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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: September 30, 2014

 

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 October 31, 2014, there were 118,656,863 shares of common stock, no par value, outstanding.

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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	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	54
PART II
Item 1.	Legal Proceedings	55
Item 1A.	Risk Factors	55
Item 6.	Exhibits	55
SIGNATURES

 

 

 

PART I

 

Item 1. Financial Statements

 

BPZ Resources, Inc. and Subsidiaries

Consolidated Balance Sheets 

(In thousands)

  

		September 30,				December 31,
		2014				2013
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	79,496			$	57,395
Accounts receivable			6,597				21,630
Income taxes receivable			2,007				2,134
Value-added tax receivable			2,273				10,490
Inventory			13,171				17,368
Restricted cash			-				1,250
Prepaid and other current assets			5,082				5,419
Total current assets			108,626				115,686
Property, equipment and construction in progress, net			186,785				217,753
Restricted cash			4,109				4,109
Other non-current assets			6,080				5,065
Investment in Ecuador property, net			509				534
Deferred tax asset			58,203				63,602
Total assets		$	364,312			$	406,749
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	6,688			$	3,127
Accrued liabilities			11,837				11,246
Other liabilities			40,849				24,494
Accrued interest payable			324				5,119
Derivative financial instruments			-				30
Current maturity of long-term debt			58,849				-
Total current liabilities			118,547				44,016
Asset retirement obligation			2,920				1,564
Other non-current liabilities			-				16,755
Long-term debt, net			153,780				206,939
Total long-term liabilities			156,700				225,258
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; 118,652 and 117,526 shares issued and outstanding at September 30, 2014 and December 31, 2013, respectively			572,062				569,061
Accumulated deficit			(482,997	)			(431,586	)
Total stockholders’ equity			89,065				137,475
Total liabilities and stockholders’ equity		$	364,312			$	406,749

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

BPZ Resources, Inc. and Subsidiaries

Consolidated Statements of Operations (Unaudited)

(In thousands, except per share data)

  

		Three Months Ended September 30,								Nine Months Ended September 30,
		2014				2013				2014				2013
Net revenue:
Oil revenue, net		$	20,174			$	12,500			$	65,268			$	38,557
Other revenue			176				29				313				99
Total net revenue			20,350				12,529				65,581				38,656
Operating and administrative expenses:
Lease operating expense			9,383				5,319				21,350				20,094
General and administrative expense			5,259				6,572				17,831				18,498
Geological, geophysical and engineering expense			705				857				2,796				1,961
Depreciation, depletion and amortization expense			4,087				7,246				16,202				22,105
Standby costs			-				705				-				4,073
Other operating expense			-				2,683				-				2,683
Asset impairments			41,000				-				41,000				-
Total operating and administrative expenses			60,434				23,382				99,179				69,414
Operating income (loss)			(40,084	)			(10,853	)			(33,598	)			(30,758	)
Other income (expense):
Income (loss) from investment in Ecuador property, net			242				(8	)			225				161
Interest expense, net			(3,296	)			(3,559	)			(10,646	)			(12,137	)
Loss on extinguishment of debt			-				(3,436	)			(1,245	)			(7,222	)
Gain (loss) on derivatives			241				(457	)			2				272
Interest income			428				128				778				175
Other expense			(195	)			(2,907	)			(224	)			(4,054	)
Total other expense, net			(2,580	)			(10,239	)			(11,110	)			(22,805	)
Loss before income taxes			(42,664	)			(21,092	)			(44,708	)			(53,563	)
Income tax expense (benefit)			2,628				(5,771	)			6,703				(5,818	)
Net loss		$	(45,292	)		$	(15,321	)		$	(51,411	)		$	(47,745	)
Basic net loss per share		$	(0.39	)		$	(0.13	)		$	(0.44	)		$	(0.41	)
Diluted net loss per share		$	(0.39	)		$	(0.13	)		$	(0.44	)		$	(0.41	)
Basic weighted average common shares outstanding			116,399				116,009				116,262				115,911
Diluted weighted average common shares outstanding			116,399				116,009				116,262				115,911

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

BPZ Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

 

		For the Nine Months Ended
		September 30,
		2014				2013
Cash flows from operating activities:
Net loss		$	(51,411	)		$	(47,745	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Stock-based compensation			2,342				2,641
Depreciation, depletion and amortization			16,202				22,105
Amortization of investment in Ecuador property			25				89
Deferred income taxes			5,312				(8,951	)
Loss on disposition of assets			-				2,683
Asset impairments			41,000				-
Loss on extinguishment of debt			1,245				7,222
Amortization of discount and deferred financing fees			6,273				7,177
Gain on derivatives			(2	)			(272	)
Other non-cash items included in net loss			(33	)			522
Changes in operating assets and liabilities:
Decrease in accounts receivable			15,033				19,438
Decrease in value-added tax receivable			7,895				9,727
Decrease in inventory			4,522				1,749
Increase in other assets			(1,389	)			(862	)
Decrease in income taxes receivable			217				-
Increase (decrease) in accounts payable			3,561				(16,317	)
Decrease in accrued liabilities			(4,204	)			(22,568	)
Decrease in income taxes payable			-				(11,704	)
Decrease in other liabilities			(400	)			(1,204	)
Net cash provided by (used in) operating activities			46,188				(36,270	)
Cash flows from investing activities:
Property and equipment additions			(25,171	)			(8,229	)
Decrease in restricted cash			1,250				67,440
Proceeds from maturity of investment securities			-				1,000
Purchase of investment securities			-				(1,000	)
Net cash provided by (used in) investing activities			(23,921	)			59,211
Cash flows from financing activities:
Borrowings			-				78,355
Repayments of borrowings			-				(99,107	)
Deferred and other loan fees			(324	)			(6,782	)
Proceeds from exercise of stock options, net			129				-
Proceeds from sale of common stock, net			29				36
Net cash used in financing activities			(166	)			(27,498	)
Net increase (decrease) in cash and cash equivalents			22,101				(4,557	)
Cash and cash equivalents at beginning of period			57,395				83,540
Cash and cash equivalents at end of period		$	79,496			$	78,983
Supplemental cash flow information:
Cash paid for:
Interest		$	18,412			$	16,752
Income tax			1,378				14,131
Non — cash items:
Convertible debt exchanged			26,000				72,850
Depletion allocated to production inventory			292				27
Asset retirement obligation capitalized to property and equipment, net of revisions			1,259				-
Property and equipment transferred to / from current assets / liabilities or other non-current assets			-				952

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

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 an independent oil and gas company 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 development of a gas-fired power generation facility which may be wholly- or partially-owned by the Company, or may be wholly-owned by a third party.

 

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 agreements for oil and gas exploration and production covering approximately 2.2 million gross (1.9 million net) acres, in four blocks in northwest Peru and off the northwest coast of Peru in the Gulf of Guayaquil. 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 contract, the 40-year term may apply to oil production as well. The Company’s estimate of proved reserves has been prepared under the assumption that the Company’s license contract will allow production for the possible 40-year term for both oil and gas.

 

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”). In May 2013, the license agreement and operating agreement covering the property were extended from May 2016 to December 2029.

 

The Company is in the process of developing its Peruvian oil and gas reserves.  The Company entered commercial production for 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 also spudded a development well from the A platform in the Albacora field of Block Z-1 in September 2013. The Company spudded an exploratory well in Block XXIII in January 2014.

 

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 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, including reserves, 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 (“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.

 

 

 

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, 2013 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, 2013.

 

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. Numerous interpretations and assumptions are made 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, plant and equipment, including impairments and asset retirement obligations, 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 2013 consolidated financial statements to conform to the 2014 presentation. These reclassifications were not material to the accompanying consolidated financial statements.

 

Summary of Significant Accounting Policies

 

The Company 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, 2013. 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, 2013.

 

Recent Accounting Pronouncements 

 

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. (“ASU”) 2014-08: Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 changes the criteria for reporting discontinued operations while enhancing disclosures in this area and is effective for annual and interim periods beginning after December 15, 2014. The Company is currently evaluating the provisions of ASU 2014-08 and assessing the impact, if any, it may have on its financial position and results of operations.

 

 

 

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers, and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. In addition, ASU 2014-09 supersedes the cost guidance in Subtopic 605-35, Revenue Recognition—Construction-Type and Production-Type Contracts, and creates new Subtopic 340-40, Other Assets and Deferred Costs— Contracts with Customers. The core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Also, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. ASU 2014-09 is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). The Company is currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on its financial position and results of operations.

 

In August 2014, the FASB issued Accounting Standards Update No. 2014-15 (ASU 2014-15), which creates Subtopic 205-40, Presentation of Financial Statements— Going Concern. ASU 2014-15 requires management to assess the entity’s ability to continue as a going concern, and to provide related footnote disclosures in certain circumstances. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods therein. The Company is currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on its financial position and results of operations.

 

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 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 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 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.

 

The development of Block Z-1 is subject to the terms and conditions of a Joint Operating Agreement with Pacific Rubiales that governs the legal, technical, and operating rights and obligations of the parties with respect to the operation of Block Z-1. Under the agreement, the Company is the operator and responsible for the administrative, regulatory, government and community related duties and Pacific Rubiales manages the technical and operating duties in Block Z-1. The Joint Operating Agreement will continue for the term of the License Contract and thereafter until all decommissioning obligations under the License Contract have been satisfied.

 

The September 30, 2014 and December 31, 2013 carry amounts were $23.8 million and $81.3 million, respectively.

 

At September 30, 2014 and December 31, 2013, the Company reflected $40.7 million and $23.9 million, respectively, as other current liabilities and zero and $16.8 million, respectively, as other non-current liabilities for exploratory expenditures related to Block Z-1 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

 

Below is a summary of accounts receivable as of September 30, 2014 and December 31, 2013:

  

		September 30, 2014				December 31, 2013
		(in thousands)
Commodity sales		$	5,618			$	2,303
Accounts receivable - joint venture			-				12,230
Other			979				7,097
Accounts receivable		$	6,597			$	21,630

 

 

At September 30, 2014 and December 31, 2013, accounts receivable other consisted of $0.7 million and $7.0 million due to the Company from the Company’s joint venture partner for services and materials provided directly to the joint venture partner.

 

Income Taxes Receivable

 

The Company’s September 30, 2014 and December 31, 2013 income tax receivable amounts were $2.0 million and $2.1 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%.

 

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

 

Activity related to the Company’s value-added tax receivable for the nine months ended September 30, 2014 and the year ended December 31, 2013 is as follows:

  

		September 30, 2014				December 31, 2013
		(in thousands)
Value-added tax receivable as of the beginning of the period		$	12,262			$	21,784
IGV accrued related to expenditures during period			9,916				12,722
IGV reduced related to sale of oil during period			(17,812	)			(22,244	)
Value-added tax receivable as of the end of the period		$	4,366			$	12,262
Current portion of value-added tax receivable as of the end of the period		$	2,273			$	10,490
Long-term portion of value-added tax receivable as of the end of the period		$	2,093			$	1,772

 

 

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

 

Below is a summary of accounts payable as of September 30, 2014 and December 31, 2013:  

 

		September 30, 2014				December 31, 2013
		(in thousands)
Accounts payable - joint venture		$	4,236			$	-
Other accounts payable			2,452				3,127
Accounts payable		$	6,688			$	3,127

 

 

The September 30, 2014 and December 31, 2013 accrued liabilities amounts were $11.8 million and $11.2 million, respectively.

 

Note 4 — Inventory

 

Inventories consist 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.  Crude oil inventory is stated at the lower of average cost or market value. Cost is determined on a weighted average basis based on production costs.

 

Below is a summary of inventory as of September 30, 2014 and December 31, 2013:

  

		September 30, 2014				December 31, 2013
		(in thousands)
Tubular goods, accessories and spare parts		$	9,976			$	15,534
Crude oil			3,195				1,834
Inventory		$	13,171			$	17,368

 

		September 30, 2014				December 31, 2013
Crude oil (barrels)			51,715				24,866
Crude oil (cost per barrel)		$	61.78			$	73.77

 

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

 

Below is a summary of prepaid and other current assets as of September 30, 2014 and December 31, 2013:

 

		September 30, 2014				December 31, 2013
		(in thousands)
Prepaid expenses and other		$	3,332			$	4,327
Prepaid insurance			1,750				1,092
Prepaid and other current assets		$	5,082			$	5,419

 

Prepaid expenses and other are related to prepayments for drilling services, equipment rental and material procurement and deposits that are rent deposits in connection with 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.

 

 

 

Below is a summary of other non-current assets as of September 30, 2014 and December 31, 2013:

 

		September 30,				December 31,
		2014				2013
		(in thousands)
Debt issue costs, net		$	3,987			$	3,293
Value-added tax receivable			2,093				1,772
Other non-current assets		$	6,080			$	5,065

 

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 September 2013, the Company prepaid the remaining principal balance on the $40.0 million secured debt facility (which had been repaid by scheduled principal repayments to $36.0 million). 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. The debt issue costs associated with those agreements were modified in accordance with ASC Topic 470 as follows:

  

(1)

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 as part of the “Loss on extinguishment of debt.”

 

(2)

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) associated with the increase in the facility size and borrowing of 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 was to 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. In September 2013, the Company prepaid the remaining principal balance on the $40.0 million secured debt facility and, accordingly, expensed the remaining $1.7 million of unamortized debt issue costs as part of the “Loss on extinguishment of debt.”

