UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2014

OR

For the transition period from              to             

Commission file number: 1-32167

 

VAALCO Energy, Inc.

(Exact name of registrant as specified on its charter)

 

 

9800 Richmond Avenue

Suite 700

Houston, Texas 77042

(Address of principal executive offices) (Zip Code)

(Registrant’s telephone number, including area code): (713) 623-0801

Securities registered under Section 12(b) of the Exchange Act:

 

Securities registered under Section 12(g) of the Exchange Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.     Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15d of the Act.    Yes  ¨    No  x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files).     Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10 K or any amendment to this Form 10-K.  x

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.

 

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

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, as of June 30, 2014 was $411,807,121 based on a closing price of $7.23 on June 30, 2014.

As of February 28, 2015, there were outstanding 57,880,481 shares of common stock, $0.10 par value per share, of the registrant.

Documents incorporated by reference: Definitive proxy statement of VAALCO Energy, Inc. relating to the Annual Meeting of Stockholders to be filed within 120 days after the end of the fiscal year covered by this Form 10-K, which is incorporated into Part III of this Form 10-K.

 

 

 

 

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VAALCO ENERGY, INC.

TABLE OF CONTENTS

 

 

 

 

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Glossary of Oil and Gas Terms

Terms used to describe quantities of oil and natural gas

Terms used to describe the Company’s interests in wells and acreage

Terms used to assign a present value to the Company’s reserves

Terms used to classify the Company’s reserve quantities

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

(i) The area of the reservoir considered as proved includes:

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(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic productibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Terms which describe the productive life of a property or group of properties

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Terms used to describe the legal ownership of the Company’s oil and gas properties

Terms used to describe seismic operations

 

 

 

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PART I

 

BACKGROUND

VAALCO Energy, Inc., a Delaware corporation incorporated in 1985, is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. VAALCO owns producing properties and conducts exploration activities as an operator in Gabon, West Africa, conducts exploration activities as an operator in Angola, West Africa, and participates in exploration and development activities as a non-operator in Equatorial Guinea, West Africa. VAALCO is the operator of unconventional resource properties in the United States in North Texas and a leasehold in Montana. The Company also owns minor interests in conventional production activities as a non-operator in the United States. As used in this report, the terms “Company”, “we”, “us”, “our”, and “VAALCO” mean VAALCO Energy, Inc. and its subsidiaries, unless the context otherwise requires. The Company’s corporate headquarters are located at 9800 Richmond Avenue, Suite 700, Houston, Texas 77042 where the telephone number is (713) 623-0801.

VAALCO’s international subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Angola (Kwanza), Inc., VAALCO UK (North Sea), Ltd., VAALCO International, Inc., VAALCO Energy (EG), Inc. and VAALCO Energy Mauritius (EG) Limited. VAALCO Energy (USA), Inc. holds interests in properties located in the United States.

STRATEGY

International

The Company’s international strategy is to pursue selective opportunities with a focus on West Africa that are characterized by reasonable entry costs, favorable economic terms, high reserve potential relative to capital expenditures and the availability of existing technical data. The Company believes that it has strong management and technical expertise with proven abilities in identifying international opportunities and establishing favorable operating relationships with host governments and local partners familiar with the local practices and infrastructure. The Company owns producing properties and conducts operating activities as an operator under an offshore license in Gabon, a license onshore Gabon (subject to approval of a new production sharing agreement which will include an extension of the exploration license), an exploration license in Angola, and as non-operator of an exploration/development license in Equatorial Guinea.

In addition, the Company’s production strategy is to maximize the value of the reserves discovered in Gabon through development of the offshore Etame Marin block (comprised of the Etame, Avouma/South Tchibala, and Ebouri producing fields, and the Southeast Etame/North Tchibala field currently being developed), and the onshore Mutamba Iroru block where the N’Gongui field is expected to be developed following the approval of a new production sharing contract with the Republic of Gabon.

Domestic

The Company’s domestic strategy has been to selectively acquire unconventional resource based properties.  The Company owns a lease with two producing wells in the Granite Wash formation in Texas, and deep rights on a lease in Montana.  Due to the surplus of domestically produced light, sweet crude oil in North America, and the associated current low price environment, the Company does not expect to focus on further development of domestic owned properties in its short-term business plans.

RECENT DEVELOPMENTS

Offshore Gabon

The Company’s primary source of revenue is from the Etame Production Sharing Contract related to the Etame Marin block located offshore the Republic of Gabon. VAALCO operates the Etame Marin block on behalf of a consortium of companies. At December 31, 2014, the Company owns a 28.1% interest in the development areas in and surrounding the Etame, Avouma/South Tchibala, and Ebouri fields, each of which is located on the Etame Marin block. The development areas were subject to a 7.5% back-in by the Government of Gabon, which occurred for these fields after their successful development. The Southeast Etame/North Tchibala field, each of which is also located on the Etame Marine block are in the process of being developed and will also be subject to a 7.5% back-in by the Government of Gabon. The Government of Gabon has since assigned the back-in interest to a third party.

