares

On March 1, 2013, the Company’s Board of Directors awarded 644,190 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, 2013, the weighted average grant date fair value per share of the restricted stock granted was $2.72.

On March 1, 2013, the Company awarded its non-employee directors a total of 238,973 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, 2013, the weighted average grant date fair value per share of the restricted stock granted was $2.72.

Stock Options

On March 1, 2013, the Company’s Board of Directors awarded officers and other key employees a total of 802,678 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.

For the six months ended June 30, 2013, the weighted average exercise price per share of the option awards granted was $2.72 and the weighted average fair value per share of the option awards granted was $1.78.

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. At June 30, 2013, 1,948,116 shares were available for issuance. On July 1, 2013, 7,283 shares were issued to employees at a price of $1.52 per share.     

Note 13— 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.

21

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.

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.

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. Accordingly, these derivatives are considered to be a Level 2 measurement on the fair value hierarchy. For further information regarding the Company’s derivatives, see Note-11, “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)
		(in thousands)
June 30, 2013
Financial Liabilities
Derivative Financial Instruments
	Current Liabilities	$	-	$	358	$	-
	Non-current Liabilities		-		-		-
		$	-	$	358	$	-
December 31, 2012
Financial Liabilities
Derivative Financial Instruments
	Current Liabilities	$	-	$	2,984	$	-
	Non-current Liabilities		-		-		-
		$	-	$	2,984	$	-

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of long-lived assets, at fair value on a non-recurring basis. As none of the Company’s non-financial assets or liabilities were impaired as of June 30, 2013 and December 31, 2012, and no other fair value measurements were required to be recognized on a non-recurring basis, additional disclosures were not provided.

22

Additional Fair Value Disclosures

Short-term Investments

The Company’s investment in held-to-maturity securities, which are stated at net of amortized cost, was as follows at June 30, 2013 and December 31, 2012:

	June 30, 2013				December 31, 2012
	Carrying Amount		Fair Value (1)		Carrying Amount		Fair Value
	(in thousands)				(in thousands)
Short-term investments - U.S. Treasury bills	$	1,000	$	1,000	$	-	$	-

(1) The Company estimated the fair value of the U.S. Treasury bill to be approximately $1.0 million at June 30, 2013, based on observed market prices for the same or similar types of debt issues. The fair value of the U.S. Treasury bill is considered to be a Level 2 measurement on the fair value hierarchy.

Debt with Variable Interest Rates

The fair value of the Company’s $40.0 million secured debt facility at June 30, 2013 approximates the carrying value because the interest rate is based on the floating rate identified by reference to the market rate, and because the interest rate charged is at a rate 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, 2013 and December 31, 2012 is as follows:

	June 30, 2013				December 31, 2012
	Carrying Amount		Fair Value (1)		Carrying Amount		Fair Value (1)
	(in thousands)				(in thousands)
$170.9 million Convertible Notes, 6.5%, due March 2015, net of discount of ($13.8) million at June 30, 2013 and ($17.4) million at December 31, 2012	$	157,132	$	138,460	$	153,479	$	147,861

 

(1) The Company estimated the fair value of the $170.9 million 2015 Convertible Notes to be approximately $138.5 million and $147.9 million at June 30, 2013 and December 31, 2012, 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 14— Oil Revenue

The oil is delivered by vessel to the refinery owned by the Peruvian national oil company, Petroleos del Peru - PETROPERU S.A. (“Petroperu”), in Talara, Peru, located approximately 70 miles south of the platform.  Produced oil is kept in production inventory until inventory quantities are at a sufficient level to make a delivery to the refinery in Talara.  Although all of the Company’s oil sales are to Petroperu, it believes that the loss of Petroperu as its sole customer would not materially impact the Company’s business because it could readily find other purchasers for the Company’s oil production both in Peru and throughout the world.

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.

23

The following table is the amount of royalty costs of approximately 5% of gross revenues for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Royalty costs	$	697	$	1,771	$	1,403	$	3,826
	$	697	$	1,771	$	1,403	$	3,826

 

Note 15 — Standby Costs

For the three and six months ended June 30, 2013, the Company incurred $2.3 million and $3.4 million, respectively, in standby costs. During the three and six months ended June 30, 2012, the Company incurred $1.4 million and $2.6 million, respectively, in standby costs. During the three months ended June 30, 2013, the Company had one rig, the Petrex-28 rig, on standby for approximately three months, compared with one rig, the Petrex-18 rig, on standby for approximately three months for the same period in 2012. During the six months ended June 30, 2013, the Company had one rig, the Petrex-10 rig, partially or fully on standby for approximately two months and one rig, the Petrex-28 rig, partially or fully on standby for approximately five months, compared with one rig, the Petrex-18 rig, on standby for approximately six months for the same period in 2012.

Note 16— 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 million 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 2013.

Note 17 — 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, 2013 and 2012:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)
Income (loss) before income taxes:
United States	$	(5,543	)	$	446		$	(9,193	)	$	(8,345	)
Foreign		(14,474	)		(10,368	)		(23,278	)		(33,178	)
	$	(20,017	)	$	(9,922	)	$	(32,471	)	$	(41,523	)
Income tax expense (benefit):
United States	$	(322	)	$	569		$	668		$	979
Foreign		(55	)		(1,991	)		(715	)		(6,711	)
	$	(377	)	$	(1,422	)	$	(47	)	$	(5,732	)

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 2032. 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.

24

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 or six months ended June 30, 2013 or 2012, 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, 2013 or December 31, 2012.

Note 18 — 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 performance 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, 2013 and 2012, 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, 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.

Note 19 — Commitments and Contingencies

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.” As a result, 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, 2013 and 2012, 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,which allowedcertain exploration and development costs to be deductible in 2013 and 2012 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 approximately 10 miles of 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 are 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 capitalized interest, 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. The Company has obtained certain permits and is in the process of obtaining additional permits to move the project forward.

25

Note 20 — Legal Proceedings

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.

26

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,” and Item 1A., “Risk Factors,” included in our Annual Report on Form 10-K for the year ended December 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 wholly-owned subsidiary BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership, and its subsidiary BPZ Energy, LLC, a Texas limited liability company. 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 gross (1.9 million net) acres in four blocks in northwest Peru. Our license contracts cover 100% ownership of the following properties: 51% working interest in Block Z-1 (0.6 million gross acres), 100% working interest in Block XIX (0.5 million gross acres), 100% working interest in Block XXII (0.9 million gross acres) and 100% working interest in Block XXIII (0.2 million gross 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, provided that Perupetro S.A. (“Perupetro”), empowered to negotiate and enter into contracts for the exploration and exploitation of hydrocarbons on behalf of Peru in order to promote these activities in Peru, agrees to the extension and we comply with the minimum work programs and requirements of the exploration phase. 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 production and up to 40 years for gas 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 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 license agreement and operating agreement covering the property was extended in May 2013 from May 2016 through December 2029.

We are in the process of developing our Peruvian oil and gas resources. We entered commercial production for Block Z-1 in November 2010 and produce and sell oil from the Corvina and Albacora fields under our current sales contracts. We completed the installation of the new CX-15 platform in the Corvina field to continue the development of the field. In July 2013 we spudded the first development well from the new CX-15 platform. We are also appraising the potential oil and natural gas reserves from the A platform in the Albacora field of Block Z-1.

Additionally, our activities in Peru include (i) analysis and evaluation of technical data on our 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 facilities. 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, 2013, we have produced approximately 6.2 MMBbls of oil.