 

The Company incurred $4.8 million of original debt issue costs in the first quarter of 2010 associated with the issuance of an aggregate principal amount of $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. As a result of the repurchase of $85.0 million aggregate principal amount of 2015 Convertible Notes during the third quarter of 2013, approximately $12.2 million of the repayment was considered a retirement of debt and approximately $0.1 million of unamortized debt issue costs were expensed. The remaining $72.8 million of the repayment was considered an exchange of debt and not deemed a substantial modification of debt. The remaining unamortized debt issue costs are being amortized over the remaining life of the 2015 Convertible Notes, using the effective interest method. In April 2014, $26.0 million of the aggregate principal amount of the 2015 Convertible Notes was exchanged for an additional $25.0 million aggregate principal amount of 2017 Convertible Notes in a private transaction. The $26.0 million of the exchange was considered a retirement of debt and approximately $0.3 million of unamortized debt issue costs were expensed as part of the “Loss on extinguishment of debt.” The remaining unamortized debt issue costs of $0.6 million are being amortized over the remaining life of the 2015 Convertible Notes, using the effective interest method.

 

The Company incurred $2.3 million of original debt issue costs in the third quarter of 2013 associated with the issuance of an aggregate principal amount of $143.8 million of convertible notes due 2017 (the “2017 Convertible Notes”).  In the second quarter of 2014, the Company incurred $0.3 million of debt issue costs associated with the issuance in the exchange of the aggregate principal amount of $25.0 million of 2017 Convertible Notes. The debt issue costs are being amortized over the life of the 2017 Convertible Notes, using the effective interest method.

 

 

 

The following table shows the amount of debt issue costs amortized into interest expense for the three and nine months ended September 30, 2014 and 2013:

  

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Amortization of debt issue costs		$	336			$	577			$	1,054			$	1,995
		$	336			$	577			$	1,054			$	1,995

 

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

 

At September 30, 2014 and December 31, 2013, the Company classified $2.1 million and $1.8 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 September 30, 2014 and December 31, 2013:

 

		September 30, 2014				December 31, 2013
		(in thousands)
Construction in progress:
Power plant and related equipment		$	49,801			$	82,928
Platforms and wells			30,447				12,505
Pipelines and processing facilities			882				846
Other			597				556
Producing properties (successful efforts method of accounting)			142,713				140,937
Producing equipment			40,209				40,209
Barge and related equipment			52,703				53,969
Office equipment, leasehold improvements and vehicles			9,141				9,122
Accumulated depletion, depreciation and amortization			(139,708	)			(123,319	)
Property, equipment and construction in progress, net		$	186,785			$	217,753

 

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.

 

Suspended Exploratory Well Costs

 

Exploratory well costs capitalized greater than one year after completion of drilling were $6.6 million as of September 30, 2014, and December 31, 2013. 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.

 

 

 

Capital Expenditures

 

During the nine months ended September 30, 2014, the Company incurred net capital expenditures of approximately $26.4 million associated with its development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of gas-fired power generation of electricity for sale in Peru.

 

The capital expenditures added were approximately $17.5 million related to the exploration of Block XXIII, which included capitalized interest of $1.6 million, approximately $7.7 million of costs related to the power plant, which consisted of capitalized interest of $7.1 million, and other capital expenditures incurred of approximately $1.2 million, which included capitalized interest of $0.6 million.

 

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 100% of capital expenditures for Block Z-1 of $112.9 million for the nine months ended September 30, 2014. These gross capital expenditures include approximately $46.5 million related to the CX-15 development drilling program, approximately $44.5 million related to the development drilling program in Albacora and expenditures related to the Piedra Redonda platform of approximately $4.9 million, the Delfin platform of approximately $4.6 million and the CX-15 platform of approximately $2.0 million.

 

Asset Impairments

 

In connection with the Company’s periodic evaluation of assets for recoverability, the Company revised its view of the Power plant and related equipment, due to recent developments that may change the extent or manner in which the asset may be used. Using a probability weighted average income approach of different courses of action available to the Company, the Company compared the undiscounted cash flows to the carrying value of the assets. The fair value of the assets was determined using a discounted cash flow models using the same methodology. As a result, the assets are considered to be impaired, and the Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets. The Company recorded an impairment loss related to Power plant and related equipment in the third quarter of 2014 of $41.0 million. See Note-13, “Fair Value Measurements and Disclosures” for further information.

 

The following table shows the amount of interest expense capitalized to construction in progress for the three and nine months ended September 30, 2014 and 2013:

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Interest expense capitalized		$	3,300			$	2,237			$	9,250			$	7,228

 

Note 7 — Asset Retirement Obligation

 

An obligation was recorded for the future plug and abandonment of the oil wells in the Corvina and Albacora fields in Block Z-1, and the Pampa la Gallina well in Block XIX 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. Any negative adjustment in excess of asset retirement cost is reclassified to depreciation, depletion, and amortization expense.

 

 

 

Activity related to the Company’s ARO for the nine months ended September 30, 2014 and the year ended December 31, 2013 is as follows:

 

		September 30, 2014				December 31, 2013
		(in thousands)
ARO as of the beginning of the period		$	1,564			$	2,708
Liabilities incurred during period			1,259				204
Accretion expense			97				238
Revisions in estimates during period			-				(1,586	)
ARO as of the end of the period		$	2,920			$	1,564

 

The 2013 revisions in estimates are due to the change in estimates of future costs and the shift in timing of cash flows associated with expected payment of the ARO liability.  As a revision to estimated costs in 2013, the present value of the liabilities was adjusted and, as a result, the Company adjusted both the liability and capitalized asset. Any negative adjustment in excess of asset retirement cost is reclassified to depreciation, depletion, and amortization expense.

 

Note 8 — Investment in Ecuador Property

 

The Company has a 10% non-operating net profits interest in the Santa Elena Property an oil and gas property in Ecuador. The Company accounts for this investment under the cost method and records its share of cash received as other income. 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 nine months ended September 30, 2014 and 2013, respectively, and the investment in the Ecuador property at September 30, 2014 and December 31, 2013, respectively.

   

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Distributions received from investment in Ecuador property		$	250			$	-			$	250			$	250
Amortization of investment in Ecuador property			(8	)			(8	)			(25	)			(89	)
Income (loss) from investment in Ecuador property, net		$	242			$	(8	)		$	225			$	161

 

		September 30,				December 31,
		2014				2013
		(in thousands)
Investment in Ecuador property, net		$	509			$	534

 

In 2013, in order to extend the term of the contract from 2016 to 2029, the Consortium, which includes the Company and three other partners, agreed to additional work commitments to increase production in the Santa Elena field. The Company’s total share of this commitment over the remaining life of the contract is $5.0 million (the Company’s 10% non-operating net profits interest) which amount is due for the remainder of 2014 through 2028. This commitment is expected to be funded by cash on hand, cash generated from new production, or loans of the Consortium. If the Consortium does not have sufficient cash on hand, the Company may elect to make a cash contribution to the Consortium for its 10% share of the commitment. If the Company elects not to make its 10% share contribution of the commitment, it would lose its rights in the Consortium and the contract for the Santa Elena field.

 

 

 

Note 9 — Restricted Cash and Performance Bonds

 

Below is a summary of restricted cash as of September 30, 2014 and December 31, 2013:

 

		September 30, 2014				December 31, 2013
		(in thousands)
Performance bonds totaling $5.7 million for properties in Peru		$	3,459			$	3,459
Performance obligations and commitments for the gas-to-power site			650				650
Secured letters of credit			-				250
$40.0 million secured debt facility			-				1,000
Unsecured performance bond totaling $0.1 million for office lease agreement			-				-
Restricted cash		$	4,109			$	5,359
Current portion of restricted cash as of the end of the period		$	-			$	1,250
Long-term portion of restricted cash as of the end of the period		$	4,109			$	4,109

 

 

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 September 30, 2014 and December 31, 2013.

 

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, to maintain a balance in the debt service reserve account equal to the aggregate amount of principal and interest payment on the $40.0 million secured debt facility due 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 increase the funding of the debt service reserve account related to the $40.0 million secured debt facility to 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 for the Company to maintain a balance in the debt service reserve account equal to the aggregate amount of principal and interest payment on the $40.0 million secured debt facility due on the succeeding principal repayment date. The remaining principal balance related to the $40.0 million secured debt facility was repaid in September 2013 utilizing $3.8 million of funds from the debt service reserve account related to this debt facility. As a result of the repayment of the remaining principal balance in September 2013 of the $40.0 million secured debt facility, it was agreed that the restricted cash balance would remain at $1.0 million relating to the Performance Based Arranger Fee for the $75.0 million secured debt facility through July 2014. In July 2014 the $1.0 million was released to the Company and the debt service reserve account was terminated. Therefore, the restricted cash balance related to the current and non-current portion of the $40.0 million secured debt financing were both zero at September 30, 2014. The restricted cash related to the current and non-current portion of the $40.0 million secured debt financing was $1.0 million and zero, respectively, at December 31, 2013.

 

All of the performance and insurance bonds are issued by Peruvian banks and their terms are governed by the corresponding license contracts, customs laws, legal requirements or rental practices.

 

 

 

Note 10 — Debt Obligations

 

At September 30, 2014 and December 31, 2013, debt consisted of the following:

 

		September 30, 2014				December 31, 2013
		(in thousands)
Convertible Notes, 8.5%, due October 2017, net of discount of ($14.9) million at September 30, 2014 and ($18.3) million at December 31, 2013		$	153,780			$	125,416
Convertible Notes, 6.5%, due March 2015, net of discount of ($1.1) million at September 30, 2014 and ($4.4) million at December 31, 2013			58,849				81,523
			212,629				206,939
Less: Current maturity of long-term debt			58,849				-
Long-term debt, net		$	153,780			$	206,939

 

Convertible Notes due 2017

 

During the third quarter of 2013, the Company closed on an offering for an aggregate principal amount of $143.8 million of convertible notes due 2017, which includes the exercise of the underwriter’s option to purchase an additional $18.8 million of the 2017 Convertible Notes in addition to the original offering of $125.0 million. The 2017 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 and rank senior in the right of payment to all of our existing and future subordinated debt.  The 2017 Convertible Notes are effectively subordinate to any secured indebtedness the Company may have to the extent of the value of the assets collateralizing such indebtedness.  The 2017 Convertible Notes are not guaranteed by the Company’s subsidiaries. In April 2014, $26.0 million of the aggregate principal amount of the 2015 Convertible Notes were exchanged for an additional $25.0 million aggregate principal amount of 2017 Convertible Notes in a private transaction. As a result, the Company has $168.7 million principal amount of 2017 Convertible Notes outstanding at September 30, 2014.

 

The interest rate on the 2017 Convertible Notes is 8.50% per year with interest payments due on April 1st and October 1st of each year.  The 2017 Convertible Notes mature with repayment of the $168.7 million principal amount (assuming no conversion) on October 1, 2017 (the “2017 Maturity Date”).

 

The conversion rate is 249.5866 shares per $1,000 principal amount (equal to an initial conversion price of approximately $4.0066 per share of common stock). Upon conversion, if conversion is elected by the noteholders, the Company must deliver, at its option, either (1) a number of shares of its common stock determined as set forth in the Indenture dated September 24, 2013 (the “2013 Indenture”), (2) cash, or (3) a combination of cash and shares of its common stock.

 

Holders may convert their 2017 Convertible Notes at their option at any time prior to the close of business on the second business day immediately preceding the 2017 Maturity Date under any of the following circumstances:

 

(1) during any fiscal quarter (and only during such fiscal quarter) commencing after October 1, 2013, 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 2017 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 July 1, 2017, 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 2017 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; or

 

(3) upon the occurrence of one of a specified number of corporate transactions.

 

Holders may also convert the 2017 Convertible Notes at their option at any time beginning on July 1, 2017, and ending at the close of business on the second business day immediately preceding the 2017 Maturity Date or may hold the 2017 Convertible Notes to maturity and be paid their outstanding principal in cash.

 

The Company may not redeem the 2017 Convertible Notes prior to the 2017 Maturity Date.

 

 

If the Company experiences any one of certain specified types of corporate transactions, holders may require the Company to purchase all or a portion of their 2017 Convertible Notes. Any repurchase of the 2017 Convertible 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 2013 Indenture for the 2017 Convertible Notes 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 2017 Convertible Notes.

 

Net proceeds from the sale of the 2017 Convertible Notes, after deducting the discounts and commissions and any offering expenses payable by the Company, were approximately $124.5 million.  The 2017 Convertible Notes were issued with a 10% discount or $14.4 million. The underwriter received commissions of approximately $4.3 million in connection with the sale and the Company incurred $0.6 million of direct expenses in connection with the offering.  The Company used the net proceeds for general corporate purposes, including funding its exploration and production efforts, other projects and to reduce or refinance its outstanding debt.

 

The Company accounts for the 2017 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 2017 Convertible Notes. 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 2017 Convertible Notes to be 12.9%. The 12.9% 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 underwriter. Using the income method and discounting the principal and interest payments of the 2017 Convertible Notes using the 12.9% non-convertible borrowing rate, the Company estimated the fair value of the $143.8 million 2017 Convertible Notes to be approximately $124.5 million, with the discount being approximately $19.3 million. The discount of $19.3 million includes the 10% discount of $14.4 million and the value of the equity component of $4.9 million. The discount is being amortized as non-cash interest expense over the life of the 2017 Convertible Notes using the effective interest method. In addition, the Company allocated approximately $2.3 million of the $4.9 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. Approximately $0.1 million of fees and commissions were treated as transaction costs associated with the equity component and the remaining $2.5 million was expensed to other expense under the caption “Other income (expense)” in the third quarter of 2013.