The Company produces from the Etame, Avouma/South Tchibala and Ebouri fields on the block. During 2014, these fields produced approximately 5.8 million Bbls (1.4 million Bbls net to the Company). The Company’s share of barrels produced reflects an allocation of cost oil and profit oil, after reduction for royalty (13%).

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In July 2012, the Company discovered the presence of hydrogen sulfide (“H₂S”) from two of the three producing wells in the Ebouri field. The wells were shut-in for safety and marketability reasons resulting in a decrease of approximately 2,000 BOPD or approximately 10% of the gross daily production from the Etame Marin block at that time. In addition, H₂S was first detected in January 2014 and later confirmed in July 2014 in the Etame 5-H well in the Etame field, and this well has also been shut-in. Analysis and options for re-establishing production from the impacted areas continued through the fourth quarter of 2014.  To re-establish and maximize production from the impacted areas, additional capital investment will be required, including a processing facility capable of removing H₂S, recompletion of the temporarily abandoned wells, and potentially, additional new wells. Considering the substantial recent fall in oil prices, the Company and its partners are focusing on more cost efficient options for a processing facility (e.g. chemical removal options, construction of a smaller facility on existing structures, or the use of surplus equipment and used structures). There can be no assurances that the processing facility will be completed by 2017, if at all, or that a more cost effective facility will cover all affected areas of the Ebouri and Etame fields. It is expected that the timing of the project startup will be known as early as the fourth quarter of 2015 with a goal of re-establishing production from the area impacted by H₂S as soon as practical. Should the Company and its partners evaluation result in no economic alternative, a decrease of as much as 2.4 million barrels of proved undeveloped reserves could result.

The Company and its partners approved the construction of two additional production platforms in late 2012 as part of future development plans for the Etame Marin block. The construction of the two new platforms began in the first quarter of 2013 and were installed in the third quarter of 2014. One platform was installed in the Etame field and the second platform was installed between the Southeast Etame/North Tchibala field. The Company contracted a drilling rig to commence a multi-well development drilling program, which moved onto location and began drilling the first well in November 2014 from the Etame platform, in the Etame field. The Company drilled a successful exploration well in the Southeast Etame area in 2010 which is expected to be developed from the second platform in 2015. The total cost to build and install the two platforms was $351.0 million ($106.5 million net to the Company). The cost of the wells is not included in the platform costs.

The sixth extension of the exploration acreage on this block expired at the end of July 2014. The Company fully met all of the obligations under the terms of the sixth extension period.  In the second quarter of 2014, and prior to the deadline, the Company and its partners submitted a proposal for a seventh exploration license. The Government of Gabon responded in the first quarter of 2015 that a seventh exploration license would require a separate production sharing contract (“PSC”) and this requirement is being evaluated by the Company and its partners.  

Due to the uncertainty of obtaining the exploration license, the balance of undeveloped leasehold costs of $1.6 million was recorded as exploration expense in the year ended December 31, 2014.  

Late in 2012, a drilling and workover campaign began with the arrival of a drilling rig to conduct a six well program that was ultimately increased to an eight well program extending into 2014.  The early-2014 program included the drilling of an exploration well that did not discover commercial quantities of hydrocarbons.  Accordingly, the Company expensed $1.9 million of incurred dry hole costs in the fourth quarter of 2013 for this well, with the remainder of $11.7 million of dry hole costs expensed in the first quarter of 2014.  The Company performed a workover to replace the electrical submersible pumps in a well in the Avouma field in the first quarter of 2014 and in May 2014 brought on production a development well drilled in the South Tchibala field to replace a well with damaged casing.  

Following the installation of the two additional platforms in the third quarter of 2014, the Company and its partners began a development well drilling campaign beginning in October 2014 from the Etame platform.  The first well drilled, the Etame 8-H well, was completed in December 2014 and was shut-in as the well was determined to be producing H₂S during the initial testing process.  The Company is planning to conduct an extended well test of the Etame 8-H well, to confirm and quantify the presence of H₂S which was detected during the initial 17 hour flow test.  The well test is expected to occur in the first half of 2015. In December 2014, the Company spudded the Etame 10-H well which was drilled to the 1-V fault block, and the well was brought on production in the first quarter of 2015. The Etame 10-H well confirmed the presence of an undrained lower lobe of the Gamba reservoir in this fault block with no H₂S present. Additional development wells are expected to be drilled in 2015 from the two platforms.