On December 14, 2012 Perupetro approved the terms of the amendment to the Block Z-1 license contract to recognize the sale of a 49% participating interest (“closing”), in offshore Block Z-1 to Pacific Rubiales Energy Corp. (“Pacific Rubiales”). Under the terms of the agreements signed on April 27, 2012, we (together with our subsidiaries) formed an unincorporated joint venture relationship with a Pacific Rubiales subsidiary, Pacific Stratus Energy S.A., to explore and develop the offshore Block Z-1 located in Peru. Pursuant to the agreements, 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 Stock Purchase Agreement (“SPA”), January 1, 2012. On December 30, 2012, the Peruvian Government signed the Supreme Decree for the execution of the amendment to the Block Z-1 license contract.

27

At December 31, 2012, we had estimated net proved oil reserves of 16.4 MMBbls, of which 13.4 MMBbls were in the Corvina field and 3.0 MMBbls were from the Albacora field. Both fields are located in Block Z-1 offshore of northwest Peru.  Of our total proved reserves, 2.1 MMBbls (12.8%) are classified as proved developed reserves, which includes both proved developed producing and proved developed non-producing reserves from 12 gross (6.1 net) wells, and 14.3 MMBbls (87.2%) 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; 

● Initiating an offshore drilling campaign for the new CX-15 platform;

● Processing and analyzing the data from the three dimensional (“3-D”) seismic survey in Block Z-1 to guide further exploration and development activity within the block;

● Working with our Block Z-1 partner, Pacific Rubiales, to continue to develop the Corvina field and the Albacora field and to explore the remainder of Block Z-1;

● Continuing acquisition, processing and interpretation of seismic data both onshore and offshore to better understand the characteristics and potential of our properties;

● Planning and permitting 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 business development efforts for our gas-to-power project to monetize our natural gas resources, 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 marketing 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 knowledge of oil and gas operations throughout Latin America and, in particular, Peru.

28

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. Our application for an environmental permit to conduct 3-D seismic in Block XIX is under consideration by the relevant authorities.

In the near term, management is focused on the drilling operations from the new platform, the CX-15, utilizing the results of the 1,600 square kilometers (“km”) of 3-D seismic survey in Block Z-1 to optimize our future activities in that location, and optimizing current production through workover activities at our current producing locations. At our onshore locations we are in the process of obtaining the necessary permits to continue exploration activities utilizing our 3-D seismic data acquired in 2011.

A data room for Blocks XIX and XXIII was open, with Credit Suisse Securities (USA) LLC managing the formal process to find a joint venture partner for these onshore blocks. 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. Interested parties have reviewed the data, however, we believe it will be in the best interests of the Company to further de-risk the Block XXIII prospects by drilling up to three shallow exploratory wells on the large anticline identified by 3-D seismic before pursuing further partnering opportunities. We have received approval to move the previously agreed drilling locations to conform to the 3-D seismic results.

In addition, our business plan includes a gas-to-power project as part of our overall gas marketing strategy, which entails the installation of 10 miles of 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 are 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 non-associated gas discovered in our Corvina field that is currently shut-in. 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 forward with the project.

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.

Block Z-1

Divestiture

On April 27, 2012, we and Pacific Rubiales executed a SPA under which we formed an unincorporated joint venture 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, including reserves, 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 were needed to allow Pacific Rubiales to become a party to the Block Z-1 License Contract. Until the required approvals were obtained, Pacific Rubiales provided a $65.0 million down payment on the purchase price and other funds which we initially accounted for as loans to continue to fund our Block Z-1 capital and exploratory activities. These amounts were reflected as long-term debt prior to closing the transaction.

 On December 14, 2012, Perupetro approved the terms of the amendment to the Block Z-1 license contract to recognize the sale of a 49% participating interest, in offshore Block Z-1 to Pacific Rubiales. We and Pacific Rubiales waived and modified certain contract conditions in order to close the transaction. On December 30, 2012, the Peruvian Government signed the Supreme Decree for the execution of the amendment to the Block Z-1 license contract.

At closing, Pacific Rubiales exchanged certain 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. Proceeds of $150.0 million (less transaction costs of $5.7 million) less the net book value of the assets sold of $117.4 million resulted in a gain on the sale that was recognized as a component of operating and administrative expenses in connection with the closing of $26.9 million. Due to certain tax benefits resulting from the sale, the after tax gain was $31.1 million.

29

The transaction provided for an adjustment based upon the collection of revenues ($56.1 million) and the payment of expenses ($32.6 million) and income taxes ($5.2 million) attributable to the properties that took place after the effective date of January 1, 2012 and prior to the closing date, which was December 14, 2012. These amounts were considered settled by adjusting down by $18.3 million the unused portion of the agreed funding of $185.0 million by Pacific Rubiales for our share of capital and exploratory expenditures in Block Z-1 (“carry amount”). At June 30, 2013 and December 31, 2012, the carry amount was $112.0 million and $126.3 million, respectively.

At June 30, 2013 and December 31, 2012, we reflected $19.9 million as other current liabilities and $20.8 million as other non-current liabilities for exploratory expenditures related to Block Z-1 under funding by Pacific Rubiales of the exploratory expenditures in Block Z-1 incurred in 2012. This amount will be settled by us and Pacific Rubiales under the terms of the SPA.

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.  We have completed a total of nine gross (4.6 net) 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., which is located 70 miles south of the platform.

Corvina's CX-11 platform is currently producing and work is underway there to expand the capacity of the existing injection compressor. Once the compressor work is completed we may perform an additional workover designed to reduce associated gas production.

The CX-15 platform was anchored in the West Corvina field, one mile south of the existing CX-11 platform, in the second half of September 2012. On November 8, 2012, we received an environmental permit from the Direccion General de Asuntos Ambientales Energeticos (“DGAAE”) allowing us to begin the drilling and subsequent operation of all production and injection facilities on the new CX-15 platform at the Corvina field. We installed three pipelines between the two Corvina platforms and one pipeline from the CX-15 platform to the discharge manifold for the floating storage and offloading vessel. We experienced difficulties with the installation of these pipelines due to mechanical issues with the pipe laying barge and unexpected strong deep currents in the area that significantly delayed divers from completing key tasks during the pipe laying project.

The platform monitoring and control system modifications necessary to facilitate operation of the CX-15 platform are complete. Equipment is tracking platform response to weather and ocean conditions as well as draft. As a precaution, an anchoring system was installed to provide redundancy to the spud can, which anchors the platform. In July 2013 we spudded the first development well from the new CX-15 platform.

Further, we are working on 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 commence operation of the LACT unit by the end of the third quarter of 2013 on a floating storage and offloading vessel.

Many of the Corvina oil wells have seen initial production decline rates of approximately 50% during the first year of production before stabilizing. Although each of the Corvina wells has declined differently, partly due to the fact that these wells were completed in different zones and some of the wells encountered mechanical problems, they have all initially shown typical solution gas drive behavior which can lead to significant production declines during the first year before leveling off to sustainable rates. We believe these results are influenced by technical/mechanical problems encountered with our initial wells, including unintentional production from intervals in the gas cap; however, it is possible we will see similar production declines with new Corvina wells. The representative rates of production decline remain to be determined because the effective production mechanism in the Corvina field has yet to be fully understood, although we believe that our recent initiation of gas reinjection into the gas cap is helping to slow production decline rates. The work planned during the development drilling program as well as the data we plan to collect during this program should help us to better understand future performance expectations. Further, our ability to produce indicated reserves in Corvina depends on our ability to finance our continued operations and get our produced oil to market. Any failure in meeting these requirements could negatively affect our indicated reserves and their value as reported under the Securities and Exchange Commission (“SEC”) rules. Therefore, in the evaluation of reserves, we attempt to account for all possible delays we can reasonably predict and their impact on the production forecast and remaining reserves to be produced.

30

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 located in water depths of less than 200 feet. We currently have completed a total of four gross (2.0 net) oil wells. We had been producing oil from the Albacora field from December 2009 through late October 2012 under various extended well testing permits.