 

As a result of the exchange during the second quarter of 2014, the Company estimated its non-convertible borrowing rate at the date of issuance of the $25.0 million 2017 Convertible Notes to be 7.89%. The 7.89% 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 a financial advisor. Using the income method and discounting the principal and interest payments of the 2017 Convertible Notes with the 7.89% non-convertible borrowing rate, the Company estimated the fair value of the $25.0 million 2017 Convertible Notes to be approximately $25.4 million, with the premium being approximately $0.4 million. The value of the equity component was estimated at $0.5 million. The premium is being amortized as non-cash interest expense over the life of the 2017 Convertible Notes using the effective interest method. In addition, approximately $0.3 million of fees were considered debt issue costs that are being amortized as a non-cash interest expense over the life of the notes using the effective interest method. The Company recognized a loss on this transaction of approximately $0.9 million and this loss was included in the “Loss on extinguishment of debt” in the consolidated statement of operations in the second quarter of 2014. For further information on debt issue costs see Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets.”

 

 

  

The following table shows the estimated remaining cash payments as of September 30, 2014, including interest payments related to the 2017 Convertible Notes, assuming no conversion (in thousands):

  

Year
2014		$	-
2015			14,340
2016			14,340
2017			183,051
Total estimated remaining cash payments related to the 2017 Convertible Notes		$	211,731

 

The Company evaluated the 2013 Indenture for the 2017 Convertible Notes 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 September 30, 2014, the net amount of $153.8 million includes the $168.7 million of principal reduced by $14.9 million of the remaining unamortized discount. The remaining unamortized discount of $14.9 million will be amortized into interest expense, using the effective interest method, over the remaining life of the 2017 Convertible Notes, which mature in October 2017.  At September 30, 2014, using the conversion rate of 249.5866 shares per $1,000 principal amount of the 2017 Convertible Notes, if the $168.7 million of principal were converted into shares of common stock, the notes would convert into approximately 42.1 million shares of common stock.  As of September 30, 2014, there is no excess if-converted value to the holders of the 2017 Convertible Notes as the price of the Company’s common stock at September 30, 2014, $1.91 per share, is less than the conversion price.

 

The annual effective interest rate on the 2017 Convertible Notes, including the amortization of debt issue costs, is approximately 12.5%.

 

The following table shows the amount of interest expense related to the 2017 Convertible Notes, disregarding capitalized interest considerations, for the three and nine months ended September 30, 2014 and 2013, respectively:

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Interest expense related to the contractual interest coupon		$	3,585			$	204			$	10,170			$	204
Amortization of debt discount expense			994				-				2,947				-
Amortization of debt issue costs			159				-				451				-
Interest expense related to the 2017 Convertible Notes		$	4,738			$	204			$	13,568			$	204

 

 

Convertible Notes due 2015

 

During the first quarter of 2010, the Company closed on a private offering for an aggregate principal amount 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 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. In September 2013, the Company repurchased $85.0 million of the aggregate principal amount of the $170.9 million 2015 Convertible Notes, leaving a principal balance of $85.9 million. In April 2014, $26.0 million of the aggregate principal amount of the 2015 Convertible Notes were exchanged for an additional $25.0 million aggregate principal amount of 2017 Convertible Notes in a private transaction. As a result, the Company has $59.9 million principal amount of 2015 Convertible Notes outstanding at September 30, 2014.

 

The interest rate on the 2015 Convertible Notes is 6.50% per year with interest payments due on March 1st and September 1st of each year.  The 2015 Convertible Notes mature with repayment of the remaining principal balance of $59.9 million (assuming no conversion) on March 1, 2015 (the “2015 Maturity Date”).

 

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 dated February 8, 2010 (the “2010 Indenture”). As a result, the conversion rate and conversion price changed to 169.0082 shares per $1,000 principal amount and $5.9169 per share of common stock, respectively. Upon conversion, if conversion is elected by the noteholders, the Company must deliver, at its option, either (1) a number of shares of its common stock determined as set forth in the 2010 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 2015 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 2015 Maturity Date or may hold the 2015 Convertible Notes to maturity and be paid their outstanding principal in cash.

 

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.

 

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 2015 Convertible 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 2010 Indenture for the 2015 Convertible Notes 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 $170.9 million of 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 2015 Convertible Notes. 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 2015 Convertible 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 net amount of the equity component was $33.3 million, which included the initial discount of $34.6 million reduced by $1.3 million of direct transaction costs.

 

 

 

In September 2013, the Company repurchased $85.0 million of aggregate principal amount of the 2015 Convertible Notes. As a result of the $85.0 million repurchase during the third quarter of 2013, approximately $12.2 million of the repayment was considered a retirement of debt and the remaining $72.8 million of the repayment was considered an exchange of debt and not deemed a substantial modification of debt. The $85.0 million of 2015 Convertible Notes were repurchased with an approximate discount of 10%. The Company recognized a gain on the retirement of the debt of approximately $0.2 million and this gain was included in the “Loss on extinguishment of debt” in the consolidated statement of operations in the third quarter of 2013. 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 exchange during the second quarter of 2014, the $26.0 million of aggregate principal amount of 2015 Convertible Notes exchanged was considered a retirement of debt and deemed a substantial modification of debt. The $26.0 million of 2015 Convertible Notes were exchanged with an approximate discount of 4%. The Company recognized a loss on the retirement of the debt of approximately $0.3 million and this loss was included in the “Loss on extinguishment of debt” in the consolidated statement of operations in the second quarter of 2014. For further information on debt issue costs see Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets.”

 

The following table shows the estimated remaining cash payments as of September 30, 2014, including interest payments related to the 2015 Convertible Notes, assuming no conversion (in thousands):

  

Year
2014		$	-
2015			61,837
Total estimated remaining cash payments related to the 2015 Convertible Notes		$	61,837

 

 

The Company evaluated the 2010 Indenture for the 2015 Convertible Notes 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 September 30, 2014, the net amount of $58.8 million of 2015 Convertible Notes outstanding includes the $59.9 million of principal reduced by $1.1 million of the remaining unamortized discount. The remaining unamortized discount of $1.1 million will be amortized into interest expense, using the effective interest method, over the remaining life of the 2015 Convertible Notes, which mature in March 2015.  At September 30, 2014, using the conversion rate of 169.0082 shares per $1,000 principal amount of the 2015 Convertible Notes, if the $59.9 million of principal were converted into shares of common stock, the notes would convert into approximately 10.1 million shares of common stock.  As of September 30 2014, 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 September 30, 2014, $1.91 per share, is less than the conversion price.

 

For the three and nine months ended September 30, 2014, the annual effective interest rate on the 2015 Convertible Notes, including the amortization of debt issue costs, was approximately 12.0%.

 

 

 

The following table shows the amount of interest expense related to the 2015 Convertible Notes, disregarding capitalized interest considerations, for the three and nine months ended September 30, 2014 and 2013:

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Interest expense related to the contractual interest coupon		$	973			$	2,671			$	3,412			$	8,226
Amortization of debt discount expense			680				1,529				2,272				5,182
Amortization of debt issue costs			177				245				603				740
Interest expense related to the 2015 Convertible Notes		$	1,830			$	4,445			$	6,287			$	14,148

 

 

$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”), whereby 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 in the second quarter of 2013. Approximately $1.4 million representing the remaining unamortized debt issue costs on the loan was expensed as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations when the Company prepaid the remaining principal in the second quarter of 2013.

 

As a result of the prepayment and amendment during the second quarter of 2012, the Company incurred $5.8 million of fees and 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.

 

The $75.0 million secured debt facility, as amended, provided for an ongoing fee through July 2014 payable by BPZ E&P to the lenders, of 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, the Company, through its subsidiaries, completed a credit agreement with Credit Suisse whereby 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 September 2013, the Company prepaid the remaining principal balance of the $40.0 million secured debt facility.    

 

In 2013, the $14.5 million of proceeds from the amended and restated $40.0 million secured debt facility was utilized to meet the Company’s 2013 capital, exploration and development work programs as well as for 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) to increase 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 was originally planned to be amortized over the remaining term, ending in January 2015, using the effective interest method.

 

As a result of the prepayment of the remaining principal balance during the third quarter of 2013, the Company incurred $2.0 million in fees and prepayment premium. The $2.0 million in fees and prepayment premium were recognized as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations in the third quarter of 2013. Approximately $1.7 million representing the remaining unamortized debt issue costs on the loan was expensed as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations when the Company prepaid the remaining principal in the third quarter of 2013.

 

The $40.0 million secured debt facility, as amended, provided for ongoing fees through July 2013 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.” 

 

Interest Expense

 

The following table is a summary of interest expense for the three and nine months ended September 30, 2014 and 2013:

  

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Interest expense		$	6,596			$	5,796			$	19,896			$	19,365
Capitalized interest expense			(3,300	)			(2,237	)			(9,250	)			(7,228	)
Interest expense, net		$	3,296			$	3,559			$	10,646			$	12,137

 

 

Note 11 — Derivative Financial Instruments

 

Objective and Strategies for Using Derivative Instruments:

 

In connection with the $40.0 million secured debt facility through July 2013 and the $75.0 million secured debt facility through July 2014, the Company and Credit Suisse agreed that a portion of the arranger fee would be based on the performance for oil prices and be payable at each of the principal repayment dates.  The fee is calculated by multiplying the principal payment amount by the change in oil prices from the loan origination date and the oil price at each 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 changes in value reflected as a gain or loss on derivatives in the accompanying Consolidated Statements of Operations. The following table sets forth a reconciliation of the changes in fair value of the Company’s derivative financial instruments for the nine months ended September 30, 2014 and the year ended December 31, 2013:

 

Derivative Financial Instruments Not Designated as Hedging Instruments

 

 

		2014				2013
		(in thousands)
Beginning fair value of derivatives		$	30			$	2,984
(Gain) loss on derivatives			(2	)			(242	)
Cash settlements paid			(28	)			(2,712	)
Ending fair value of derivatives		$	-			$	30

 

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.

 

 

 

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 convertible debt agreements, outstanding stock options, shares of restricted stock or performance stock units, 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								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands, except per share data)
Net loss		$	(45,292	)		$	(15,321	)		$	(51,411	)		$	(47,745	)
Shares:
Basic weighted average common shares outstanding			116,399				116,009				116,262				115,911
Incremental shares from assumed conversion of dilutive share based awards			-				-				-				-
Diluted weighted average common shares outstanding			116,399				116,009				116,262				115,911
Excluded share based awards (1) (2)			7,999				8,020				7,999				8,020
Excluded 2017 convertible debt shares (1)			42,108				35,878				42,108				35,878
Excluded 2015 convertible debt shares (1)			10,122				14,516				10,122				14,516
Basic net loss per share		$	(0.39	)		$	(0.13	)		$	(0.44	)		$	(0.41	)
Diluted net loss per share		$	(0.39	)		$	(0.13	)		$	(0.44	)		$	(0.41	)

 

(1) Inclusion of the shares for these awards would have had an antidilutive effect.

(2) Inclusion of the performance share units for these awards would have had an antidilutive effect. The actual number of performance share units earned may range from 0% to 200%.

 

The following table summarizes stock-based compensation costs recognized under ASC Topic 718, “Stock Compensation,” for the three and nine months ended September 30, 2014 and 2013, respectively, which are included in “General and administrative expense” on the Consolidated Statements of Operations:

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Employee stock—based compensation costs		$	584			$	879			$	1,788			$	2,183
Director stock—based compensation costs			179				157				548				450
Employee stock purchase plan costs			2				2				6				8
		$	765			$	1,038			$	2,342			$	2,641

 

 

 

Stock Option, Restricted Stock and Performance Share Plans

 

The Company has in effect the 2007 Long-Term Incentive Compensation Plan, as amended in 2010 and 2014 to increase the number of shares available (the “2007 LTIP”), and the 2007 Directors’ Compensation Incentive Plan (the “Directors’ Plan”). The 2007 LTIP and 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 the 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 12.0 million and 4.0 million, respectively, which includes an additional 4.0 million shares related to the 2007 LTIP and 1.5 million shares related to the Directors’ Plan approved by the Company’s shareholders on June 20, 2014. As of September 30, 2014, approximately 4.5 million shares remain available for future grants under the 2007 LTIP and 1.8 million shares remain available for future grants under the Directors’ Plan.

 

Restricted Stock Awards and Performance Stock Units

 

Restricted Stock

 

On February 20, 2014, the Company’s Board of Directors awarded 724,389 shares of restricted stock to officers and other key employees under the Company’s 2007 LTIP. On August 1, 2014, the Company’s Board of Directors awarded 16,700 shares of restricted stock to key employees under the Company’s 2007 LTIP. The restricted stock awards generally vest on the second anniversary of the grant date, or may vest equally over three years of the grant date. For the nine months ended September 30, 2014, the weighted average grant date fair value per share of the restricted stock granted was $2.18.

 

On February 20, 2014, the Company awarded its non-employee directors a total of 347,220 shares of restricted stock under the Directors’ Plan. On August 27, 2014, the Company awarded its non-employee directors a total of 20,921 shares of restricted stock under the Directors’ Plan. The restricted stock awards generally vest on the second anniversary of the grant date. For the nine months ended September 30, 2014, the weighted average grant date fair value per share of the restricted stock granted was $2.17.