As part of securing the first of two five-year extensions in 2011 to the Etame field production license to which the Company is entitled from the government of Gabon, the Company agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin Block. The agreement was finalized in the first quarter of 2014 (effective 2011) providing for annual funding over the remaining life of the production license. The amounts paid will be reimbursed through the cost account and are non-refundable to the Company. The initial funding took place in October 2014 for calendar years 2012 and 2013 totaling $8.4 million ($2.3 million net to the Company). The funding for calendar year 2014 was paid in the first quarter of 2015 in the amount of $4.2 million ($1.2 million net to the Company).  As in prior periods, the obligation for abandonment of the Gabon offshore facilities is included in the asset retirement obligation shown on the Company’s balance sheet. The cash funding is reflected under other long term assets as “Abandonment Funding”.

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In the fourth quarter of 2014, the Company recorded an impairment loss of $98.3 million to write down its investment in certain fields comprising the Etame Marin Block, offshore Gabon to its fair value. An impairment of $38.5 million was recorded in the Etame field, $5.9 million in the Ebouri field and $53.9 million in the Southeast Etame/North Tchibala field.  The impairment is a result of the recent decline in the forecasted oil prices used in the impairment testing and calculation.

Onshore Gabon

The Company executed a farm-out agreement in August 2010 with Total Gabon on the Mutamba Iroru block located onshore near the coast in central Gabon. The Mutamba Iroru block contains an exploration area of approximately 270,000 acres. The Company has a 50% working interest on the block (41% net working interest assuming the Republic of Gabon exercises its back-in rights).  

Under the terms of the agreement, the Company and Total Gabon committed to reprocess 400 kilometers of 2-D seismic data and drill one exploration well. The seismic reprocessing work was completed in 2012. The exploration well was drilled in 2012 resulting in a discovery.

A revised production sharing contract (“PSC”) including exploration rights is in the approval process.  The term sheet, which specifies financial and other obligations to be included in the PSC, was agreed to and signed by the Company, its joint venture partner, and the Government of Gabon on July 31, 2014. The form of the PSC has been completed and presented to the Company and its joint venture partner for execution.  The joint venture partner has withheld its approval of the new PSC pending resolution of certain legal aspects of the new agreement with the Government of Gabon.  In March 2015, the joint venture partner indicated to the Company that the legal aspects have not yet been resolved to their satisfaction.  The Company can provide no assurance as to the joint venture partner approving the PSC. The Company remains committed to this block and further meetings of the parties are expected to occur in the first half of 2015.  

After the PSC is approved, an application for a development area will be made by the Company.  After issuance of a development area, the next step is the submittal of the plan of development.  The Company can provide no assurances as to either the approval of the PSC by the Government of Gabon, or the subsequent approval of a development area by the Government of Gabon.

Development of the onshore block is expected to capitalize on synergies such as experienced personnel from our operating base office space, warehouse and open yard space in Port Gentil, Gabon.

Offshore Angola

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola. The four year primary term with an optional three year extension awards the Company exploration rights to 1.4 million acres offshore central Angola. The Company’s working interest is 40%, and its paying interest is 50% including the government’s carried working interest during the exploration phase.

By a governmental decree dated December 1, 2010, the government-assigned working interest partner was removed from the production sharing contract for cause, and a one year time extension was granted for drilling the two exploration commitment wells while the government decided on the disposition of the available interest. Additional extensions were subsequently granted by the Angolan government until November 30, 2014 to drill the two exploration commitment wells.

In the fourth quarter of 2013, the Company received a written confirmation from The Ministry of Petroleum of Angola that the available 40% working interest in Block 5, offshore Angola, has been assigned to Sonangol E.P., the National Concessionaire.  The Ministry of Petroleum also confirmed that Sonangol E.P. would assign the aforementioned participating interest to its exploration and production affiliate, Sonangol P&P. The assignment was made effective on January 1, 2014.

In April 2014, the Company received a letter and contractual amendment proposal from Sonangol E.P., the national oil company in Angola related to the extension of the two well drilling commitment. Due to the uncertainty that the primary term of the exploration license would be extended by the Republic of Angola in accordance with the contractual amendment proposal before the November 30, 2014 expiration date, in October 2014, the Company entered into the Subsequent Exploration Phase (“SEP”), together with its working interest partner, Sonangol P&P. The SEP option was provided for in the Production Sharing Agreement signed in 2006 with the Republic of Angola. The SEP extends the exploration period for an additional three year period such that the new expiry date for exploration activities is November 30, 2017. Entering the SEP requires the Company and its partner to acquire 3D seismic covering six hundred square kilometers and to drill two additional exploration wells. The Company has already satisfied the seismic obligation of the SEP with the purchase of 3D seismic in the outboard segment of the block in late 2013, which is currently being processed and will continue to be processed into 2015.

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By entering into the SEP, the Company is required to drill a total of four exploration wells during the exploration extension period.  The four well obligations include the two well commitments under the primary exploration period that carries over to the SEP period. A $10.0 million dollar assessment ($5.0 million dollars net to VAALCO) applies to each of the four commitment exploration wells, if any, that remain undrilled at the end of the exploration period in November 2017. Restricted cash of $10.0 million for the two new commitment wells was recorded in the fourth quarter of 2014. At December 31, 2014 the Company had $20.0 million in restricted cash related to the offshore Angola exploration agreement.