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 received the required environmental permit for gas injection on October 29, 2012. The Albacora field is no longer subject to an extended well testing program, and the gas and water reinjection equipment is operating in a routine manner. We intend to mobilize a drilling rig on Albacora and reinitiate the development drilling program there guided by the 3-D seismic we obtained over this field.

Block Z-1 Seismic

We completed the 3-D seismic survey of the area to assess our prospects before conducting further drilling operations, as well as to comply with our exploration commitments under our license contract. On November 3, 2011, we received the environmental permit to acquire approximately 1,600 square kms of 3-D seismic data in our offshore Block Z-1 that was granted by the DGAAE. The seismic survey began in the first quarter of 2012. A second seismic boat was contracted to acquire the remaining areas where the CGGVeritas Vantage vessel was unable to safely navigate. The 3-D seismic acquisition on the remaining areas of Block Z-1 commenced in September 2012, with completion in February 2013. Processing the seismic data acquired to date was recently completed by Fugro Seismic Services.

The joint technical team continues to interpret the Block Z-1 3-D seismic data.  

Block XIX 

We have received approval from 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 258 kms of 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 plan to conduct an additional 2-D seismic program in 2013 as confirmation of potential drilling locations, and plan to drill exploratory tests, after receipt of the necessary environmental permits.

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 in process, and subsequent receipt of the necessary ancillary permits. Drilling on Block XXII is expected no earlier than 2014.

Block XXIII

For Block XXIII, in 2011 we acquired approximately 370 square kms of 3-D seismic data and 312 kms of 2-D seismic data which included certain areas of interest within the Palo Santo region and four other prospects that are a part of the Mancora gas play. The processing of the 3-D and 2-D data of the Block XXIII has been completed and evaluated.

The environmental permits for the drilling of several prospects identified by the 2-D and 3-D seismic data acquired in 2011 on Block XXIII was approved in January 2013. We have received approval to move the previously agreed drilling locations to conform to the 3-D seismic results.

We are now in the second exploration period. Drilling on Block XXIII is expected near year end 2013.

31

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 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 is now 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. 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 capitalized interest, 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. We have obtained certain permits and are in the process of obtaining additional permits to move the project forward.

32

Results of Operations

The following table sets forth revenues and operating expenses for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Increase/ (Decrease)			2013			2012			Increase/ (Decrease)
Net sales volume:	(in thousands except per bbl information)									(in thousands except per bbl information)
Oil (MBbls)		136			324			(188	)		265			658			(393	)
Net revenue:
Oil revenue, net	$	12,776		$	32,679		$	(19,903	)	$	26,057		$	69,154		$	(43,097	)
Other revenue		39			2			37			70			80			(10	)
Total net revenue		12,815			32,681			(19,866	)		26,127			69,234			(43,107	)
Average sales price (approximately):
Oil (per Bbl)	$	93.94		$	101.00		$	(7.06	)	$	98.48		$	105.14		$	(6.66	)
Operating and administrative expenses:
Lease operating expense		8,102			12,694			(4,592	)		14,775			24,062			(9,287	)
General and administrative expense		6,451			9,347			(2,896	)		11,926			15,547			(3,621	)
Geological, geophysical and engineering expense		746			3,520			(2,774	)		1,104			28,741			(27,637	)
Depreciation, depletion and amortization expense		7,955			11,648			(3,693	)		14,859			23,154			(8,295	)
Standby costs		2,225			1,409			816			3,368			2,599			769
Other expense		-			756			(756	)		-			756			(756	)
Total operating and administrative expenses	$	25,479		$	39,374		$	(13,895	)	$	46,032		$	94,859		$	(48,827	)
Operating loss	$	(12,664	)	$	(6,693	)	$	(5,971	)	$	(19,905	)	$	(25,625	)	$	5,720

Net Oil Revenue

For the three months ended June 30, 2013, our net oil revenue decreased by $19.9 million to $12.8 million from $32.7 million for the same period in 2012. The decrease in net oil revenue is due to: (1) a decrease in the amount of oil sold of 188 MBbls and (2) a decrease of $7.06, or 7.0%, in the average per barrel sales price received. Total sales for the three months ended June 30, 2013 were 136 MBbls compared to 324 MBbls for the same period in 2012.

For the six months ended June 30, 2013, our net oil revenue decreased by $43.1 million to $26.1 million from $69.2 million for the same period in 2012. The decrease in net oil revenue is due to: (1) a decrease in the amount of oil sold of 393 MBbls, and (2) a decrease of $6.66, or 6.3%, in the average per barrel sales price received. Total sales for the six months ended June 30, 2013 were 265 MBbls compared to 658 MBbls for the same period in 2012.

The decrease in amount of oil sold is primarily due to the December 2012 sale of a 49% participating interest in Block Z-1 to Pacific Rubiales (159 MBbls and 322 MBbls for the three and six months ended June 30, 2012, respectively).

The price/volume analysis is as follows:

	Three Months Ended			Six Months Ended
	June 30,			June 30,
	(in thousands)
2012 Oil revenue, net	$	32,679		$	69,154
Changes associated with sales volumes		(18,895	)		(41,333	)
Changes associated with prices		(1,008	)		(1,764	)
2013 Oil revenue, net	$	12,776		$	26,057

For the three months ended June 30, 2013, we had consistent oil production from seven gross (3.6 net) producing wells, and intermittent production from three gross (1.5 net) wells. During the same period in 2012, we had consistent oil production from eight (gross and net) producing wells and intermittent production from three (gross and net) wells. Total oil production for the three months ended June 30, 2013 was 130 MBbls compared to 323 MBbls for the same period in 2012.

33

On a pro forma basis, our production for the three months ended June 30, 2012 would have been 165 MBbls, assuming the sale of the 49% participating interest in Block Z-1 had closed on January 1, 2012.

For the six months ended June 30, 2013, we had consistent oil production from seven gross (3.6 net) producing wells and intermittent production from three gross (1.5 net) wells. During the same period in 2012, we had consistent oil production from eight (gross and net) producing wells and intermittent production from three wells (gross and net). Total oil production for the six months ended June 30, 2013 was 264 MBbls compared to 676 MBbls for the same period in 2012.

On a pro forma basis, our production for the six months ended June 30, 2012 would have been 345 MBbls, assuming the sale of the 49% participating interest in Block Z-1 had closed on January 1, 2012.

The decrease in oil production is due to the December 2012 sale of a 49% participating interest in Block Z-1 to Pacific Rubiales (158 MBbls and 331 MBbls for the three and six months ended June 30, 2013, respectively), higher than expected decline rates in oil production in the Corvina field, and lower 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.

The following table is the amount of royalty costs of approximately 5% of gross revenues for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Royalty costs	$	697	$	1,771	$	1,403	$	3,826
	$	697	$	1,771	$	1,403	$	3,826

 

Other Revenue

For the three and six months ended June 30, 2013, we recognized $0.1 million and $0.1 million, respectively, of other revenue associated with the chartering of support vessels. 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 support 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 and inventory changes. 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, 2013, lease operating expenses decreased by $4.6 million to $8.1 million ($59.57 per Bbl) from $12.7 million ($39.24 per Bbl). The decrease is primarily driven by a reduction in lease operating expenses of $6.2 million related to the sale of a 49% participating interest in Block Z-1 in December 2012. Additionally, repairs and maintenance expense decreased by $1.3 million primarily due to fewer maintenance and repairs on vessel support services and contract pumping services decreased by $0.5 million due to reduced rent of hydraulic jet pumps used to assist oil production. These decreases were offset by higher workover expenses of $2.7 million primarily associated with the one major workover performed in 2013, compared to no workovers in 2012, higher costs of $0.6 million associated with an oil inventory draw in the three months ended June 30, 2013 versus an oil inventory build in the three months ended June 30, 2012, and higher other lease operating expenses of $0.1 million.