 

Performance Stock Units

 

On February 20, 2014, the Company’s Board of Directors awarded 225,695 shares of performance stock units, which are referred to by the Company as Relative Performance Stock Units, to officers under the Company’s 2007 LTIP. Shares of the Company's common stock will be issued following the vesting of the Relative Performance Stock Units determined based on the level of achievement of the performance measure at the end of the performance period (from January 1, 2014 through December 31, 2016).  The actual number of shares of Company common stock to be issued at payment is measured on a three-year cumulative stock price basis relative to a selected peer group and can range from a minimum of 0% of the number of shares of Company common stock granted to a maximum of 200% of the number of shares of Company common stock granted.

 

Compensation expense associated with these Relative Performance Stock Units is based on the grant date fair value of a single Relative Performance Stock Unit as determined using a Monte Carlo simulation model.  As the Company intends to settle these Relative Performance Stock Units with shares of the Company’s common stock at the end of the performance period, the Relative Performance Stock Unit awards are accounted for as equity awards and the expense is calculated on the grant date and amortized over the life of the Relative Performance Stock Unit awards. The grant date fair value per share of the Relative Performance Stock Unit award granted was $2.12.

 

In addition, on February 20, 2014, the Company’s Board of Directors awarded 225,694 shares of performance stock units, which are referred to by the Company as Absolute Performance Stock Units, to officers under the Company’s 2007 LTIP. Shares of the Company's common stock will be issued following the vesting of the Absolute Performance Stock Units determined based on the level of achievement of the performance measure at the end of the performance period (from January 1, 2014 through December 31, 2016).  The actual number of shares of the Company common stock to be issued at payment is measured on a three-year cumulative stock price basis relative to pre-established stock price goals and can range from a minimum of 0% of the number of shares of Company common stock granted to a maximum of 200% of the number of shares of Company common stock granted.

 

Compensation expense associated with these Absolute Performance Stock Units is based on the grant date fair value of a single Absolute Performance Stock Unit as determined using a Monte Carlo simulation model.  As the Company intends to settle these Absolute Performance Stock Units with shares of the Company’s common stock at the end of the performance period, the Absolute Performance Stock Unit awards are accounted for as equity awards and the expense is calculated on the grant date and amortized over the life of the Absolute Performance Stock Unit awards. The grant date fair value per share of the Absolute Performance Stock Unit award granted was $0.80.

 

 

 

Stock Options

 

Incentive and non-qualified stock options issued to directors, officers, employees and consultants are typically granted at the fair market value on the date of grant. The Company’s stock options generally vest in equal annual installments over a two to three year period and expire ten years from the date of grant. There have been no stock options awarded in 2014.

 

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 September 30, 2014, 1,917,512 shares were available for issuance. On October 1, 2014, 5,166 shares were issued to employees at a price of $1.62 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.

 

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 associated with the Company’s long-term assets, short-term debt and long-term debt. 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 (through July 2013), the $75.0 million secured debt facility (through July 2014) 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 is as follows:

 

			Fair Value Measurements Using:
			Quoted				Significant
			Prices in				Other				Significant
			Active				Observable				Unobservable
	Balance Sheet		Markets				Inputs				Inputs
	Location		(Level 1)				(Level 2)				(Level 3)
			(in thousands)
September 30, 2014
Financial Liabilities
Derivative Financial Instruments
	Current Liabilities		$	-			$	-			$	-
	Non-current Liabilities			-				-				-
			$	-			$	-			$	-
December 31, 2013
Financial Liabilities
Derivative Financial Instruments
	Current Liabilities		$	-			$	30			$	-
	Non-current Liabilities			-				-				-
			$	-			$	30			$	-

 

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. The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.

 

  

Fair Value Measurements Using:

Quoted

Significant

Prices in

Other

Significant

Active

Observable

Unobservable

Markets

Inputs

Inputs

Before-Tax

(Level 1)

(Level 2)

(Level 3) (a)

Loss

(in thousands)

Nine Months Ended September 30, 2014

Long-lived assets held for use -

Power plant and related equipment

$

-

$

-

$

49,801

$

41,000

 

(a) Represents fair value at the time of impairment.

  

 

The long-lived assets held for use are impaired to their fair values. The fair value was measured using an probability weighted average income approach and considered project specific assumptions for future project operating revenues and costs and expected plant construction and operations, anticipated proceeds in the event a sale of the assets and the estimated value to be received in the event the assets were included in a joint venture operation.

 

  

Additional Fair Value Disclosures

 

Debt with Fixed Interest Rates

 

The fair value information regarding the Company’s fixed rate debt at September 30, 2014 and December 31, 2013 is as follows:

 

		September 30, 2014								December 31, 2013
		Carrying Amount				Fair Value				Carrying Amount				Fair Value
		(in thousands)								(in thousands)
Convertible Notes, 8.5%, due October 2017, net of discount of ($14.9) million at September 30, 2014 and ($18.3) million at December 31, 2013 (1)		$	153,780			$	159,665			$	125,416			$	130,094
Convertible Notes, 6.5%, due March 2015, net of discount of ($1.1) million at September 30, 2014 and ($4.4) million at December 31, 2013 (2)			58,849				58,992				81,523				79,663

---

(1)

The Company estimated the fair value of the 2017 Convertible Notes to be approximately $159.7 million and $130.1 million at September 30, 2014 and December 31, 2013, respectively, based on observed market prices for the same or similar types of debt issues. The fair value of the 2017 Convertible Notes is considered to be a Level 1 measurement on the fair value hierarchy.

 

(2)

The Company estimated the fair value of the 2015 Convertible Notes to be approximately $59.0 million and $79.7 million at September 30, 2014 and December 31, 2013, respectively, based on observed market prices for the same or similar types of debt issues. The fair value of the 2015 Convertible Notes is considered to be a Level 1 measurement on the fair value hierarchy.

 

Note 14 — Revenue

 

The oil produced is delivered by vessel to the refinery owned by the Peruvian national oil company, Petroleos del Peru - PETROPERU S.A. (“Petroperu”), in Talara, located approximately 70 miles south of the platforms.  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 the loss of Petroperu as its sole customer would not materially impact the Company’s business because it could readily find other purchasers for its 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.

 

The following table shows the amount of royalty costs related to gross revenues for the three and nine months ended September 30, 2014 and 2013:

  

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Royalty costs		$	1,114			$	665			$	3,668			$	2,068
		$	1,114			$	665			$	3,668			$	2,068

 

Note 15 — Standby Costs

 

For the three and nine months ended September 30, 2014, the Company incurred no standby costs.

 

For the three and nine months ended September 30, 2013, the Company incurred $0.7 million and $4.1 million, respectively, of standby costs. During the three months ended September 30, 2013, the Company had Petrex-21 rig on standby for approximately two months. During the nine months ended September 30, 2013, the Company had the Petrex-10 rig partially or fully on standby for approximately three months and two rigs, the Petrex-28 rig and Petrex-21 rig, partially or fully on standby for approximately five months.

 

 

 

Note 16— Other Operating Expense

 

For the three and nine months ended September 30, 2014, the Company incurred no other operating expense.

 

For the three and nine months ended September 30, 2013, the Company reported $2.7 million of other operating expense. The Company expensed costs related to historical pre-development drilling studies for drilling locations and platform technologies and associated capitalized interest as it believes that these locations and technologies may change and it does not see a future value of these studies.

 

Note 17 — Income Tax

 

The following is a summary of income (loss) before income taxes and income tax expense (benefit) for the three and nine months ended September 30, 2014 and 2013:

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Income (loss) before income taxes:
United States		$	(27,561	)		$	(16,287	)		$	(37,504	)		$	(25,480	)
Foreign			(15,103	)			(4,805	)			(7,204	)			(28,083	)
		$	(42,664	)		$	(21,092	)		$	(44,708	)		$	(53,563	)
Income tax expense (benefit):
United States		$	-			$	-			$	-			$	668
Foreign			2,628				(5,771	)			6,703				(6,486	)
		$	2,628			$	(5,771	)		$	6,703			$	(5,818	)

 

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 2033. Furthermore, because the Company has no operations within the U.S. taxing jurisdiction, it is likely that sufficient generation of revenue to offset the Company’s deferred tax asset is remote.

 

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

 

During the three and nine months ended September 30, 2014, the Company recorded a valuation allowance of $8.0 million on the deferred tax assets of its foreign subsidiary engaging in the development of the gas-to-power project, as the Company considered it more likely than not that a portion or all of the subsidiary's deferred tax assets will not be realized. Further, the Company will place a valuation allowance on future deferred tax assets of that same foreign subsidiary until the Company believes it is more likely than not the deferred tax assets will be realized. There was no similar adjustment for the three and nine months ended September 30, 2013.

 

The September 30, 2014 and December 31, 2013 balance of unrecognized tax benefits includes $0.7 million that, if recognized, would impact the Corporation’s effective income tax rate. Over the next 12 months, the Company does not anticipate any reduction in the balance. The Company had accrued interest and penalties related to unrecognized tax benefits of $46,000 at both September 30, 2014 and December 31, 2013. Estimated interest and penalties related to potential underpayment on unrecognized tax benefits, if any, are classified as a component of income tax expense in the Consolidated Statement of Operations.

 

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 nine months ended September 30, 2014 and 2013, 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, 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 profit sharing rate at 8%. However, in Peru, the Hydrocarbon Law states, and the Supreme Court ruled, that hydrocarbons are not related to mining activities. Hydrocarbons are included under “Companies Performing Other Activities,” thus Oil and Gas Companies pay profit sharing at a rate of 5%. The 5% of income is determined by calculating a percentage of the Company’s Peruvian subsidiaries’ annual total revenues subject to income tax less the expenses required to produce revenue or maintain the source of revenues. The benefit granted by the law to employees is calculated on the basis of “income subject to taxation” per the Peruvian tax code, and not based on income (loss) before income taxes as reported under GAAP. For the three and nine months ended September 30, 2014 and 2013, 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 declaring commercial production in the Corvina field, which allowed certain exploration and development costs to be deductible in 2014 and 2013 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 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, or the power generation facility may be wholly owned by a third party. 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 proceed with the project.

 

Santa Elena Field

 

In 2013, in order to extend the term of the contract from 2016 to 2029, the Consortium, which includes the Company and three other partners, agreed to additional work commitments to increase production in the Santa Elena field. The Company’s total share of this commitment over the remaining life of the contract is $5.0 million (the Company’s 10% non-operating net profits interest) which amount is due for the remainder of 2014 to 2028. This commitment is expected to be funded by cash on hand, cash generated from new production, or loans of the Consortium. If the Consortium does not have sufficient cash on hand, the Company may elect to make a cash contribution to the Consortium for its 10% share of the commitment. If the Company elects not to make its 10% share contribution of the commitment, it would lose its rights in the Consortium and the contract for the Santa Elena field.

 

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 potentially 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.

 

 

 

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, 2013. In addition, you should read our Risk Factors in the Form 8-K Exhibit 99.3, filed on October 2, 2014.

 

 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 an independent oil and gas company 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 development of a gas-fired power generation facility in Peru, which we may wholly- or partially-own, or may be wholly-owned by a third party.

 

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 the license contracts for oil and gas exploration and production covering approximately 2.2 million gross (1.9 million net) acres in four blocks in northwest Peru, and off the northwest coast of Peru in the Gulf of Guayaquil. Our 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 an additional three years up 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 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. Our estimate of proved reserves has been prepared under the assumption that our license contract will allow production for the possible 40-year term for both oil and gas.

 

We also 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”). In May 2013, the license agreement and operating agreement covering the property were extended from May 2016 through December 2029.

 

We are in the process of developing our Peruvian oil and gas reserves. 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 also spudded a development well from the A platform in the Albacora field of Block Z-1 in September 2013. We spudded an exploratory well in Block XXIII in January 2014.

 

From the time we began producing from the Corvina field in November 2007 and the Albacora field in December 2009, through September 30, 2014, the two fields have produced approximately 7.2 MMBbls (100% gross and net through December 14, 2012 and 51% net participating interest thereafter) of oil.

 

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 terms of the agreements signed on April 27, 2012, we (together with our subsidiaries) formed an unincorporated joint venture 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, 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 (“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.

 

 

 

At December 31, 2013, we had estimated net proved oil reserves of 16.1 MMBbls, of which 12.7 MMBbls were in the Corvina field and 3.4 MMBbls were from the Albacora field. Both fields are located in Block Z-1 offshore of northwest Peru.  Of our total proved reserves, 3.2 MMBbls (19.9%) are classified as proved developed reserves, which includes both proved developed producing and proved developed non-producing reserves from 11 gross (5.6 net) wells, and 12.9 MMBbls (80.1%) are classified as proved undeveloped reserves. The process of estimating oil and natural gas reserves is complex and requires many interpretations of available data and assumptions that may turn out to be inaccurate. 

 

Our current activities and related planning are focused on the following objectives:

 

●

At Block Z-1 with our joint venture partner, Pacific Rubiales;

 

●

Continuing the offshore development drilling campaign from the Corvina CX-15 platform and Albacora platform;

 

●

Optimizing oil production in the Corvina and Albacora fields in Block Z-1;

 

●

Analyzing the data from the 3-D seismic survey in Block Z-1 to guide further exploration and development activities within the Block;

 

●

Working with our Block Z-1 partner, Pacific Rubiales, to continue to develop the Corvina and Albacora fields;

 

●

Exploring the remainder of the Block, starting with the Delfin prospect where we have received the permit to install a platform and begin exploratory drilling;

 

●

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

 

●

Executing an exploratory drilling campaign in Block XXIII;

 

●

Planning and permitting an onshore drilling campaign to explore and appraise Block XXII 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 the Corvina field but for which no market has yet been secured and related financing has yet to be obtained.