A drilling rig contract was signed in July 2014 for a semi-submersible rig to drill the exploration well on the Kindele prospect, a post-salt objective. The well began drilling in the first quarter of 2015. Drilling this well satisfies one of the four exploration well obligations and will release $5.0 million of the $20.0 million recorded as restricted cash at December 31, 2014 by the Company.

Offshore Equatorial Guinea

In July 2012, the Company signed a definitive agreement with Petronas Carigali Overseas SDN BHD for the purchase of a 31% working interest in Block P, located offshore Equatorial Guinea for 57,000 acres at a cost of $10.0 million. The acquisition was completed on November 1, 2012. GEPetrol, the national oil company of Equatorial Guinea, is the operator of the block. During 2014, the Company and GEPetrol continued to work on a joint operatorship model whereby the Company would have a significant role in operator activities on the block. Additionally, the Company has been working with the Ministry of Mines, Industry and Energy regarding timing and budgeting for development and exploration activities.

AVAILABLE INFORMATION

The Company files annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You may read and copy any document the Company files at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. The Company’s SEC filings are also available to the public at the SEC’s website at www.sec.gov.

You may also obtain copies of the Company’s annual, quarterly and current reports, proxy statements and certain other information filed with the SEC, as well as amendments thereto, free of charge from the Company’s website at www.vaalco.com. No information from the SEC’s or the Company’s website is incorporated by reference herein. The Company has placed on its website copies of its Audit Committee Charter, Code of Business Conduct and Ethics, and Code of Ethics for the Chief Executive Officer and Chief Financial Officer. Stockholders may request a printed copy of these governance materials by writing to the Corporate Secretary, VAALCO Energy, Inc., 9800 Richmond Avenue, Suite 700, Houston, Texas 77042.

CUSTOMERS

Substantially all of the Company’s oil and gas is sold at posted or indexed prices under short-term contracts, as is customary in the industry. In Gabon, starting in the second quarter of 2014, the Company switched to an agency model to sell its crude oil. The Company contracted with a third party in order to sell, based on a fixed per barrel fee, on the spot market (“agency model”). Prior to the second quarter in 2014, the Company sold oil under contracts with Mercuria Trading NV (“Mercuria”) beginning with the calendar year 2011.  For the first quarter of 2015, the Company will also sell its oil under the agency model on the spot market.

Domestic operated production in Texas is sold via two contracts, one for oil and one for gas and natural gas liquids. The Company has access to several alternative buyers for oil, gas, and natural gas liquids domestically.

EMPLOYEES

As of December 31, 2014, the Company had 113 full-time employees and consultant contractors, 60 of whom were located in Gabon, 7 of whom were located in Angola and 1 employee located in Equatorial Guinea. The Company is not subject to any collective bargaining agreements, although most of the national employees in Gabon are members of the NEOP (National Organization of Petroleum Workers) union. The Company believes its relations with its employees are satisfactory.

COMPETITION

The oil and gas industry is highly competitive. Competition is particularly intense from other independent operators and from major oil and natural gas companies with respect to acquisitions of desirable oil and gas properties and contracting for drilling equipment. There is also competition for the hiring of experienced personnel. In addition, the drilling, producing, processing and marketing of oil and gas is affected by a number of factors beyond the control of the Company, including but not limited to shortages

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of drilling rigs, pipe and personnel, which may delay drilling, increase prices and have other adverse effects which cannot be accurately predicted.

The Company’s competition for acquisitions, exploration, development and production includes the major oil and gas companies in addition to numerous independent oil companies, individual proprietors, investors and others. Many of these competitors possess financial, technical and personnel resources substantially in excess of those available to the Company, giving those competitors an enhanced ability to evaluate and acquire desirable leases properties or prospects. The ability of the Company to generate reserves in the future will depend on its ability to select and acquire suitable producing properties and prospects for future drilling and exploration.

INSURANCE

In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. The Company currently has insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to its oil and gas properties, operational control of offshore wells, aviation, auto liability, marine liability, worker’s compensation and employer’s liability, among other things. At the depths and in the areas in which the Company operates, and in light of the vertical and horizontal drilling that it undertakes, the Company typically does not encounter high pressures or high temperature drilling conditions.

Currently, the Company has Operator’s Extra Expense insurance coverage up to $100.0 million per occurrence.  This includes coverage for redrill and restoration of wells, as well as coverage for resultant environmental damage, including voluntary clean-up.  The Company also carries Physical Damage coverage on offshore assets that is subject to full replacement cost limits.  Both of these coverages, Operator’s Extra Expense and Physical Damage, are subject to certain customary exclusions and limitations and to deductibles (generally ranging from $100,000 to $1,000,000 per occurrence) that must be met prior to recovery.  In addition, the Company carries General Liability and Excess Liability Insurance, subject to customary exclusions and limitations, with limits of $75.0 million.  This program includes coverage for bodily injury and property damage to third parties, including sudden and accidental pollution liability coverage.