For the six months ended June 30, 2013, lease operating expenses decreased by $9.3 million to $14.8 million ($55.83 per Bbl) from $24.1 million ($36.58 per Bbl). The decrease is primarily driven by a reduction in lease operating expenses of $11.8 million related to the sale of a 49% participating interest in Block Z-1 in December 2012. Additionally, repairs and maintenance expense decreased by $2.0 million primarily due to fewer maintenance and repairs on vessel support services, contract pumping services decreased by $0.7 million due to reduced rent of hydraulic jet pumps used to assist oil production, and other lease operating expenses were lower by $0.3 million. These decreases were offset by higher workover expenses of $4.7 million primarily associated with the one major workover performed in 2013, compared to no workovers in 2012 and higher costs of $0.8 million associated with an oil inventory draw in the six months ended June 30, 2013 versus an oil inventory build in the six months ended June 30, 2012.

34

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, 2013, general and administrative expenses decreased by $2.9 million to $6.4 million from $9.3 million for the same period in 2012.  Stock-based compensation expense, a subset of general and administrative expenses, was $0.9 million for the three months ended June 30, 2013 and $0.7 million for the same period in 2012. Other general and administrative expenses decreased $3.1 million to $5.5 million from $8.6 million for the same period in 2012. The $3.1 million decrease is due to lower third party costs primarily related to the 2012 Block Z-1 transaction of $1.1 million, lower salary and related costs of $1.0 million and lower non-income taxes of $1.0 million.

For the six months ended June 30, 2013, general and administrative expenses decreased by $3.6 million to $11.9 million from $15.5 million for the same period in 2012.  Stock-based compensation expense, a subset of general and administrative expenses, was $1.6 million for the six months ended June 30, 2013 and $1.4 million for the same period in 2012. Other general and administrative expenses decreased $3.8 million to $10.3 million from $14.1 million for the same period in 2012. The $3.8 million decrease is due to lower salary and related costs of $1.1 million, lower third party costs primarily related to the 2012 Block Z-1 transaction of $1.1 million, lower non-income taxes of $1.0 million and lower other general and administrative expenses of $0.6 million.

Geological, Geophysical and Engineering Expense

Geological, geophysical and engineering expenses include laboratory, environmental and seismic acquisition related expenses.

The transfer of a 49% participating interest in Block Z-1 to Pacific Rubiales was effective on December 14, 2012 and the carry of exploratory expenditures for Block Z-1 by Pacific Rubiales began that day. Our share of the 2013 Block Z-1 exploratory expenditures should be fully funded by our partner under the carry agreement in place.

For the three months ended June 30, 2013, geological, geophysical and engineering expenses decreased $2.8 million to $0.7 million compared to $3.5 million for the same period in 2012. The decrease is due to the seismic acquisition program in place for Block Z-1 that occurred in 2012 compared to the lower activity and funding of seismic expenses in Block Z-1 by Pacific Rubiales in 2013 under the carry agreement.

For the six months ended June 30, 2013, geological, geophysical and engineering expenses decreased $27.6 million to $1.1 million compared to $28.7 million for the same period in 2012. The decrease is due to the seismic acquisition activity associated with our seismic data acquisition plan for Block Z-1 that occurred in 2012 compared to the lower activity and funding of seismic expenses in Block Z-1 by Pacific Rubiales in 2013.

Depreciation, Depletion and Amortization Expense

For the three months ended June 30, 2013, depreciation, depletion and amortization expense decreased $3.7 million to $8.0 million from $11.7 million for the same period in 2012. For the six months ended June 30, 2013, depreciation, depletion and amortization expense decreased $8.3 million to $14.9 million from $23.2 million for the same period in 2012.

For the three months ended June 30, 2013, depletion expense decreased $2.5 million to $5.7 million from $8.2 million during the same period in 2012. For the six months ended June 30, 2013, depletion expense decreased $6.0 million to $10.3 million from $16.3 million during the same period in 2012. The decreases for the three and six months ended June 30,2013 compared to the same periods in 2012 are primarily due to lower production in the Corvina and Albacora fields in 2013 due to the sale of a 49% participating interest in the Block Z-1 license contract in December 2012.

For the three months ended June 30, 2013, depreciation expense decreased $1.2 million to $2.3 million compared to $3.5 million for the same period in 2012. For the six months ended June 30, 2013, depreciation expense decreased $2.3 million to $4.6 million compared to $6.9 million for the same period in 2012. The decreases are primarily due to assets included in the sale of a 49% participating interest in the Block Z-1 license contract in December 2012 and the change in estimate in depreciating producing equipment to the unit-of-production method from a straight-line five-year life, partially offset by a change in useful life, as a result of new laws, of two vessels used in Marine operations that is contributing an additional $0.6 million of depreciation expense per quarter beginning in the third quarter of 2012 and is expected to continue through December 2014.

35

Standby Costs

For the three months ended June 30, 2013, standby costs increased $0.9 million to $2.3 million from $1.4 million for the same period in 2012. During the three months ended June 30, 2013 we had the Petrex-28 rig, to be used for drilling on the CX-15 platform, on standby for three months. During the three months ended June 30, 2012, we had one rig, the Petrex-18, on standby for approximately three months.

For the six months ended June 30, 2013, standby costs increased $0.8 million to $3.4 million from $2.6 million for the same period in 2012. During the six months ended June 30, 2013 we had the Petrex-10 workover rig either partially or fully on standby for two months, and the Petrex-28 rig, to be used for drilling on the CX-15 platform, either partially or fully on standby for five months. During the six months ended June 30, 2012, we had one rig, the Petrex-18, on standby for approximately six months.

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 million 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 2013.

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, 2013, total other expense increased $4.2 million to $7.4 million compared to $3.2 million during the same period in 2012. For the six months ended June 30, 2013, total other expense decreased $3.3 million to $12.6 million compared to $15.9 million during the same period in 2012. The change is due primarily to the following:

Interest expense: For the three months ended June 30, 2013, we recognized approximately $4.3 million of net interest expense, which includes $6.7 million of interest expense reduced by $2.4 million of capitalized interest expense. For the same period in 2012, we recognized $4.1 million in net interest expense, which included $7.8 million of interest expense reduced by $3.7 million of capitalized interest. The increase of $0.2 million in net interest expense is due to lower interest capitalized of $1.3 million due to lower average construction in progress as a result of the CX-15 platform, partially offset by lower interest expense of $1.1 million resulting from a lower average of interest bearing debt outstanding between the two periods due to the $40.0 million principal debt prepayment made in May 2012 on the $75.0 million secured debt facility, scheduled principal repayments since March 2012 and the retirement of the remaining $30.5 million of the $75.0 million secured debt facility in May 2013.

For the six months ended June 30, 2013, we recognized approximately $8.6 million of net interest expense, which includes $13.6 million of interest expense reduced by $5.0 million of capitalized interest expense. For the same period in 2012, we recognized $10.3 million in net interest expense, which included $17.0 million of interest expense reduced by $6.7 million of capitalized interest. The decrease of $1.7 million in net interest expense is due to lower interest expense of $3.4 million resulting from a lower average of interest bearing debt outstanding between the two periods due to the $40.0 million principal debt prepayment made in May 2012 on the $75.0 million secured debt facility, scheduled principal repayments since March 2012 and the retirement of the remaining $30.5 million of the $75.0 million secured debt facility in May 2013.

Loss on extinguishment of debt: As a result of the prepayment remaining $30.5 million of the $75.0 million secured debt facility during the second quarter of 2013, we incurred $2.4 million of fees and a prepayment premium and expensed $1.4 million of unamortized debt issue costs. These amounts were recognized as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations. For the three and six months ended June 30, 2013, we reported $3.8 million as a loss on extinguishment of debt.