 

Our activities in Peru 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 valuable knowledge of oil and gas operations throughout Latin America and, in particular, Peru.

 

 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 Block Z-1 in our first well in the Corvina field in 2007, and our first well in Albacora in December 2009, we are focusing on development of the proved oil reserves in those two fields. Before considering further drilling activity in Block XIX we are planning to acquire additional seismic data. In Block XXII, the environmental assessment process for an environmental permit is underway and approval must be received before anticipated drilling can begin in 2015. In January 2014, we spudded the first of three exploration wells, the Caracol 1X, in Block XXIII. The Cardo 2X exploratory well was spud in late March 2014 and the Piedra Candela 3X exploratory well was spud in late April 2014.

 

In the near term, management is focused on drilling operations at both the CX-15 platform in the Corvina field and at the A platform in the Albacora field, utilizing the results of the 1,600 square kilometers (“km”) of three dimensional (“3-D”) seismic survey in Block Z-1, and three exploratory wells in Block XXIII.

 

Credit Suisse Securities (USA) LLC is managing the formal process to find a joint venture partner for Blocks XIX and XXIII. 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 would be in the best interests of the Company to further de-risk the Block XXIII prospects after the drilling of three shallow exploratory wells on the large anticline identified by 3-D seismic to prove the existence of hydrocarbons before pursuing further partnering opportunities.

 

In addition, our business plan includes a gas-to-power project as part of our overall gas marketing strategy, which entails the installation of a 10 mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and the building of an approximately 135 megawatt (“MW”) simple cycle electric generating plant. The proposed power plant site is located adjacent to an existing substation and power transmission lines which, with certain upgrades, are expected to be capable of handling up to 420 MW of power. The power generation facility may be part- or wholly-owned by us, or wholly-owned by a third party. The gas-to-power project is planned to generate a revenue stream by creating a market for the non-associated gas in our Corvina field that is currently shut-in. This project has not yet been financed and we continue to consider the alternatives for the project. Meanwhile, we have obtained certain permits and are in the process of obtaining additional permits to proceed 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 and consultation with our joint venture partner with respect to Block Z-1.  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.

 

Further, our ability to produce reserves in the Corvina and Albacora fields 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 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.

 

Block Z-1

 

The Block Z-1 License Contract provides for an initial exploration phase of seven years, and exploration can continue in the exploitation phase for an additional six years (in three two-year periods). Each period has a commitment for exploration activities and requires a financial guarantee to secure the performance of the work commitment during such period. We are in the exploitation phase in Block Z-1 which requires one exploration well or 225 exploration work units in each of the three two-year periods. We received approval from Perupetro for the initial two-year period and have committed to drill an exploratory well. The initial two-year phase was originally set to expire in January 2015, but has been extended to July 2015. At the end of the third two-year period, we will be required by the License Contract to surrender back to Perupetro all unexplored areas in Block Z-1.

 

 

 

Divestiture

 

On April 27, 2012, we and Pacific Rubiales (together with its subsidiaries) 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.

 

The development of Block Z-1 is subject to terms and conditions of a Joint Operating Agreement with Pacific Rubiales that governs the legal, technical and operating rights and obligations of the parties with respect to the operation of Block Z-1. Under the agreement we are the operator and responsible for the administrative, regulatory, government and community related duties, and Pacific Rubiales manages the technical and operating duties in Block Z-1. The Joint Operating Agreement will continue for the term of the License Contract and thereafter until all decommissioning obligations under the License Contract have been satisfied.

 

At September 30, 2014 and December 31, 2013, the carry amount was $23.8 million and $81.3 million, respectively.

 

At September 30, 2014 and December 31, 2013, we reflected $40.7 million and $23.9 million, respectively, as other current liabilities and zero and $16.8 million, respectively, as other non-current liabilities for exploratory expenditures related to Block Z-1 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.  On the CX-11 platform, we have completed a total of nine gross (4.6 net) oil wells, one of which is being used as a gas injection and/or water well. Produced oil is kept in production inventory until such time as 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.

    

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. Modifications were made to the platform monitoring and control systems necessary to facilitate operation of the CX-15 platform. 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, the CX15-1D, from the new CX-15 platform. Production from the CX15-1D well began in October 2013. We spudded the second development well, the CX15-2D, in November 2013. The CX15-2D well was drilled near the existing CX11-18XD well to a measured depth of approximately 9,000 feet. We completed the CX15-2D well in January 2014. Production from the CX15-2D well began in February 2014. We spudded the CX15-3D development well in February 2014 and production began in April 2014. In July 2014, the CX-15-3D well was shut in due to high water production. The well was then evaluated to determine the appropriate work plan. The CX15-3D well returned to production in September 2014. We spudded the CX15-5D development well in April 2014 and production began in July 2014. The CX15-7D development well was spud in July 2014 and production began in September 2014. The CX15-10D development well was spud in September 2014 and completed in October 2014. The CX15-14D development well was spud in October 2014.

 

 

 

Production at each of the Corvina oil 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. The wells 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. We believe that our 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 in our public filings pursuant to SEC requirements. 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.

  

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 100 feet. We currently have completed a total of eight gross (4.1 net) oil wells, one of which is currently being used as a gas injector and/or water injection well. 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 gas and water reinjection equipment was completed on the Albacora A platform 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.

 

We spudded a development well, the A-18D well, from the A platform in the Albacora field of Block Z-1 in September 2013. This well was completed in December 2013. The A-18D well, which began producing at the end of 2013, was shut-in in late March 2014 due to gas intrusion. The well was sidetracked to a depth of 13,600 feet which is 1,000 feet deeper than the original A-18D well depth. The A-18D side track well was completed in September 2014 and production began in September 2014 and has been under production testing to evaluate the new deeper oil zones. We also spudded a development well, the A-19D well, from the A platform in the Albacora field of Block Z-1 on January 1, 2014. The A-19D well began production on March 1, 2014. The A-21D development well was spud in early March 2014 and production began in May 2014. In July 2014, the A-21D well was shut in due to high water production. The well was then evaluated to determine the appropriate work plan. The A-21D well returned to production in September 2014. We spudded the A-26D development well in May 2014 and production began in July 2014. The A-27D development well was spud in October 2014.

  

Block Z-1 Seismic

 

We completed the 3-D seismic survey in February 2013 and seismic data processing of the area in September 2013 to assess our prospects before conducting further drilling operations, as well as to comply with our exploration commitments under our Block Z-1 License Contract.

  

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

  

Block XIX 

 

We are in the fourth exploration phase in Block XIX which requires 117 exploration work units which will determine our exploration commitment for the period. The fourth exploration phase expires in September 2015.

 

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 phase to further evaluate future drilling locations. The environmental permit for the additional seismic work was received in August 2014 following the environmental assessment process.

 

Block XXII

 

We are in the second exploration phase in Block XXII which requires the drilling of one exploration well.

 

As a result of the 258 km 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 expect to conduct an additional 2-D seismic program 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 in Block XXII will depend on approval of the environmental assessment, which is underway, and subsequent receipt of the necessary ancillary permits. Drilling on Block XXII is expected in 2015.

 

Block XXIII

 

We are in the second exploration phase in Block XXIII which requires 678 exploration work units which will determine the number of wells drilled.

 

In 2011, we acquired approximately 370 square km of 3-D seismic data and 312 km 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 seismic data of 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 were approved in January 2013. We have received approval to move the previously agreed drilling locations to conform to the 3-D seismic results.

 

We spudded an exploration well, the Caracol 1X, on January 5, 2014. This was the first of three exploratory wells drilled in Block XXIII in 2014. The depth of the Caracol 1X well is approximately 3,500 feet. The Cardo 2X exploratory well was spud in late March 2014, and reached a total depth of 3,800 feet in April 2014. The Piedra Candela 3X exploratory well was spud in late April 2014 and reached a total depth of 3,515 feet in May 2014. The Caracol 1X exploratory well tested dry gas from the Mancora formation, light oil from the Heath formation and dry gas from the Zorritos formation. The Cardo 2X exploratory well and the Piedra Candela 3X exploratory well tested dry gas from the Mancora formation. We will pursue a long-term testing program in these Block XXIII prospects.

 

 Marine Operations

 

In December 2013, we entered into a Management Services Agreement with a third party marine operator to manage our marine fleet. We transferred our BPZ Marine Peru S.R.L. employees to the new operator in the fourth quarter of 2013.

 

Gas-to-Power Project

 

Our gas-to-power project entails the planned installation of an approximately 10-mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and a 135 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 retain only a minority position in the project, or the power generation facility may be wholly-owned by a third party. 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 proceed with the project.

  

 

 

Results of Operations

 

The following table sets forth revenues and operating expenses for the three and nine months ended September 30, 2014 and 2013:

  

		Three Months Ended												Nine Months Ended
		September 30,												September 30,
		2014				2013				Increase/ (Decrease)				2014				2013				Increase/ (Decrease)
		(in thousands except per bbl information)												(in thousands except per bbl information)
Net sales volume:
Oil (MBbls)			215				123				92				667				388				279
Net revenue:
Oil revenue, net		$	20,174			$	12,500			$	7,674			$	65,268			$	38,557			$	26,711
Other revenue			176				29				147				313				99				214
Total net revenue			20,350				12,529				7,821				65,581				38,656				26,925
Average sales price (approximately):
Oil (per Bbl)		$	94.03			$	101.46			$	(7.43	)		$	97.92			$	99.42			$	(1.50	)
Operating and administrative expenses:
Lease operating expense			9,383				5,319				4,064				21,350				20,094				1,256
General and administrative expense			5,259				6,572				(1,313	)			17,831				18,498				(667	)
Geological, geophysical and engineering expense			705				857				(152	)			2,796				1,961				835
Depreciation, depletion and amortization expense			4,087				7,246				(3,159	)			16,202				22,105				(5,903	)
Standby costs			-				705				(705	)			-				4,073				(4,073	)
Other operating expense			-				2,683				(2,683	)			-				2,683				(2,683	)
Asset impairments			41,000				-				41,000				41,000				-				41,000
Total operating and administrative expenses		$	60,434			$	23,382			$	37,052			$	99,179			$	69,414			$	29,765
Operating income (loss)		$	(40,084	)		$	(10,853	)		$	(29,231	)		$	(33,598	)		$	(30,758	)		$	(2,840	)

 

Net Oil Revenue

 

For the three months ended September 30, 2014, our net oil revenue increased by $7.7 million to $20.2 million from $12.5 million for the same period in 2013. The increase in net oil revenue is due to an increase in the amount of oil sold of 92 MBbls, partially offset by an decrease of $7.43, or 7.3%, in the average per barrel sales price received. Total sales for the three months ended September 30, 2014 were 215 MBbls compared to 123 MBbls for the same period in 2013.

 

The increase in amount of oil sold for the three months ended September 30, 2014 compared to the same period in 2013 is due to increased production in the Albacora field from the A-18D, A-19D, A-21D and A-26D wells and increased production from the CX-15 platform from the CX15-1D, CX15-2D, CX15-3D, CX15-5D and CX15-7D wells.

 

For the nine months ended September 30, 2014, our net oil revenue increased by $26.7 million to $65.3 million from $38.6 million for the same period in 2013. The increase in net oil revenue is due to an increase in the amount of oil sold of 279 MBbls, partially offset by a decrease of $1.50, or 1.5%, in the average per barrel sales price received. Total sales for the nine months ended September 30, 2014 were 667 MBbls compared to 388 MBbls for the same period in 2013.

 

The increase in amount of oil sold for the nine months ended September 30, 2014 compared to the same period in 2013 is due to increased production in the Albacora field from the A-18D, A-19D, A-21D and A-26D wells and increased production from the CX-15 platform from the CX15-1D, CX15-2D, CX15-3D, CX15-5D and CX15-7D wells.

 

The price/volume analysis is as follows:

 

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		(in thousands)
2013 Oil revenue, net		$	12,500			$	38,557
Changes associated with sales volumes			9,268				27,711
Changes associated with prices			(1,594	)			(1,000	)
2014 Oil revenue, net		$	20,174			$	65,268

 

 

 

 

For the three months ended September 30, 2014, the increase in oil production is due to increased production in the Albacora field as the A-18D, A-19D, A-21D and A-26D wells contributed to production volumes during the third quarter of 2014. At the Corvina field, the declines in production from the wells at the CX-11 platform were more than offset by the new production from the CX-15 platform’s CX15-1D, CX15-2D, CX15-3D, CX15-5D and CX15-7D wells. Total oil production for the three months ended September 30, 2014 was 224 MBbls compared to 122 MBbls for the same period in 2013.

 

For the nine months ended September 30,2014, the increase in oil production is due to increased production in the Albacora field as the A-18D, A-19D, A-21D and A-26D wells contributed to production volumes during 2014. At the Corvina field, the declines in production from the wells at the CX-11 platform were more than offset by the new production from the CX-15 platform’s CX15-1D, CX15-2D, CX15-3D, CX15-5D and CX15-7D wells. Total oil production for the nine months ended September 30, 2014 was 693 MBbls compared to 386 MBbls for the same period in 2013.