The Company requires all of its third-party contractors to sign master service agreements in which they agree to indemnify the Company for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by the Company’s employees and other contractors. Additionally, each party generally is responsible for damage to its own property.

The third-party contractors that perform hydraulic fracturing operations for the Company sign the master service agreements containing the indemnification provisions noted above. The Company does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, the Company believes its general liability and excess liability insurance policies would cover third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. The Company does not have ongoing hydraulic fracturing operations at December 31, 2014 nor plans for any such operations in the near future.

The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that the Company will be able to maintain insurance in the future at rates that we consider reasonable and it may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

ENVIRONMENTAL REGULATIONS

General

The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control in the United States and Gabon and will be subject to the laws and regulations of Angola and Equatorial Guinea when exploration drilling begins in those countries. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing laws, rules and regulations regulating the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the Company’s capital expenditures, earnings or competitive position with respect to its existing assets and operations. The Company cannot predict what effect future regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. In part because they are developing countries, it is unclear how quickly and to what extent Gabon, Angola or Equatorial Guinea will increase their regulation of environmental issues in the future; any significant increase in the regulation or enforcement of environmental issues by Gabon, Angola or Equatorial Guinea

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could have a material effect on the Company. Developing countries, in certain instances, have patterned environmental laws after those in the United States which are discussed below. However, the extent to which any environmental laws are enforced in developing countries varies significantly.

In the United States, environmental laws and regulations may require the acquisition of permits before drilling commences, the installation of pollution control equipment for our operations, special handling or disposal of materials used in our operations, or remedial measures to mitigate pollution from our operations or on the properties on which we operate. These laws and regulations may also restrict the types of substances used in our drilling operations which can be used or released into the environment or limit or prohibit drilling activities on certain lands such as wetlands or sensitive protected areas or restrict the rate of production below the rate that would otherwise be possible..

As a general matter, the oil and gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities.  The Environmental Protection Agency (“EPA”) has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for 2014-2016.  The trend has been the enactment of new or more stringent requirements on the oil and gas industry. These changes result in increased operating costs, and additional changes could results in further increases in our costs for environmental compliance.

Environmental Regulations in the United States

Superfund

The Company currently owns or leases, and in the past has owned or leased, properties that have been used for the exploration and production of oil and gas for many years. Although the Company has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed or released on or under the properties owned or leased by the Company or on or under locations where such wastes have been taken for disposal. In addition, some of these properties are or have been operated by third parties. The Company has no control over such entities’ treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have gradually become stricter over time. The Company could, in the future, be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRPs”), include the current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of Hazardous Substances found at a facility. CERCLA also authorizes the (EPA) and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the costs of such action.

Although CERCLA generally exempts “petroleum” from the definition of Hazardous Substance, in the course of its operations, the Company has generated and will generate substances that may fall within CERCLA’s definition of Hazardous Substance and may have disposed of these substances at disposal sites owned and operated by others. The Company may also be the owner or operator of sites on which Hazardous Substances have been released. To its knowledge, neither the Company nor its predecessors have been designated as a PRP by the EPA under CERCLA; the Company also does not know of any prior owners or operators of its properties that are named as PRPs related to their ownership or operation of such properties. States such as Texas have comparable statutes which may cover substances (including petroleum) in addition to those covered under CERCLA. In the event contamination is discovered at a site on which the Company is or has been an owner or operator or to which the Company sent regulated substances, the Company could be liable for costs of investigation and remediation and natural resources damages.

Solid and Hazardous Waste Handling

The Company generates wastes, including hazardous wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA and various state agencies have limited the disposal options for certain wastes, including wastes designated as hazardous under RCRA and state analogs (“Hazardous Wastes”). Furthermore, although most oil and gas wastes generally are exempt from regulation as hazardous waste, not all current comparable state statutes may provide this exemption, and certain wastes generated by the Company may be subject to RCRA or comparable state statutes. It is possible that certain wastes generated by the Company’s oil and gas operations that are currently exempt may in the future be designated as

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Hazardous Wastes under RCRA or other applicable statutes and, therefore, may be subject to more rigorous and costly disposal requirements.

Clean Water Act

The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge (including spills and leaks) of pollutants, including produced waters and other oil and natural gas wastes, into state waters and waters of the United States, a term broadly defined. These controls have become more stringent over the years, and it is probable that additional restrictions will be imposed in the future. Generally, permits must be obtained to discharge pollutants. The CWA provides for civil, criminal and administrative penalties for unauthorized discharges of oil and hazardous substances and of other pollutants. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or other pollutants. The CWA also prohibits the discharge of fill materials to regulated waters, including wetlands, without a permit. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other pollutants, into state waters. In addition, the EPA has promulgated regulations that may require the Company to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an unauthorized discharge of wastes, the Company may be liable for penalties and cleanup and response costs.