As a result of the prepayment and amendment to the $75.0 million secured debt facility during the second quarter of 2012, we incurred $5.8 million of fees and a prepayment premium and $1.1 million of debt issue costs. The $5.8 million in fees and prepayment premium was 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% was 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 on the $75.0 million secured debt facility. For the three and six months ended June 30, 2012, we reported $7.3 million as a loss on extinguishment of debt.

36

Gain 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, 2013 and 2012, respectively, the gain associated with the embedded derivatives decreased $7.2 million to a $1.2 million gain for the three months ended June 30, 2013 from a $8.4 million gain for the same period in 2012, and from the measurement at January 1, 2013 and January 1, 2012, respectively, the gain associated with the embedded derivatives decreased $1.3 million to a $0.7 million gain for the six months ended June 30, 2013 from a $2.0 million gain for the same period in 2012.

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, 2013 and June 30, 2012:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)
Income (loss) before income taxes:
United States	$	(5,543	)	$	446		$	(9,193	)	$	(8,345	)
Foreign		(14,474	)		(10,368	)		(23,278	)		(33,178	)
	$	(20,017	)	$	(9,922	)	$	(32,471	)	$	(41,523	)
Income tax expense (benefit):
United States	$	(322	)	$	569		$	668		$	979
Foreign		(55	)		(1,991	)		(715	)		(6,711	)
	$	(377	)	$	(1,422	)	$	(47	)	$	(5,732	)

We have recognized a gross deferred tax asset related to net operating loss carryforwards attributable to the United States, before application of the valuation allowances. We have a valuation allowance for the full amount of the domestic net deferred tax asset, as we believe, 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 2032. Furthermore, because we have no operations within the U.S. taxing jurisdiction, it is likely that sufficient generation of revenue to offset our 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. We 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, 2013 or 2012, respectively. We 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, 2013 or December 31, 2012.

Net Loss

For the three months ended June 30, 2013, our net loss increased $11.1 million to a net loss of $19.6 million or ($0.17) per basic and diluted share from net loss of $8.5 million or ($0.07) per basic and diluted share for the same period in 2012. For the six months ended June 30, 2013, our net loss decreased $3.4 million to a net loss of $32.4 million or ($0.28) per basic and diluted share from net loss of $35.8 million or ($0.31) per basic and diluted share for the same period in 2012.

Liquidity, Capital Resources and Capital Expenditures

At June 30, 2013, we had cash and cash equivalents of $103.8 million, an accounts receivable balance of $8.6 million and working capital of $63.6 million.

At June 30, 2013, we had trade accounts payable and accrued liabilities of $59.8 million.

37

At June 30, 2013, our outstanding debt consisted of 2015 Convertible Notes whose net amount of $157.1 million includes the $170.9 million of principal reduced by $13.8 million of the remaining unamortized discount and $40.0 million outstanding under the $40.0 million secured debt facility. At June 30, 2013, the current and long-term portions of our long-term debt were $17.0 million and $180.1 million, respectively.

	For the Six Months Ended June 30,
Cash Flows	2013			2012
	(in thousands)
Cash provided by (used in):
Operating activities	$	(1,762	)	$	(15,622	)
Investing activities		57,277			(40,284	)
Financing activities		(35,223	)		95,106

Operating Activities

Cash used in operating activities decreased by $13.8 million to a use of cash of $1.8 million for the six months ended June 30, 2013 from a use of cash of $15.6 million for the same period in 2012. The change in cash flows before changes in operating assets and liabilities decreased $4.8 million due to lower revenues, partially offset by lower geological, geophysical and engineering expense, as well as the impact of lower lease operating expenses and lower other costs. Changes in cash flow as a result of changes in operating assets and liabilities provided a decrease in the use of cash of $18.6 million. The decrease in the use of cash is due to changes in assets (primarily accounts receivable of $12.2 million mainly related to amounts due from our Block Z-1 joint venture partner) providing a source of cash of $15.5 million. Also, the changes in liabilities (primarily accounts payable of $27.1 million mainly related to amounts due to our Block Z-1 joint venture partner) providing a source of cash of $3.1 million.

Investing Activities

Net cash provided by investing activities increased by $97.6 million to $57.3 million for the six months ended June 30, 2013 from a use of cash of $40.3 million for the same period in 2012. The increase in cash provided by investing activities is due to a change in restricted cash of $63.7 million due to the repayment of the $75.0 million secured debt facility and the amendment and restatement of the $40.0 million secured debt facility and decreased capital expenditures of $34.9 million, primarily due to our funding of capital expenditures for Block Z-1 provided by Pacific Rubiales under the carry agreement that was partially offset by the purchase of investment securities of $1.0 million.

2013 Capital Expenditures

During the six months ended June 30, 2013, we incurred capital expenditures of approximately $5.4 million primarily associated with our development of gas-fired power generation of electricity for sale in Peru.

The capital expenditures added were approximately $4.2 million of costs to the power plant, which primarily consisted of capitalized interest of $3.9 million, and incurred approximately $1.2 million related to other capitalized costs, which included capitalized interest of $1.1 million and $0.1 million of information technology investment.

The transfer of a 49% participating interest in Block Z-1 to Pacific Rubiales was effective on December 14, 2012. Pursuant to the carry agreement, Pacific Rubiales provided funding for capital expenditures for Block Z-1 of $20.8 million for the six months ended June 30, 2013. These capital expenditures were primarily related to the costs incurred in the design, fabrication, installation and pipeline connections related to the CX-15 platform of approximately $11.2 million and approximately $6.4 million related to the CX-15 development drilling program.

Financing Activities

Cash used in financing activities decreased by $130.3 million to a use of cash of $35.2 million for the six months ended June 30, 2013, compared to a source of cash of $95.1 million for the same period in 2012. The increase in cash used in financing activities is due to lower borrowings of $127.2 million in 2013 compared to 2012 (primarily borrowing of $141.7 million from Pacific Rubiales in 2012 as compared to the drawdown of $14.5 million from the $40.0 million secured debt facility in May 2013), higher repayments of $1.4 million in 2013 compared to 2012 (primarily the repayments of $38.9 million under the $75.0 million secured facility and $7.2 million under the $40.0 million secured facility in 2013 as compared to the repayments of $41.5 million under the $75.0 million secured facility and $3.2 million for capital leases in 2012) and higher debt issue costs and other of $1.7 million in 2013 compared to 2012.

38

Shelf Registration

To finance our operations, we may sell additional shares of our common stock or other securities. Our certificate of formation does not provide for preemptive rights, although we may grant similar rights by contract from time to time. We currently have $134.6 million in common stock covered for potential issuance under an effective shelf registration statement, and another $500.0 million covered under the same shelf registration statement for debt securities, common stock, preferred stock, depositary shares and securities warrants, subscription rights, units, and guarantees of debt securities or any combination thereof, which we may sell from time to time in one or more offerings pursuant to underwritten public offerings, negotiated transactions, at the market transactions, block trades or a combination of these methods. This registration statement will expire on December 20, 2013.

Debt

At June 30, 2013 and December 31, 2012, debt consisted of the following:

	June 30, 2013		December 31, 2012
	(in thousands)
$170.9 million Convertible Notes, 6.5%, due March 2015, net of discount of ($13.8) million at June 30, 2013 and ($17.4) million at December 31, 2012	$	157,132	$	153,479
$75.0 million Secured Debt Facility, 3-month LIBOR plus 9%, due July 2015		-		35,000
$40.0 million Secured Debt Facility, 3-month LIBOR plus 8%, due January 2015		40,000		32,727
		197,132		221,206
Less: Current maturity of long-term debt		17,000		24,046
Long-term debt, net	$	180,132	$	197,160

$170.9 Million Convertible Notes due 2015

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

The interest rate on the 2015 Convertible Notesis 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, we must deliver, at our option, either (1) a number of shares of our common stock determined as set forth in the Indenture, (2) cash, or (3) a combination of cash and shares of our 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 any of the following circumstances:

(1) during any fiscal quarter (and only during such fiscal quarter) commencing after March 31, 2010, if the last reported sale price of our 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 our common stock and the conversion rate on such trading day;

39

(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.