 

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 shows the amount of royalty costs related to gross revenues for the three and nine months ended September 30, 2014 and 2013:

  

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Royalty costs		$	1,114			$	665			$	3,668			$	2,068
		$	1,114			$	665			$	3,668			$	2,068

 

Other Revenue

 

For the three months ended September 30, 2014, other revenue increased by $147,000 to $176,000 compared to $29,000 for the same period in 2013.

 

For the nine months ended September 30, 2014, other revenue increased by $214,000 to $313,000 compared to $99,000 for the same period in 2013.

 

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 September 30, 2014, lease operating expenses increased by $4.1 million to $9.4 million ($43.64 per Bbl) from $5.3 million ($43.24 per Bbl) for the same period in 2013. The increase is due to additional operating expenses with Pacific Rubiales of $2.4 million, higher crude oil transportation expense of $2.3 million due to higher crude oil sales and higher maintenance and repairs on vessel support services of $0.5 million, partially offset by lower costs of $0.6 million associated with the change in oil inventory in the three months ended September 30, 2014, compared to the change in oil inventory in the three months ended September 30, 2013, workover expenses decreasing $0.3 million due to no major workovers performed in 2014 compared to one major workover in 2013 and lower other lease operating expenses of $0.2 million.

 

For the nine months ended September 30, 2014, lease operating expenses increased by $1.3 million to $21.4 million ($32.01 per Bbl) from $20.1 million ($51.79 per Bbl) for the same period in 2013. The increase is due to higher crude oil transportation expense of $4.6 million due to higher crude oil sales, additional operating expenses with Pacific Rubiales of $2.4 million and higher maintenance and repairs on vessel support services of $1.2 million, partially offset by workover expenses decreasing $5.0 million due to no major workovers performed in 2014 compared to one major workover in 2013, lower costs of $1.7 million associated with the change in oil inventory in the nine months ended September 30, 2014, compared to the change in oil inventory in the nine months ended September 30, 2013, and lower other lease operating expenses of $0.2 million. 

 

 

 

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 September 30, 2014, general and administrative expenses decreased $1.4 million to $5.2 million from $6.6 million for the same period in 2013.  Stock-based compensation expense, a subset of general and administrative expenses, was $0.7 million for the three months ended September 30, 2014 and $1.0 million for the same period in 2013. Other general and administrative expenses decreased $1.1 million to $4.5 million from $5.6 million for the same period in 2013. The $1.1 million decrease is due to lower salary and related costs of $1.1 million due to fewer employees and lower other general and administrative expenses of $0.7 million, partially offset by a higher ship management fee of $0.4 million and higher indirect charges from our Block Z-1 partner of $0.3 million.

 

For the nine months ended September 30, 2014, general and administrative expenses decreased by $0.7 million to $17.8 million from $18.5 million for the same period in 2013.  Stock-based compensation expense, a subset of general and administrative expenses, was $2.3 million for the nine months ended September 30, 2014 and $2.6 million for the same period in 2013. Other general and administrative expenses decreased $0.4 million to $15.5 million from $15.9 million for the same period in 2013. The $0.4 million decrease is due lower salary and related costs of $2.3 million due to fewer employees and lower other general and administrative expenses of $0.7 million, partially offset by a $1.5 million increase due to higher indirect charges from our Block Z-1 partner and a higher ship management fee of $1.1 million.

 

Geological, Geophysical and Engineering Expense

 

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

 

For the three months ended September 30, 2014, geological, geophysical and engineering expenses decreased $0.2 million to $0.7 million compared to $0.9 million for the same period in 2013. This decrease is due to lower environmental impact assessment work costs to prepare for seismic programs..

 

For the nine months ended September 30, 2014, geological, geophysical and engineering expenses increased $0.8 million to $2.8 million compared to $2.0 million for the same period in 2013. This increase is due to higher overall geological, geophysical and engineering expenses, partially offset by lower environmental impact assessment work costs to prepare for seismic programs.

 

Depreciation, Depletion and Amortization Expense

 

For the three months ended September 30, 2014, depreciation, depletion and amortization expense decreased $3.1 million to $4.1 million from $7.2 million for the same period in 2013. For the nine months ended September 30, 2014, depreciation, depletion and amortization expense decreased $5.9 million to $16.2 million from $22.1 million for the same period in 2013.

 

For the three months ended September 30, 2014, depletion expense decreased $2.7 million to $2.3 million from $5.0 million during the same period in 2013. For the nine months ended September 30, 2014, depletion expense decreased $5.3 million to $10.0 million from $15.3 million during the same period in 2013. Depletion decreased in both periods due to capital costs in Block Z-1 reimbursed under the Carry Agreement with Pacific Rubiales and reserves added to the depletion base in 2014.

 

For the three months ended September 30, 2014, depreciation expense decreased $0.4 million to $1.8 million compared to $2.2 million for the same period in 2013. For the nine months ended September 30, 2014, depreciation expense decreased $0.6 million to $6.2 million compared to $6.8 million for the same period in 2013.

 

Standby Costs

 

For the three months ended September 30, 2014, we incurred no standby costs. During the three months ended September 30, 2013, we incurred $0.7 million in standby costs.

 

During the three months ended September 30, 2013, we had the Petrex-21 rig on standby for approximately two months.

 

 

 

For the nine months ended September 30, 2014, we incurred no standby costs. During the nine months ended September 30, 2013, we incurred $4.1 million in standby costs.

 

During the nine months ended September 30, 2013, we had the Petrex-10 rig either partially or fully on standby for three months and two rigs, the Petrex-28 rig and Petrex-21 rig, partially or fully on standby for approximately five months. 

 

Other Operating Expense

 

For the three and nine months ended September 30, 2014, we incurred no other operating expense.

 

For the three and nine months ended September 30, 2013, we reported $2.7 million of other operating expense. We expensed costs related to historical pre-development drilling studies for drilling locations and platform technologies and associated capitalized interest as we believe that these locations and technologies may change and it does not see a future value of these studies.

 

Asset Impairments

 

For the three and nine months ended September 30, 2014, we incurred impairments of $41.0 million related to our Power plant and related equipment, due to recent developments that may change the extent or manner in which the asset may be used.

 

For the three and nine months ended September 30, 2013, we incurred no asset impairments. 

 

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 September 30, 2014, total other expense decreased $7.6 million to $2.6 million compared to $10.2 million during the same period in 2013.

 

The change is due to the following:

 

Interest expense: For the three months ended September 30, 2014, we recognized approximately $3.2 million of net interest expense, which included $6.6 million of interest expense reduced by $3.4 million of capitalized interest expense. For the same period in 2013, we recognized $3.5 million in net interest expense, which included $5.7 million of interest expense reduced by $2.2 million of capitalized interest. The decrease of $0.3 million in net interest expense is due to higher interest capitalized of $1.2 million from a higher average construction in progress, partially offset by a higher interest expense of $0.9 million resulting from a higher average interest cost of debt outstanding between the periods.

 

Loss on extinguishment of debt: For the three months ended September 30, 2014 and September 30, 2013, respectively, we reported zero and $3.4 million as a loss on extinguishment of debt.

   

As a result of the prepayment of the remaining $36.0 million under the $40.0 million secured debt facility during the third quarter of 2013, we incurred $2.0 million of fees and prepayment premium and expensed $1.7 million of unamortized debt issue costs. These amounts were recognized as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations. As a result of the repurchase of $85.0 million of principal amount of the convertible notes due 2015 (the “2015 Convertible Notes”) during the third quarter of 2013, approximately $12.2 million of the repayment was considered a retirement of debt. We recognized a gain on the retirement of the debt of approximately $0.2 million and this gain is included in the “Loss on extinguishment of debt” in the Consolidated Statement of Operations.

 

Gain (loss) on derivatives: In connection with obtaining the $40.0 million and $75.0 million secured debt facilities in January and July 2011, respectively, we entered into performance based arranger fees (“Performance Based Arranger Fee”) that we are accounting for as embedded derivatives. The Performance Based Arranger Fee for the $40.0 million secured debt facility expired in July 2013. The Performance Based Arranger Fee for the $75.0 million secured debt facility expired in July 2014. As a result of the fair value measurement at September 30, 2014 and 2013, respectively, the gain associated with the embedded derivatives increased $0.6 million to a $0.2 million gain for the three months ended September 30, 2014 from a $0.4 million loss for the same period in 2013.

 

Other income (expense): For the three months ended September 30, 2014, other income increased $3.3 million to $0.5 million of income compared to $2.8 million of expense for the same period in 2013. For the three months ended September 30, 2014 and 2013, foreign currency gains (losses), a component of other expense, were ($0.3) million and zero, respectively. For the three months ended September 30, 2013, expenses of $2.5 million relating to the issuance of the 2017 Convertible Notes were included. There were no similar expenses for the same period in 2014.

 

 

 

For the nine months ended September 30, 2014, total other expense decreased $11.7 million to $11.1 million compared to $22.8 million during the same period in 2013.

 

The change is due to the following:

 

Interest expense: For the nine months ended September 30, 2014, we recognized approximately $10.6 million of net interest expense, which included $19.9 million of interest expense reduced by $9.3 million of capitalized interest expense. For the same period in 2013, we recognized $12.1 million in net interest expense, which included $19.3 million of interest expense reduced by $7.2 million of capitalized interest. The decrease of $1.5 million in net interest expense is due to higher interest capitalized of $2.1 million from a higher average construction in progress, partially offset by a higher interest expense of $0.6 million resulting from a higher average interest cost of debt outstanding between the periods. In May 2013, we retired the remaining $30.5 million of the $75.0 million secured debt facility and in September 2013 we retired the remaining $36.0 million of the $40.0 million secured debt facility.

 

Loss on extinguishment of debt: For the nine months ended September 30, 2014 and September 30, 2013, respectively, we reported $1.2 million and $7.2 million as a loss on extinguishment of debt.

   

In April 2014, $26.0 million of the aggregate principal amount of the 2015 Convertible Notes were exchanged for an additional $25.0 million aggregate principal amount of 2017 Convertible Notes in a private transaction. As a result of the exchange during the second quarter of 2014, we incurred a $1.2 million loss.

 

As a result of the prepayment of the remaining $30.5 million under the $75.0 million secured debt facility during the second quarter of 2013, we incurred $2.4 million of fees and prepayment premium and expensed $1.4 million of unamortized debt issue costs. As a result of the prepayment of the remaining $36.0 million under the $40.0 million secured debt facility during the third quarter of 2013, we incurred $2.0 million of fees and prepayment premium and expensed $1.7 million of unamortized debt issue costs. As a result of the repurchase of $85.0 million of principal amount of the convertible notes due 2015 (the “2015 Convertible Notes”) during the third quarter of 2013, approximately $12.2 million of the repayment was considered a retirement of debt. We recognized a gain on the retirement of the debt of approximately $0.2 million.

 

Gain (loss) on derivatives: As a result of the fair value measurement of the Performance Arranger Fees at September 30, 2014 and 2013, respectively, from the measurement at January 1, 2014, and January 1, 2013, respectively, the gain associated with the embedded derivatives decreased $0.3 million to a $2,000 gain for the nine months ended September 30, 2014 from a $0.3 million gain for the same period in 2013.

 

Other income (expense): For the nine months ended September 30, 2014, other income increased $4.5 million to $0.8 million of income compared to $3.7 million loss for the same period in 2013. For the nine months ended September 30, 2014 and 2013, foreign currency gains (losses), a component of other income, were ($0.4) million and ($1.1) million, respectively. For the nine months ended September 30, 2013, expenses of $2.5 million relating to the issuance of the 2017 Convertible Notes were included. There were no similar expenses for the same period in 2014.

 

 

 

Income Taxes

 

The following is a summary of income (loss) before income taxes and income tax expense (benefit) for the three and nine months ended September 30, 2014 and 2013: 

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Income (loss) before income taxes:
United States		$	(27,561	)		$	(16,287	)		$	(37,504	)		$	(25,480	)
Foreign			(15,103	)			(4,805	)			(7,204	)			(28,083	)
		$	(42,664	)		$	(21,092	)		$	(44,708	)		$	(53,563	)
Income tax expense (benefit):
United States		$	-			$	-			$	-			$	668
Foreign			2,628				(5,771	)			6,703				(6,486	)
		$	2,628			$	(5,771	)		$	6,703			$	(5,818	)

 

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 2033. 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 and certain expenses which are not deductible in Peru.

 

During the three and nine months ended September 30, 2014, we recorded a valuation allowance of $8.0 million on the deferred tax assets of our foreign subsidiary engaging in the development of the gas-to-power project, as we considered it more likely than not that a portion or all of the subsidiary's deferred tax assets will not be realized. Further, we will place a valuation allowance on future deferred tax assets of that same foreign subsidiary until we believe it is more likely than not the deferred tax assets will be realized. There was no similar adjustment for the three and nine months ended September 30, 2013.

 

The September 30, 2014 and December 31, 2013 balance of unrecognized tax benefits includes $0.7 million that, if recognized, would impact our effective income tax rate. Over the next 12 months, we do not anticipate any reduction in the balance. We have accrued interest and penalties related to unrecognized tax benefits of $46,000 at both September 30, 2014 and December 31, 2013. Estimated interest and penalties related to potential underpayment on unrecognized tax benefits, if any, are classified as a component of income tax expense in the Consolidated Statement of Operations.