Oil Pollution Act

The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the CWA, imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, the Company may be liable for costs and damages.

The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs in a potential spill. Certain amendments to the OPA that were enacted in 1996 require owners and operators of offshore facilities that have a worst case oil spill potential of more than 1,000 Bbls to demonstrate financial responsibility in amounts ranging from $10.0 million in specified state waters and $35.0 million in federal outer continental shelf (“OCS”) waters, with higher amounts, up to $150.0 million based upon worst case oil-spill discharge volume calculations. In light of recent events, it is possible that these requirements may become more stringent. The Company believes that currently it has established adequate proof of financial responsibility for its offshore facilities.

Hydraulic Fracturing

Hydraulic fracturing involves the injection of water, sand (or other proppant) and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not as extensively at the federal level.  For example, the federal Safe Drinking Water Act (“SDWA”) protects underground sources of drinking water through the EPA’s underground injection control (“UIC”) program, which regulates the subsurface emplacement of fluid. The definition of “underground injection” in the SDWA expressly excludes the “underground injection of fluids or propping agents (other than diesel fuel) pursuant to hydraulic fracturing operations.” Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, there have been recent developments at the federal and state levels that could result in regulation of hydraulic fracturing becoming more stringent and costly.

In February 2014, the EPA issued guidance regarding federal regulatory authority under the SDWA over hydraulic fracturing using diesel fuel, specifying that owners or operators of wells who inject diesel fuels for hydraulic fracturing related to oil and gas operations must obtain a permit under the Class II well category under the EPA’s UIC program regulations before injection begins.  This guidance also identified fluids associated with five Chemical Abstracts Services (CAS) registry numbers as the most appropriate interpretation of the statutory term “diesel fuels” to use for permitting hydraulic fracturing that uses diesel fuels under the EPA’s UIC program. This guidance also clarified that diesel fuels used as a component of drilling muds or pipe joint compounds used in the well construction process or in motorized equipment at the surface are not subject to UIC Class II permitting requirements because such uses of diesel fuels are considered to be part of the well construction process and not diesel fuels injected for purposes of hydraulic fracturing.

The EPA also commenced a study of the potential environmental impacts of hydraulic fracturing activities and released a progress report in December 2012, which resulted in the EPA’s Subpart OOOO regulations (see discussion below) signed by the EPA Administrator on December 19, 2014.

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In addition, a committee of the U.S. House of Representatives conducted an investigation of hydraulic fracturing practices. Moreover, in past sessions legislation was introduced before Congress to provide for federal regulation of hydraulic fracturing by eliminating the current exemption in the Safe Drinking Water Act, and, further, to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that restrict hydraulic fracturing in certain circumstances or that require disclosure of the chemicals in the fracturing fluids. Additionally some states, localities and river basin conservancy districts have exercised or considered exercising their regulatory powers to limit, and in some cases place a moratorium on hydraulic fracturing.

The Bureau of Land Management (“BLM”) has regulated hydraulic fracturing activities on federal lands since 1983, but the BLM’s existing regulations were not written to address modern hydraulic fracturing activities.  The BLM has proposed revisions to its hydraulic fracturing regulations, which could require disclosure of hydraulic fracturing chemicals and the volume of water used. Such proposed regulations are still pending before the BLM.

Further, in response to a petition filed in January 2012 under section 21 of the Toxic Substances Control Act (“TSCA”), the EPA issued an Advance Notice of Proposed Rulemaking, RIN 2070-AJ93 (“ANPR”), which was published in the Federal Register on May 19, 2014. The EPA indicated that the purpose of this ANPR is soliciting public comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanism for obtaining this information, minimizing reporting burdens and avoiding duplication of state and other federal agency information collections, and soliciting comments on incentives and recognition programs that “could be used to support the development and use of safer chemicals in hydraulic fracturing”. The public comment period for this ANPR was extended for an additional month and ended on September 18, 2014. The next phase of this regulatory rulemaking process is still pending at the EPA.

If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where the Company conducts business, the Company could incur substantial compliance costs and such requirements could adversely delay or restrict its ability to conduct fracturing activities on its assets.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act, or NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

Endangered Species Act

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company were to have a portion of its leases designated as critical or suitable habitat, it may adversely impact the value of the affected leases.

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Climate Change Legislation

More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause us to incur material expenses in complying with them. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.  In addition, both houses of the United States Congress have considered legislation to reduce emissions of greenhouse gases without any ultimate resolution and many states have taken or considered legal measures to reduce GHG emissions, including, in a few locations, the consideration of a cap and trade program. Most cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. Depending on the regulatory reach of the EPA’s rules or new Clean Air Act (“CAA”) legislation or implementing regulations restricting the emission of GHGs or state programs, the Company could incur significant costs to control its emissions and comply with regulatory requirements. In addition, the EPA adopted a mandatory GHG emissions reporting program which imposes reporting and monitoring requirements on various industries including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. The Company will incur costs to monitor, keep records of, and report emissions of GHGs. We do not believe that our compliance with applicable monitoring, recordkeeping and reporting requirements under the reporting rule will have a material adverse effect on our results of operations or financial position.