As of February 3, 2013, we 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 we mail the redemption notice, the “last reported sale price” of our 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 we experience any one of certain specified types of corporate transactions, holders may require us 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 us, were approximately $164.9 million.  The initial purchaser received commissions of approximately $5.5 million in connection with the sale and we incurred approximately $0.6 million of direct expenses in connection with the offering.  We used the net proceeds for general corporate purposes, including capital expenditures and working capital, reduction or refinancing of debt, and other corporate obligations.

We accounted for the 2015 Convertible Notes in accordance with Accounting Standard Codification (“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 nonconvertible 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.

We estimated our 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 us 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, we 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, we 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 loan using the effective interest method. The remaining $1.3 million of fees and commissions were treated as transaction costs associated with the equity component.

40

The following table is the estimated remaining cash payments, including interest payments related to the 2015 Convertible Notes, assuming no conversion (in thousands):

 

Year
2013	$	5,556
2014		11,111
2015		176,493
Total estimated remaining cash payments related to the 2015 Convertible Notes	$	193,160

We 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, 2013, the net amount of $157.1 million includes the $170.9 million of principal reduced by $13.8 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 $13.8 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, 2013, 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, 2013, there is no excess if-converted value to the holders of the 2015 Convertible Notes as the price of our common stock at June 30, 2013, $1.79 per share, is less than the conversion price.

For the three and six months ended June 30, 2013, the annual effective interest rate on the 2015 Convertible Notes, including the amortization of debt issue costs, was approximately 12.6%.

The following table is the amount of interest expense related to the 2015 Convertible Notes, disregarding capitalized interest considerations, for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Interest expense related to the contractual interest coupon	$	2,777	$	2,777	$	5,555	$	5,555
Amortization of debt discount expense		1,862		1,656		3,653		3,251
Amortization of debt issue costs		250		238		495		473
Interest expense related to the 2015 Convertible Notes	$	4,889	$	4,671	$	9,703	$	9,279

$75.0 Million Secured Debt Facility

On July 6, 2011, we and our 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 our subsidiary, BPZ E&P. The full amount available under the $75.0 million secured debt facility was drawn down by us on July 7, 2011. In April 2012, we and the lenders amended the terms of the $75.0 million secured debt facility and in May 2012, we prepaid $40.0 million of the principal balance of the $75.0 million secured debt facility. In May 2013, we prepaid the remaining 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.

41

As a result of the prepayment of the remaining principal balance during the second quarter of 2013, we incurred $2.4 million of fees and a prepayment premium. The $2.4 million in fees and prepayment premium were recognized as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations. Approximately $1.4 million representing the remaining unamortized debt issue costs loan was expensed as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations when we prepaid the remaining principal. For further information on debt issue costs see Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets.”

As a result of the prepayment and amendment during the second quarter of 2012, we incurred $5.8 million of fees and a prepayment premium and $1.1 million of debt issue costs. The $5.8 million in fees and prepayment premium were recognized as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations, of which 25% was paid at the time of the amendment and prepayment and 25% was 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 further information on debt issue costs see Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets.”

The $75.0 million secured debt facility, as amended, provides for an ongoing fee through July 2014 payable by BPZ E&P to the lenders, of the 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-11, “Derivative Financial Instruments” and Note-13, “Fair Value Measurements and Disclosures.”

$40.0 Million Secured Debt Facility

In January 2011, we, through our subsidiaries, completed a credit agreement with Credit Suisse where Credit Suisse provided a $40.0 million secured debt facility to our power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L. On April 27, 2012, we and our 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. In May 2013, we amended and restated the $40.0 million secured debt facility (which had been repaid by scheduled principal repayments to $25.5 million) by increasing the facility size and borrowing an additional $14.5 million.    

In 2013, the $14.5 million of proceeds from the amended and restated $40.0 million secured debt facility will be utilized to meet our 2013 capital, exploration and development work programs as well as general corporate purposes. In 2011, the proceeds from the $40.0 million secured debt facility were utilized to meet our 2011 capital, exploration and development work programs, and to reduce other debt obligations.

In May 2013, as a result of amending and restating the $40.0 million secured debt facility (which had been repaid by scheduled principal repayments to $25.5 million) by increasing the facility size and borrowing an additional $14.5 million, we added $1.8 million of debt issue costs. The $1.8 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 remaining term, ending in January 2015, using the effective interest method. For further information on debt issue costs, see Note-5, “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 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-11, “Derivative Financial Instruments” and Note-13, “Fair Value Measurements and Disclosures.”

The $40.0 million secured debt facility is secured by three LM6000 gas-fired packaged power units (approximately $53.0 million) that were purchased by us from GE through our power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L. and the associated debt service reserve account. We and our 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 us to establish and maintain a debt service reserve account during the term of the facility. At June 30, 2013, the debt service reserve account maintained a balance 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. For further information regarding the debt service reserve account and its requirements, see Note-9, “Restricted Cash and Performance Bonds.”

42

The amended and restated $40.0 million secured debt facility matures in January 2015, with revised principal repayments due in quarterly installments of $4.0 million to $9.0 million commencing in July 2013 and extending through January 2015.  The $40.0 million secured debt facility has an annual interest rate of the three month LIBOR rate plus 8%. Interest is due and payable quarterly.

The amended and restated $40.0 million secured debt facility subjects us to various financial covenants calculated as of the last day of each quarter, including a maximum consolidated leverage ratio, a maximum net consolidated leverage ratio, a minimum consolidated interest coverage ratio, a maximum consolidated capitalization ratio and minimum oil production quota per quarter. We were in compliance with these revised financial covenants at June 30, 2013.

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 we secure financing for its gas-to-power project.

The following table is the estimated remaining cash payments related to the $40.0 million secured debt facility, as amended and restated, and excluding potential payments for the Performance Based Arranger Fee but including interest payments (in thousands).

Year
2013	$	9,574
2014		25,069
2015		9,186
Total estimated remaining cash payments related to the $40.0 million secured debt facility	$	43,829

Restricted Cash and Performance Bonds

Below is a summary of restricted cash as of June 30, 2013 and December 31, 2012:

	June 30, 2013		December 31, 2012
	(in thousands)
Performance bonds totaling $5.7 million for properties in Peru	$	3,460	$	3,338
Insurance bonds for import duties related to a construction vessel		-		825
Performance obligations and commitments for the gas-to power site		650		650
Secured letters of credit		250		259
$75.0 million secured debt facility		-		35,000
$40.0 million secured debt facility		4,759		32,727
Unsecured performance bond totaling $0.2 million for office lease agreement		-		-
Restricted cash	$	9,119	$	72,799
Current portion of restricted cash as of the end of the period	$	5,010	$	25,129
Long-term portion of restricted cash as of the end of the period	$	4,109	$	47,670

The $75.0 million secured debt facility we entered into in July 2011 required us to establish a $2.5 million debt service reserve account during the first 15 months the debt facility was outstanding.  After the first 15-month period, we were 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 requirement was subsequently amended subject to the closing of the sale of a 49% participating interest in Block Z-1 to require the funding of the debt service reserve account related to the $75.0 million secured debt facility in the amount of outstanding principal. The remaining principal balance related to the $75.0 million secured debt facility was repaid in May 2013 utilizing the funds in the debt service reserve account related to this debt facility, bringing both the current and non-current balances to zero at June 30, 2013. The restricted cash related to the current and non-current portion of the $75.0 million secured debt financing was $9.5 million and $25.5 million, respectively, at December 31, 2012.