 

Net Loss

 

For the three months ended September 30, 2014, our net loss increased $30.0 million to a net loss of $45.3 million or ($0.39) per basic and diluted share from a net loss of $15.3 million or ($0.13) per basic and diluted share for the same period in 2013. For the nine months ended September 30, 2014, our net loss increased $3.7 million to a net loss of $51.4 million or ($0.44) per basic and diluted share from a net loss of $47.7 million or ($0.41) per basic and diluted share for the same period in 2013.

  

Liquidity, Capital Resources and Capital Expenditures

 

At September 30, 2014, we had cash and cash equivalents of $79.5 million, an accounts receivable balance of $6.6 million and a working capital deficit of $9.9 million.

 

At September 30, 2014, we had trade accounts payable and accrued liabilities of $18.5 million.

 

At September 30, 2014, our outstanding debt consisted of the 2015 Convertible Notes, whose net amount of $58.8 million includes the $59.9 million of principal reduced by $1.1 million of the remaining unamortized discount, and the 2017 Convertible Notes, whose net amount of $153.8 million includes the $168.7 million of principal reduced by $14.9 million of the remaining unamortized discount. At September 30, 2014, the current and long-term portions of our long-term debt were $58.8 million and $153.8 million, respectively. 

 

 

 

		For the Nine Months Ended
		September 30,
Cash Flows		2014				2013
		(in thousands)
Cash provided by (used in):
Operating activities		$	46,188			$	(36,270	)
Investing activities			(23,921	)			59,211
Financing activities			(166	)			(27,498	)

 

Operating Activities 

 

Cash provided by operating activities increased by $82.5 million to a source of cash of $46.2 million for the nine months ended September 30, 2014 from a use of cash of $36.3 million for the same period in 2013. The change in cash flows before changes in operating assets and liabilities provided an increase in the source of cash of $35.5 million due to higher revenues and lower standby costs. Changes in cash flow as a result of changes in operating assets and liabilities provided an increase in the source of cash of $47.0 million. The increase in the source of cash is due to the changes in liabilities (accounts payable of $19.9 million, accrued liabilities of $18.4 million and income taxes payable of $11.7 million) providing an increase in the source of cash of $50.8 million. Partially offsetting these amounts are changes in assets (accounts receivable of $4.4 million and value-added tax receivables of $1.8 million, partially offset by changes in inventory and other assets of $2.2 million) providing a decrease in the source of cash of $3.8 million.  

 

Investing Activities

 

Net cash used in investing activities increased by $83.1 million to $23.9 million for the nine months ended September 30, 2014 from a source of cash of $59.2 million for the same period in 2013. The increase in cash used in investing activities is due to a release of restricted cash of $67.4 million from principal repayments of the $75.0 million secured debt facility and the $40.0 million secured debt facility in the first nine months of 2013 compared to $1.2 million change in restricted cash in the first nine months of 2014, and increased capital expenditures of $16.9 million in 2014 due to our development initiatives for the exploration and production of our onshore oil and natural gas reserves.

 

2014 Capital Expenditures

 

During the nine months ended September 30, 2014, we incurred net capital expenditures of approximately $26.4 million associated with our development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of gas-fired power generation of electricity for sale in Peru.

 

The capital expenditures added were approximately $17.5 million related to the exploration of Block XXIII, which included capitalized interest of $1.6 million, approximately $7.7 million of costs related to the power plant, which consisted of capitalized interest of $7.1 million, and other capital expenditures incurred of approximately $1.2 million, which included capitalized interest of $0.6 million.

 

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 100% of capital expenditures for Block Z-1 of $112.9 million for the nine months ended September 30, 2014. These gross capital expenditures include approximately $46.5 million related to the CX-15 development drilling program, approximately $44.5 million related to the development drilling program in Albacora and expenditures incurred related to the Piedra Redonda platform of approximately $4.9 million, the Delfin platform of approximately $4.6 million and the CX-15 platform of approximately $2.0 million.

 

Financing Activities

 

Cash used in financing activities decreased by $27.3 million to a use of cash of $0.2 for the nine months ended September 30, 2014, compared to a use of cash of $27.5 million for the same period in 2013. The decrease in cash used in financing activities is due to debt repayments of $99.1 million in 2013 compared to zero in 2014 (the repayment of $38.8 million under the $75.0 million secured facility in 2013, the repayment of $49.3 million under the $40.0 million secured facility in 2013 and the repayment of $11.0 million under the 2015 Convertible Notes) and debt issue costs and other of $6.8 million in 2013 compared to $0.3 million in 2014, partially offset by debt borrowings in 2013 of $78.4 million compared to zero in 2014 (drawdown of $14.5 million from the $40.0 secured debt facility in May 2013 and the issuance of the 2017 Convertible Notes of $63.9 million in September 2013).

 

 

 

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 $500.0 million available under an effective shelf registration statement for debt securities, common stock, preferred stock, depositary shares and securities warrants, subscription rights, units 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 January 2, 2017.

 

Debt Obligations

 

At September 30, 2014 and December 31, 2013, debt consisted of the following:

 

		September 30, 2014				December 31, 2013
		(in thousands)
Convertible Notes, 8.5%, due October 2017, net of discount of ($14.9) million at September 30, 2014 and ($18.3) million at December 31, 2013		$	153,780			$	125,416
Convertible Notes, 6.5%, due March 2015, net of discount of ($1.1) million at September 30, 2014 and ($4.4) million at December 31, 2013			58,849				81,523
			212,629				206,939
Less: Current maturity of long-term debt			58,849				-
Long-term debt, net		$	153,780			$	206,939

 

Convertible Notes due 2017

 

During the third quarter of 2013, we closed on an offering for an aggregate principal amount of $143.8 million of convertible notes due 2017 (the “2017 Convertible Notes”) which includes the exercise of the underwriter’s option to purchase an additional $18.8 million of the 2017 Convertible Notes in addition to the original offering of $125.0 million. The 2017 Convertible Notes are general senior unsecured obligations and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in the right of payment to all of our existing and future subordinated debt.  The 2017 Convertible Notes are effectively subordinate to any secured indebtedness we may have to the extent of the value of the assets collateralizing such indebtedness.  The 2017 Convertible Notes are not guaranteed by our subsidiaries. In April 2014, $26.0 million of the aggregate principal amount of the 2015 Convertible Notes were exchanged for an additional $25.0 million aggregate principal amount of 2017 Convertible Notes in a private transaction. As a result, we have $168.7 million principal amount of 2017 Convertible Notes outstanding at September 30, 2014.

 

The interest rate on the 2017 Convertible Notes is 8.50% per year with interest payments due on April 1st and October 1st of each year.  The 2017 Convertible Notes mature with repayment of the $168.7 million principal amount (assuming no conversion) on October 1, 2017 (the “2017 Maturity Date”).

 

The conversion rate is 249.5866 shares per $1,000 principal amount (equal to an initial conversion price of approximately $4.0066 per share of common stock). Upon conversion, if conversion is elected by the noteholders, we must deliver, at our option, either (1) a number of shares of our common stock determined as set forth in the Indenture dated September 24, 2013 (the “2013 Indenture”), (2) cash, or (3) a combination of cash and shares of our common stock.

 

Holders may convert their 2017 Convertible Notes at their option at any time prior to the close of business on the second business day immediately preceding the 2017 Maturity Date under any of the following circumstances:

 

(1) during any fiscal quarter (and only during such fiscal quarter) commencing after October 1, 2013, if the last reported sale price of our common stock is greater than or equal to 130% of the conversion price of the 2017 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 July 1, 2017, 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 2017 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; or

 

(3) upon the occurrence of one of a specified number of corporate transactions.

 

Holders may also convert the 2017 Convertible Notes at their option at any time beginning on July 1, 2017, and ending at the close of business on the second business day immediately preceding the 2017 Maturity Date or may hold the 2017 Convertible Notes to maturity and be paid their outstanding principal in cash.

 

We may not redeem the 2017 Convertible Notes prior to the 2017 Maturity 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 2017 Convertible Notes. Any repurchase of the 2017 Convertible 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 2013 Indenture for the 2017 Convertible Notes 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 2017 Convertible Notes.

 

Net proceeds from the sale of the 2017 Convertible Notes, after deducting the discounts and commissions and any offering expenses payable by us, were approximately $124.5 million.  The 2017 Convertible Notes were issued with a 10% discount or $14.4 million. The underwriter received commissions of approximately $4.3 million in connection with the sale and we incurred $0.6 million of direct expenses in connection with the offering.  We used the net proceeds for general corporate purposes, including funding of our exploration and production efforts and other projects and to reduce or refinance our outstanding debt.

 

We accounted for the 2017 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 2017 Convertible Notes. 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 2017 Convertible Notes to be 12.9%. The 12.9% 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 underwriter. Using the income method and discounting the principal and interest payments of the 2017 Convertible Notes using the 12.9% non-convertible borrowing rate, we estimated the fair value of the $143.8 million 2017 Convertible Notes to be approximately $124.5 million with the discount being approximately $19.3 million. The discount of $19.3 million includes the 10% discount of $14.4 million and the value of the equity component of $4.9 million. The discount is being amortized as non-cash interest expense over the life of the 2017 Convertible Notes using the effective interest method. In addition, we allocated approximately $2.3 million of the $4.9 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. Approximately $0.1 million of fees and commissions were treated as transaction costs associated with the equity component and the remaining $2.5 million was expensed to other expense under the caption “Other income (expense)”.

 

As a result of the exchange during the second quarter of 2014, we estimated our non-convertible borrowing rate at the date of issuance of the $25.0 million 2017 Convertible Notes to be 7.89%. The 7.89% 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 a financial advisor. Using the income method and discounting the principal and interest payments of the 2017 Convertible Notes with the 7.89% non-convertible borrowing rate, we estimated the fair value of the $25.0 million 2017 Convertible Notes to be approximately $25.4 million, with the premium being approximately $0.4 million. The value of the equity component was estimated at $0.5 million. The premium is being amortized as non-cash interest expense over the life of the 2017 Convertible Notes using the effective interest method. In addition, approximately $0.3 million of fees were considered debt issue costs that are being amortized as a non-cash interest expense over the life of the notes using the effective interest method. We recognized a loss on this transaction of approximately $0.9 million and this loss was included in the “Loss on extinguishment of debt” in the consolidated statement of operations in the second quarter of 2014. For further information on debt issue costs see Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets.”

 

 

 

The following table shows the estimated remaining cash payments as of September 30, 2014, including interest payments related to the 2017 Convertible Notes, assuming no conversion (in thousands):

 

Year
2014		$	-
2015			14,340
2016			14,340
2017			183,051
Total estimated remaining cash payments related to the 2017 Convertible Notes		$	211,731

 

 

We evaluated the 2013 Indenture for the 2017 Convertible Notes 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 September 30, 2014, the net amount of $153.8 million includes the $168.7 million of principal reduced by $14.9 million of the remaining unamortized discount. The remaining unamortized discount of $14.9 million will be amortized into interest expense, using the effective interest method, over the remaining life of the 2017 Convertible Notes, which mature in October 2017.  At September 30, 2014, using the conversion rate of 249.5866 shares per $1,000 principal amount of the 2017 Convertible Notes, if the $168.7 million of principal were converted into shares of common stock, the notes would convert into approximately 42.1 million shares of common stock.  As of September 30, 2014, there is no excess if-converted value to the holders of the 2017 Convertible Notes as the price of our common stock at September 30, 2014, $1.91 per share, is less than the conversion price.

 

The annual effective interest rate on the 2017 Convertible Notes, including the amortization of debt issue costs, is approximately 12.5%.

 

The following table shows the amount of interest expense related to the 2017 Convertible Notes, disregarding capitalized interest considerations, for the three and nine months ended September 30, 2014 and 2013, respectively:

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Interest expense related to the contractual interest coupon		$	3,585			$	204			$	10,170			$	204
Amortization of debt discount expense			994				-				2,947				-
Amortization of debt issue costs			159				-				451				-
Interest expense related to the 2017 Convertible Notes		$	4,738			$	204			$	13,568			$	204

 

 

Convertible Notes due 2015

 

During the first quarter of 2010, we closed on a private offering for an aggregate principal amount 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 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. In September 2013, we repurchased $85.0 million of the aggregate principal amount of the $170.9 million 2015 Convertible Notes leaving a principal balance of $85.9 million. In April 2014, $26.0 million of the aggregate principal amount of the 2015 Convertible Notes were exchanged for an additional $25.0 million aggregate principal amount of 2017 Convertible Notes in a private transaction. As a result, we have $59.9 million principal amount of 2015 Convertible Notes outstanding at September 30, 2014.

 

 

 

The interest rate on the 2015 Convertible Notes is 6.50% per year with interest payments due on March 1st and September 1st of each year.  The 2015 Convertible Notes mature with repayment of the remaining principal balance of $59.9 million (assuming no conversion) on March 1, 2015 (the “2015 Maturity Date”).

 

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 dated February 8, 2010 (the “2010 Indenture”). As a result, the conversion rate and conversion price changed to 169.0082 shares per $1,000 principal amount and $5.9169 per share of common stock, respectively. Upon conversion, if conversion is elected by the noteholders, we must deliver, at our option, either (1) a number of shares of our common stock determined as set forth in the 2010 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 2015 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;

 

(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 2015 Maturity Date or may hold the 2015 Convertible Notes to maturity and be paid their outstanding principal in cash.