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how federal and state regulation of GHGs will unfold and how it may impact our industry. Moreover, the federal, regional, state and local regulatory initiatives could adversely affect the marketability of the oil and natural gas that the Company produces. The impact of such future programs cannot be predicted, but the Company does not expect its operations to be affected any differently than other similarly situated domestic competitors.

The EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations.  The measures include the development of New Source Performance Standards (“NSPS”) regulations in 2016 for reducing methane from new and modified oil and gas production sources, and natural gas processing and transmission sources.  

Air Emissions

The Company’s operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. At the Federal level, the Clean Air Act (“CAA”) is the primary statute governing air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (or toxic) air pollutants might require installation of additional controls. Administrative enforcement actions for failure to comply with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require the Company to forego construction, modification or operation of certain air emission sources.

On April 17, 2012, the EPA issued final rules to subject oil and gas operations to regulation under the NSPS and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells.  On December 19, 2014, the EPA Administrator signed and submitted for publication in the Federal Register (77 FR 49542, Aug. 16, 2012, as amended at 79 FR 79037, Dec. 31, 2014) the EPA’s finalized amendments to the NSPS with respect to emissions from the oil and natural gas sector, entitled “Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution” (40 CFR Part 60, Subpart OOOO). Section 60.5375(a) of Subpart OOOO of the EPA rules includes NSPS standards for completions of hydraulically fractured natural gas wells.  These standards are applicable to new hydraulically fractured wells and also existing wells that are refractured.

For each well completion operation with hydraulic fracturing begun prior to January 1, 2015, these standards require owners/operators to comply with Section 60.5375(a)(3) and (4) and reduce volatile organic compound (“VOC”) emissions from natural gas not sent to the gathering line during well completion by flaring using a completion combustion device, with the option to capture the gas emissions using reduced emission completions (“REC” aka “green completions”). For each well completion with hydraulic fracturing begun on or after January 1, 2015, operators must comply with Section 60.5375(a)(1) and (2) and capture the gas and make it available for use or sale, which can be done through the use of green completions. Section 60.5375(a)(1) distinguishes between the “initial flowback stage” of a well completion (specifying that gas present in the initial flowback stage is not subject to control under Section 60.5375(a)(1)) and the “separation flowback stage” of a well completion. Section 60.5375(a)(1)(ii) specifies that gas present in the separation flowback stage must be recovered from the separator and routed into a gas flow line or collection system, reinjected into the well or another well, used as an onsite fuel source, or used for another useful purpose that a purchased fuel or raw

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material would serve. If it is infeasible to route the recovered gas as specified above, then it is to be flared using a completion combustion device in accordance with Section 60.5375(a)(3).

Further, the finalized Subpart OOOO regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment.

These rules may require changes to our operations, including the installation of new equipment to control emissions. We are currently evaluating the effect these rules will have on our business.

OSHA and Other Regulations

To the extent not preempted by other applicable laws, the Company is subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, where applicable. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes, where applicable, require the Company to organize, maintain and/or disclose information about hazardous materials used or produced in its operations.

FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended to be covered by the safe harbors created by those laws. The Company has based these forward-looking statements on its current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of the Company’s operations. All statements, other than statements of historical facts, included in this report that address activities, events or developments that the Company expects or anticipates may occur in the future, including without limitation, statements regarding the Company’s financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures, plans and objectives of the Company’s management for future operations are forward-looking statements. When the Company uses words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “will,” “could,” “should,” “may,” “likely,” “plan,” “probably” or similar expressions, the Company is making forward-looking statements. Many risks and uncertainties that could affect the Company’s future results and could cause results to differ materially from those expressed in the Company’s forward-looking statements include, but are not limited to:

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The information contained in this report, including the information set forth under the heading “Risk Factors,” identifies additional factors that could cause the Company’s results or performance to differ materially from those the Company expresses in its forward-looking statements. Although the Company believes that the assumptions underlying its forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements which are included in this report, the Company’s inclusion of this information is not a representation by the Company or any other person that the Company’s objectives and plans will be achieved. When you consider the Company’s forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this report.

The Company’s forward-looking statements speak only as of the date made and the Company will not update these forward-looking statements unless the securities laws require the Company to do so. The Company’s forward-looking statements are expressly qualified in their entirety by this cautionary statement. In light of these risks, uncertainties and assumptions, any forward-looking events discussed in this report may not occur.

 

 

 

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You should carefully consider the following risk factors in addition to the other information included in this report. If any of these risks or uncertainties actually occurs, our business, financial condition and results of operations could be materially adversely affected. Additional risks not presently known to us or which we consider immaterial based on information currently available to us may also materially adversely affect us.