43

The $40.0 million secured debt facility we entered into in January 2011 required us to establish a $2.0 million debt service reserve account during the first 18-month period and, thereafter, we must have maintained 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 requirement was amended subject to the closing of the sale of a 49% participating interest in Block Z-1 to require the funding of the debt service reserve account related to the $40.0 million secured debt facility in the amount of outstanding principal. The requirement was subsequently changed when we amended and restated the $40.0 million secured debt facility in May 2013 to maintaining 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 restricted cash related to the current and non-current portion of the $40.0 million secured debt financing was $4.8 million and none, respectively, at June 30, 2013. The restricted cash related to the current and non-current portion of the $40.0 million secured debt financing was $14.5 million and $18.2 million, respectively, at December 31, 2012.

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. 

Revision to the 2013 Estimated Capital and Exploratory Expenditures Budget

We are currently estimating our 2013 capital and exploratory expenditures, excluding capitalized interest, to be approximately $19.0 million from $27.0 million for our three onshore blocks in which we hold 100% working interests. Our $19.0 million estimated capital and exploratory expenditures onshore include $9.0 million for shallow drilling activities at Block XXIII as well as $5.0 million of 2-D seismic work for Block XXII. Other expenditures of $5.0 million are also included.

The capital and exploratory expenditures for offshore Block Z-1 are fully carried by Pacific Rubiales under the joint venture agreements in 2013. Our 51% share of the Block Z-1 capital investments to be fully carried by Pacific Rubiales is estimated to be $64.0 million from $79.0 million ($125.0 million gross from $154.0 million gross). Our planned activities at Block Z-1 include $21.0 million of CX-15 developmental drilling for three wells, $17.0 million for projects and engineering at the Corvina and Albacora fields and $7.0 million related to other expenditures. The estimate includes $16.0 million related to a two-well drilling program and facilities at the Albacora field. In addition, exploratory expenditures include $3.0 million for the completion of 3-D seismic survey-related activity, including processing, as well as other engineering projects.

Liquidity Outlook

       Our major sources of funding to date have been oil sales, equity and debt financing activities and asset sales.  With our current cash balance, current and prospective Corvina and Albacora oil development cash flow and the carry amount funding related to the 49% participating interest in Block Z-1 (See Divestiture above for additional details on the joint venture), we believe we will have sufficient capital resources to execute our planned Corvina and Albacora oil development projects and our initial onshore projects as well as service our current obligations.

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, and Pacific Rubiales agreed to pay $150.0 million for a 49% participating interest in Block Z-1. Pursuant to the SPA, Pacific Rubiales 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. The transaction provided for certain sale adjustments based upon the collection of revenues, the payment of expenses and income taxes attributable to the properties that took place after an effective date of January 1, 2012 and prior to the closing, which was effective on December 14, 2012. These amounts were considered settled by adjusting down the unused portion of the agreed funding amount of $185.0 million. At June 30, 2013, based on our share of 2013 Block Z-1 capital and exploratory expenditures credited against the carry amount, and the sale adjustments, the carry amount available for our portion of future capital and exploratory expenditures in Block Z-1 was $112.0 million.

We currently have $134.6 million in common stock available under an effective shelf registration statement, and another $500.0 million available under the same shelf registration statement for debt securities, common stock, preferred stock, depositary shares and securities warrants, subscription rights, units, and guarantees of debt securities or any combination thereof, which we may sell from time to time in one or more offerings pursuant to underwritten public offerings, negotiated transactions, at the market transactions, block trades or a combination of these methods. Potential future equity financing, if any, would be dependent on the success of alternative sources of financing such as other possible joint venture arrangements, our cash position and market conditions.

Off-Balance Sheet Arrangements

As of June 30, 2013, we had no transactions, agreements or other contractual arrangements with unconsolidated entities or financial partnerships, often referred to as special purpose entities, which are generally established for the purpose of facilitating off-balance sheet arrangements.

44

Critical Accounting Estimates

In our annual report on Form 10-K for the year ended December 31, 2012, we identified our most critical accounting policies. In preparing the consolidated financial statements, we make assumptions, estimates and judgments that affect the amounts reported. We periodically evaluate our estimates and judgments that are the most critical in nature which are related to oil reserves, successful efforts method of accounting, revenue recognition, impairment of long-lived assets, future dismantlement, restoration, and abandonment costs, derivative instruments, income taxes, as well as stock-based compensation. Our estimates are based on historical experience and on our future expectations that we believe are reasonable. Those 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 are likely to differ from our current estimates and those differences may be material.

Recent Accounting Pronouncements

On August 22, 2012, the SEC adopted rules mandated by the Dodd-Frank Act requiring entities who file reports with the SEC and commercially develop oil, natural gas or liquids (“resource extraction issuers”) to disclose certain payments made to the U.S. government and foreign governments. The rules provide guidance on the types of payments and information about payments that must be disclosed. The rules required a resource extraction issuer to disclose the information annually by filing a new form with the SEC (Form SD) no later than 150 days after the end of its fiscal year. A resource extraction issuer would have been required to comply with the new rules for fiscal years ending after September 30, 2013. As a result, beginning in 2014, the rules would have required us to annually provide information about the type and total amount of payments made for each project related to the commercial development of oil, natural gas, or minerals, and the type and total amount of payments made to each government. There would have been no impact on our financial position and results of operations, but the new rules would have required additional disclosures in future filings.

However, on July 2, 2013, the District Court for the District of Columbia vacated the SEC’s rule requiring resource extraction issuers to disclose payments made to the U.S. government and foreign governments and has ordered the SEC to conduct further proceedings before enacting a new rule. The SEC may appeal the decision to the Circuit Court of Appeals for the District of Columbia. It is not yet entirely clear if the SEC will ultimately be required to rewrite the rule, or when a final rule will be effective. While the result of the decision is that the SEC’s rule requiring resource extraction issuers to disclose payments made to the U.S. government and foreign governments is no longer effective, a rule in some form must be promulgated by the SEC to implement, though the information that is ultimately required to be made public may be more limited.

Disclosure Regarding Forward-Looking Statements

We caution that this document contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in or incorporated by reference into this Form 10-Q which address activities, events or developments which we expect, believe or anticipate will or may occur in the future are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” “plans” and similar expressions, or the negative thereof, are also intended to identify forward-looking statements. In particular, statements, expressed or implied, concerning future operating results, the ability to replace or increase reserves, or to increase production, or the ability to generate income or cash flows are by nature, forward-looking statements. These statements are based on certain assumptions and analyses made by the management of BPZ in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. However, forward-looking statements are not guarantees of performance and no assurance can be given that these expectations will be achieved.

Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, but are not limited to, any of the following in the jurisdictions in which BPZ or its subsidiaries are doing business: market conditions, uncertainties inherent in oil and gas production operations and estimating reserves, unexpected future capital expenditures, the timing and extent of changes in commodity prices for crude oil, natural gas and related products, currency exchange rates, interest rates, inflation, the availability of goods and services, drilling and other operational risks, satisfaction of well testing period requirements, successful installation of required permanent processing facilities, receipt of all required permits, successful completion and installation of new drilling platforms, successful installation and operation of the turbines for the gas-to-power project, availability of capital resources, success of our operational risk management activities, governmental relations, legislative or regulatory changes, political developments, acts of war and terrorism. A more detailed discussion on risks relating to the oil and natural gas industry and to our Company is included in our Annual Report on Form 10-K for the year ended December 31, 2012.

45

In light of these risks, uncertainties and assumptions, we caution the reader that these forward-looking statements are subject to risks and uncertainties, many of which are beyond our control, which could cause actual events or results to differ materially from those expressed or implied by the statements. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements. We undertake no obligations to update or revise our forward-looking statements, whether as a result of new information, future events or otherwise.