 

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 2015 Convertible 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 2010 Indenture for the 2015 Convertible Notes 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 $170.9 million of 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 account 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 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 2015 Convertible Notes. 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 2015 Convertible 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 net amount of the equity component was $33.3 million, which included the initial discount of $34.6 million reduced by $1.3 million of direct transaction costs.

 

In September 2013, we repurchased $85.0 million of aggregate principal amount of the 2015 Convertible Notes. As a result of the $85.0 million repurchase during the third quarter of 2013, approximately $12.2 million of the repayment was considered a retirement of debt and the remaining $72.8 million of the repayment was considered an exchange of debt and not deemed a substantial modification of debt. The $85.0 million of 2015 Convertible Notes were repurchased with an approximate discount of 10%. We recognized a gain on the retirement of the debt of approximately $0.2 million and this gain was included in the “Loss on extinguishment of debt” in the consolidated statement of operations in the third quarter of 2013. 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 exchange during the second quarter of 2014, the $26.0 million of aggregate principal amount of 2015 Convertible Notes exchanged was considered a retirement of debt and deemed a substantial modification of debt. The $26.0 million of 2015 Convertible Notes were exchanged with an approximate discount of 4%. We recognized a loss on the retirement of the debt of approximately $0.3 million and this loss was included in the “Loss on extinguishment of debt” in the consolidated statement of operations in the second quarter of 2014. For further information on debt issue costs see Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets.”

 

The following table shows the estimated remaining cash payments as of September 30, 2014, including interest payments related to the 2015 Convertible Notes, assuming no conversion (in thousands):

 

Year
2014		$	-
2015			61,837
Total estimated remaining cash payments related to the 2015 Convertible Notes		$	61,837

 

 

We evaluated the 2010 Indenture for the 2015 Convertible Notes 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 September 30, 2014, the net amount of $58.8 million of 2015 Convertible Notes outstanding includes the $59.9 million of principal reduced by $1.1 million of the remaining unamortized discount. The remaining unamortized discount of $1.1 million will be amortized into interest expense, using the effective interest method, over the remaining life of the 2015 Convertible Notes, which mature in March 2015.  At September 30, 2014, using the conversion rate of 169.0082 shares per $1,000 principal amount of the 2015 Convertible Notes, if the $59.9 million of principal were converted into shares of common stock, the notes would convert into approximately 10.1 million shares of common stock.  As of September 30, 2014, there is no excess if-converted value to the holders of the 2015 Convertible Notes as the price of our common stock at September 30, 2014, $1.91 per share, is less than the conversion price.

 

For the three and nine months ended September 30, 2014, the annual effective interest rate on the 2015 Convertible Notes, including the amortization of debt issue costs, was approximately 12.0%.

 

 

 

The following table shows the amount of interest expense related to the 2015 Convertible Notes, disregarding capitalized interest considerations, for the three and nine months ended September 30, 2014 and 2013:

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		(in thousands)
Interest expense related to the contractual interest coupon		$	973			$	2,671			$	3,412			$	8,226
Amortization of debt discount expense			680				1,529				2,272				5,182
Amortization of debt issue costs			177				245				603				740
Interest expense related to the 2015 Convertible Notes		$	1,830			$	4,445			$	6,287			$	14,148

 

 

$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”), whereby 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.

 

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 in the second quarter of 2013. Approximately $1.4 million representing the remaining unamortized debt issue costs on the loan was expensed as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations when we prepaid the remaining principal in the second quarter of 2013.

 

As a result of the prepayment and amendment during the second quarter of 2012, we incurred $5.8 million of fees and 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% being paid at the time of each of the next three quarterly interest payment dates ending in January 2013.

 

The $75.0 million secured debt facility, as amended, provided 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 whereby 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 September 2013, we prepaid the remaining principal balance of the $40.0 million secured debt facility.        

 

In 2013, the $14.5 million of proceeds from the amended and restated $40.0 million secured debt facility was utilized to meet our 2013 capital, exploration and development work programs as well as for 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) to increase 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 was originally planned to be amortized over the remaining term, ending in January 2015, using the effective interest method.

 

As a result of the prepayment of the remaining principal balance during the third quarter of 2013, we incurred $2.0 million in fees and prepayment premium. The $2.0 million in fees and prepayment premium were recognized as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations in the third quarter of 2013. Approximately $1.7 million representing the remaining unamortized debt issue costs on the loan was expensed as a “Loss on extinguishment of debt” in the Consolidated Statement of Operations when we prepaid the remaining principal in the third quarter of 2013.  

 

The $40.0 million secured debt facility, as amended, provided for ongoing fees through July 2013 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.”

 

Restricted Cash and Performance Bonds

 

Below is a summary of restricted cash as of September 30, 2014 and December 31, 2013:

 

		September 30, 2014				December 31, 2013
		(in thousands)
Performance bonds totaling $5.7 million for properties in Peru		$	3,459			$	3,459
Performance obligations and commitments for the gas-to-power site			650				650
Secured letters of credit			-				250
$40.0 million secured debt facility			-				1,000
Unsecured performance bond totaling $0.1 million for office lease agreement			-				-
Restricted cash		$	4,109			$	5,359
Current portion of restricted cash as of the end of the period		$	-			$	1,250
Long-term portion of restricted cash as of the end of the period		$	4,109			$	4,109

 

 

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 September 30, 2014. The restricted cash balance related to the current and non-current portion of the $75.0 million secured debt financing was zero at December 31, 2013.

 

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, to maintain a balance in the debt service reserve account equal to the aggregate amount of principal and interest payment on the $40.0 million secured debt facility due 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 increase the funding of the debt service reserve account related to the $40.0 million secured debt facility to 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 for us to maintain a balance in the debt service reserve account equal to the aggregate amount of principal and interest payment on the $40.0 million secured debt facility due on the succeeding principal repayment date. The remaining principal balance related to the $40.0 million secured debt facility was repaid in September 2013 utilizing $3.8 million of funds from the debt service reserve account related to this debt facility. As a result of the repayment of the remaining principal balance of the $40.0 million secured debt facility, it was agreed that the restricted cash balance would remain at $1.0 million relating to the performance based arranger fee for the $75.0 million secured debt facility through July 2014. In July 2014 the $1.0 million was released to us and the debt service reserve account was terminated. Therefore, the restricted cash balance related to the current and non-current portion of the $40.0 million secured debt financing were both zero at September 30, 2014. The restricted cash related to the current and non-current portion of the $40.0 million secured debt financing was $1.0 million and zero, respectively, at December 31, 2013.

 

 

 

All of the performance and insurance bonds are issued by Peruvian banks and their terms are governed by the corresponding license contracts, customs laws, legal requirements or rental practices. 

 

Revision to the 2014 Estimated Capital and Exploratory Expenditures Budget

 

Our $21.0 million estimated planned capital and exploratory expenditures onshore include $16.0 million for shallow drilling activities at Block XXIII as well as $5.0 million of other geological, geophysical and engineering activities.     

 

Our 51% share of the Block Z-1 capital investments, of which $81.3 million is to be fully carried by Pacific Rubiales, is estimated at $103.0 million ($202.0 million gross).  Our planned activities at Block Z-1 include $37.0 million of CX-15 developmental drilling for 6 wells, $30.0 million of Albacora developmental drilling for 4 wells plus a sidetrack, $18.0 million for two platforms, one at Delfin and one at Piedra Redonda and $18.0 million for projects and engineering and other expenditures.

 

Our total estimated capital expenditures, excluding capitalized interest, is approximately $42.7 million.  This includes $21.0 million for our three onshore blocks in which we hold 100% working interests, and $21.7 million for the capital and exploratory expenditures for offshore Block Z-1, which would be the amount that could exceed the $81.3 million carry amount available to us from Pacific Rubiales, should the estimated investments be all incurred. 

 

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 our 51% participating interest in Block Z-1 (See Divestiture above for additional details on the joint venture), along with additional financing, 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 September 30, 2014, based on our share of 2014 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 $23.8 million.

 

During the third quarter of 2013, we closed on an offering for an aggregate of $143.8 million of 2017 Convertible Notes which amount includes the exercise of the underwriter’s option to purchase an additional $18.8 million of the 2017 Convertible Notes in addition to the original offering of $125.0 million. Net proceeds from the sale of the 2017 Convertible Notes, after deducting the discounts and commissions and any offering expenses payable by us, were approximately $124.5 million. We used the net proceeds for general corporate purposes, including funding our exploration and production efforts or other projects and to reduce or refinance our outstanding debt.

 

In April 2014, $26.0 million of the aggregate principal amount of the 2015 Convertible Notes were exchanged for an additional $25.0 million aggregate principal amount of 2017 Convertible Notes in a private transaction. As a result, we have $59.9 million principal amount of 2015 Convertible Notes outstanding and $168.7 million principal amount of 2017 Convertible Notes outstanding.

 

This remaining balance of the 2015 Convertible Notes will mature on March 1, 2015. We plan to repay the 2015 Convertible notes with a combination of cash on hand, cash from operations, possible asset sales or additional financings as required.

 

We currently have $500.0 million available under an effective shelf registration statement for debt securities, common stock, preferred stock, depositary shares and securities warrants, subscription rights, units 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 or debt 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 September 30, 2014, we had no transactions, agreements or other contractual arrangements with unconsolidated entities or financial partnerships, often referred to as special purpose entities, which generally are established for the purpose of facilitating off-balance sheet arrangements.

 

   

Critical Accounting Estimates

 

In our annual report on Form 10-K for the year ended December 31, 2013, 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

 

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. (“ASU”) 2014-08: Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 changes the criteria for reporting discontinued operations while enhancing disclosures in this area and is effective for annual and interim periods beginning after December 15, 2014. We are currently evaluating the provisions of ASU 2014-08 and assessing the impact, if any, it may have on our financial position and results of operations.

 

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers, and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. In addition, ASU 2014-09 supersedes the cost guidance in Subtopic 605-35, Revenue Recognition—Construction-Type and Production-Type Contracts, and creates new Subtopic 340-40, Other Assets and Deferred Costs— Contracts with Customers. The core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Also, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. ASU 2014-09 is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations.

 

In August 2014, the FASB issued Accounting Standards Update No. 2014-15 (ASU 2014-15), which creates Subtopic 205-40, Presentation of Financial Statements— Going Concern. ASU 2014-15 requires management to assess the entity’s ability to continue as a going concern, and to provide related footnote disclosures in certain circumstances. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods therein. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on its financial position and results of operations.

 

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, 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, 2013 and updated in our Form 8-K Exhibit 99.3, filed on October 2, 2014.

 

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 September 30, 2014, we had long-term debt of approximately $153.8 million and current maturities of long-term debt of approximately $58.8 million.

 

During the third quarter of 2013, we closed on an offering for an aggregate of $143.8 million of 2017 Convertible Notes which amount includes the exercise of the underwriter’s option to purchase an additional $18.8 million of the 2017 Convertible Notes.

 

In February and March 2010, we closed on the private offering for an aggregate $170.9 million of 2015 Convertible Notes. In September 2013, we repurchased $85.0 million of the principal balance of the $170.9 million of the 2015 Convertible Notes. 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 2010 Indenture, our exposure to potential gains if we were to repay or refinance such debt are minimal.

 

In April 2014, we exchanged $26.0 million of the aggregate principal amount of the 2015 Convertible Notes for $25.0 million aggregate principal amount of additional 2017 Convertible Notes.

 

 

 

The fair value of our 2017 Convertible Notes and 2015 Convertible Notes as compared to the carrying value at September 30, 2014 and December 31, 2013, is as follows:

 

		September 30, 2014								December 31, 2013
		Carrying Amount				Fair Value				Carrying Amount				Fair Value
		(in thousands)								(in thousands)
Convertible Notes, 8.5%, due October 2017, net of discount of ($14.9) million at September 30, 2014 and ($18.3) million at December 31, 2013 (1)		$	153,780			$	159,665			$	125,416			$	130,094
Convertible Notes, 6.5%, due March 2015, net of discount of ($1.1) million at September 30, 2014 and ($4.4) million at December 31, 2013 (2)			58,849				58,992				81,523				79,663

 

(1)

We estimated the fair value of the 2017 Convertible Notes to be approximately $159.7 million and $130.1 million at September 30, 2014 and December 31, 2013, respectively, based on observed market prices for the same or similar type of debt issues.

 

(2)

We estimated the fair value of the 2015 Convertible Notes to be approximately $59.0 million and $79.7 million at September 30, 2014 and December 31, 2013, respectively, based on observed market prices for the same or similar type of debt issues.

 

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.

 

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 September 30, 2014 and 2013, foreign currency gains (losses) were ($0.3) million and zero, respectively.

 

For the nine months ended September 30, 2014 and 2013, foreign currency gains (losses) were ($0.4) million and ($1.1) 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.

 

 

  

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 September 30, 2014, 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.

 

 

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, 2013 for a discussion of legal proceedings, which are incorporated into this Part II, Item 1. “Legal Proceedings” by reference.

 

Item 1A. Risk Factors

 

We have updated our risk factors as previously described in our Annual Report on Form 10-K for the year ended December 31, 2013, in the Form 8-K Exhibit 99.3, filed on October 2, 2014.

 

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)
99.1	Updated Risk Factors (Incorporated by reference to Exhibit 99.3 to the Company’s Form 8-K filed on October 2, 2014)
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)

 

 

 

 

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: November 7, 2014		/s/  MANUEL PABLO ZÚÑIGA-PFLÜCKER
		Manuel Pablo Zúñiga-Pflücker
		President, Chief Executive Officer and Director

 

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