Cautionary Statement Regarding Certain Information Releases

We are aware that certain information concerning our operations and production is available from time to time from Perupetro and the Peruvian Ministry of Energy and Mines. This information is available from the websites of Perupetro and the Peruvian Ministry of Energy and Mines and may be available from other official sources of which we are unaware. This information is published by Perupetro and the Peruvian Ministry of Energy and Mines outside our control and may be published in a format different from the format we use to disclose such information, in compliance with SEC and other U.S. regulatory requirements.

Additionally, our joint venture partner in Block Z-1, Pacific Rubiales, is a Canadian public company that is not listed on a U.S. stock exchange, but is listed on the Toronto (TSX), Bolsa de Valores de Colombia (BVC) and BOVESPA stock exchanges. As such, Pacific Rubiales may be subject to different disclosure requirements than us. While Pacific Rubiales is subject to various confidentiality requirements regarding us, information concerning us, such as information concerning energy reserves, may be released by Pacific Rubiales outside of our control and may be released in a format different from the format we use to disclose such information, in compliance with SEC and other U.S. regulatory requirements.

We provide any such information in the format required, and at the times required, by the SEC and as determined to be both material and relevant by our management. We urge interested investors and third parties to consider closely the disclosure in our SEC filings, available from us at 580 Westlake Park Blvd., Suite 525, Houston, Texas 77079; Telephone: (281) 556-6200; Internet: www.bpzenergy.com. These filings can also be obtained from the SEC via the internet at www.sec.gov.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates, oil and natural gas prices and foreign currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Interest Rate Risk

As of June 30, 2013, we had long-term debt of approximately $180.1 million and $17.0 million of current maturities of long-term debt.

The $40.0 million secured debt facility, which at June 30, 2013 had $40.0 million outstanding, is variable rate debt that exposes us to the risk of increased interest expense in the event of increases in short-term interest rates. If the variable interest rate were to increase by 1% from the rate at inception, interest expense would increase by approximately $0.3 million annually. The carrying value of the variable interest rate debt approximates fair value as it bears interest at current market rates.

In February and March 2010, we closed on the private offering for an aggregate $170.9 million of convertible notes due 2015. The 2015 Convertible Notes are general senior unsecured obligations of BPZ and subject us to risks related to changes in the fair value of the debt, however, due to make-whole provisions within the Indenture, our exposure to potential gains if we were to repay or refinance such debt are minimal.

The fair value of our 6.5% 2015 Convertible Notes as compared to the carrying value at June 30, 2013 and December 31, 2012, was as follows:

	June 30, 2013				December 31, 2012
	Carrying Amount		Fair Value (1)		Carrying Amount		Fair Value (1)
	(in thousands)				(in thousands)
$170.9 million Convertible Notes, 6.5%, due March 2015, net of discount of ($13.8) million at June 30, 2013 and ($17.4) million at December 31, 2012	$	157,132	$	138,460	$	153,479	$	147,861

(1) We estimated the fair value of the $170.9 million 2015 Convertible Notes to be approximately $138.5 million and $147.9 million at June 30, 2013 and December 31, 2012, respectively, based on observed market prices for the same or similar type of debt issues.

46

Commodity Price Risk

With respect to our oil and gas business, any revenues, cash flow, profitability and future rate of growth we achieve will be greatly dependent upon prevailing prices for oil and gas.  Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms is also expected to be dependent on oil and gas prices.  Historically, oil and gas prices and markets have been volatile and are likely to continue to be volatile in the future.  Prices for oil and gas are subject to potentially wide fluctuations in response to relatively minor changes in supply of and demand for oil and gas, market uncertainty, and a variety of additional factors that are beyond our control.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but may also reduce the amount of oil and natural gas we can produce economically, if any.  A substantial or extended decline in oil and natural gas prices may materially affect our future business, financial condition, results of operations, liquidity and borrowing capacity, and may require a reduction in the carrying value of our oil and gas properties.  While our revenues may increase if prevailing oil and gas prices increase significantly, exploration and production costs and acquisition costs for additional properties and reserves may also increase.

In January 2011, we closed on a $40.0 million secured debt facility whose fee contains a performance based fee that is dependent on the change in oil prices from the inception date of the debt agreement and the price of oil at each principal repayment date. This performance based payment is subject to certain maximum limitations; however, this performance based fee exposes us to commodity price risk and may limit our ability to fully receive potential gains if oil prices increase above the price of oil at the inception of the debt agreement.

In July 2011, we closed on a $75.0 million secured debt facility whose fee contains a performance based fee that is dependent on the change in oil prices from the inception date of the debt agreement and the price of oil at each principal repayment date. This performance based payment is subject to certain maximum limitations; however, this performance based fee exposes us to commodity price risk and may limit our ability to fully receive potential gains if oil prices increase above the price of oil at the inception of the debt agreement.

With respect to our planned electricity generation business, the price we can obtain from the sale of electricity through our proposed power plant may not rise at the same rate, or may not rise at all, to match a rise in the cost of production and transportation of our gas reserves which will be used to generate the electricity.  Prices for electricity in Peru have been volatile in the past and may be volatile in the future.  However, gas prices for gas sourced in Peru are regulated and therefore not volatile.

Foreign Currency Exchange Rate Risk

The U.S. Dollar is the functional currency for our operations in both Peru and Ecuador.  Ecuador has adopted the U.S. Dollar as its official currency.  Peru, however, uses its local currency, the Nuevo Sol, in addition to the U.S. Dollar, and therefore, our financial results are subject to favorable or unfavorable fluctuations in the exchange rate and inflation in that country.  Transaction differences have been nominal to-date but are expected to increase as our activities in Peru continue to escalate. 

For the three months ended June 30, 2013 and 2012, foreign currency gains (losses) were ($0.9) million and ($0.2) million, respectively. For the six months ended June 30, 2013 and 2012, foreign currency gains (losses) were ($1.1) million and ($0.3) million, respectively. Foreign currency gains (losses) are included in other income (expense) in the Consolidated Statements of Operations.

We currently have no foreign currency derivative instruments outstanding. However, we may enter into foreign currency derivative instruments (such as forward contracts, costless collars or swap agreements) in the future if we determine that it is necessary to invest in such instruments in order to mitigate our foreign currency exchange risk.

47

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures as defined in Rule 13a-15(e) of the Exchange Act were effective as of the end of the period covered by this report to ensure that information required to be disclosed by the Company in the reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control over Financial Reporting

During the quarter ended June 30, 2013, there was no change in internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

48

PART II

Item 1. Legal Proceedings

See Note-20, “Legal Proceedings,” of the Notes to Unaudited Consolidated Financial Statements included in this Form 10-Q and Item 3. of Part I of our Annual Report on Form 10-K for the year ended December 31, 2012 for a discussion of legal proceedings, which are incorporated into this Part II, Item 1. “Legal Proceedings” by reference.

Item 1A. Risk Factors

There are no material changes in our risk factors as previously described in our Annual Report on Form 10-K for the year ended December 31, 2012.

Item 6. Exhibits

31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. (Filed herewith)
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. (Filed herewith)
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002. (Filed herewith)
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002. (Filed herewith)
101.INS	XBRL Instance Document. (Filed herewith)
101.SCH	XBRL Schema Document. (Filed herewith)
101.CAL	XBRL Calculation Linkbase Document. (Filed herewith)
101.LAB	XBRL Label Linkbase Document. (Filed herewith)
101.PRE	XBRL Presentation Linkbase Document. (Filed herewith)
101.DEF	XBRL Definition Linkbase Document. (Filed herewith)

49

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	BPZ Resources, Inc.
Date: August 9, 2013	/s/ MANUEL PABLO ZÚÑIGA-PFLÜCKER
	Manuel Pablo Zúñiga-Pflücker
	President and Chief Executive Officer

 

50