Almost all of the value of our production and reserves is concentrated in a single block offshore Gabon, and any production problems or reductions in reserve estimates related to this property would adversely impact our business.

The Etame field consisting of three producing wells, the Avouma/South Tchibala fields consisting of three wells, and the Ebouri field with one producing well constituted approximately 97% of our total production for the year ended December 31, 2014. In addition, at December 31, 2014, 97% of our total net proved reserves were attributable to these fields. If mechanical problems, storms or other events curtailed a substantial portion of this production, or if the actual reserves associated with this producing property are less than our estimated reserves, our results of operations, financial condition, and cash flows could be materially adversely affected.

Additionally, we discovered the presence of H₂S from two of our producing wells in the Ebouri field in 2012 and one in the Etame field in 2014.  At year end 2014 we intended to, and we still may, build a processing facility capable of removing H₂S from production in order to re-establish and maximize production from the impacted areas.  However, subsequent to 2014 year end, as a result of the substantial recent fall in oil prices, we are considering more cost efficient options, and there can be no assurances that the processing facility will be completed by 2017, if at all, or that a more cost effective facility will re-establish production to all affected wells in the Ebouri and Etame fields.  A determination to not build the processing facility in order to re-establish production or to build a more cost effective facility that does not re-establish all production from affected wells could force us to reclassify certain of our proved reserves in these fields as unproved reserves.

Oil and natural gas prices are highly volatile, and continued depressed prices will negatively affect our financial results.

Our revenues, cash flow, profitability, oil and natural gas reserves value and future rate of growth are substantially dependent upon prevailing prices for oil and natural gas. Our ability to borrow funds and to obtain additional capital on attractive terms is also substantially dependent on oil and natural gas prices. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas were highly volatile in 2014 and declined dramatically in the second half of the year. For example, during 2014, based on NYMEX pricing, the price for a barrel (bbl) of oil ranged from a high of $107.26 to a low of $53.27 and the price for an Mmbtu of natural gas ranged from a high of $8.15 to a low of $2.74.

Continued depressed oil and natural gas prices or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved reserves.  The average price at which we sold in 2014 was $93.66 per barrel compared to $108.35 per barrel in 2013, and $111.06 per barrel in 2012. Because the oil price we are required to use by Security and Exchange Commission (“SEC”) to estimate our future net cash flows is the average price over the 12 months prior to the date of determination of future net cash flows, the full effect of falling prices may not be reflected in our estimated net cash flows for several quarters.  We review the carrying value of our properties on a quarterly basis and once incurred, a write-down in the carrying value of our properties is not reversible at a later date, even if prices increase.

Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include, but are not limited to, increases in supplies from US shale production,  international political conditions, including recent uprisings and political unrest in the Middle East and Africa, the European sovereign debt crisis, the domestic and foreign supply of oil and natural gas, the level of consumer demand due to slowing economic growth in China and continued weak economic growth in Europe, weather conditions, domestic and foreign governmental regulations and taxes, the price and availability of alternative fuels, the health of international economic and credit markets, the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) and other state-controlled oil companies to agree upon and maintain oil price and production controls, and general economic conditions. In addition, various factors, including the effect of federal, state and foreign regulation of production and transportation, general economic conditions, changes in supply due to drilling by other producers and changes in demand may adversely affect our ability to market our oil and natural gas production. Any significant decline in the price of oil or natural gas would adversely affect our revenues, operating income, cash flows and borrowing capacity and may require a reduction in the carrying value of our oil and natural gas properties and our planned level of capital expenditures including the development of the H₂S processing facility.

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Increases in oil supplies from US shale production, coupled with slower economic growth in economies around the world and a decision by OPEC not to cut production to support higher oil prices, has led to a dramatic reduction in oil prices. While this fall in oil prices may escalate global economic growth rates, thereby increasing demand for oil supplies, the decline in oil prices may adversely affect our results of operations.

The increase in world oil supplies being produced, due to increased US shale production and OPEC’s decision not to reduce production to support higher oil prices, occurring at the same time as reduced economic activity associated with slower economic growth in China, Europe and other global economies has reduced the demand for, and the prices we receive for, our oil and natural gas production. A sustained reduction in the prices we receive for our oil and natural gas production will have a material adverse effect on our results of operations and the borrowing base under our credit facility. A reduction in the borrowing base (e.g., a reduction in the estimated value of our assets) under our credit facility could mean a reduction in the capital available for investment in our oil and natural gas exploration and development activities in 2015 and could require mandatory loan repayment obligations under our credit facility.

The development plan for our proved undeveloped reserves may take longer, require higher levels of capital expenditures or be revised by us in a manner other than we currently plan due to factors beyond our control, which may require that we re-classify proved undeveloped reserves to an unproved category.

Approximately 60% of our total estimated proved reserves as of December 31, 2014, were proved undeveloped reserves and may not be ultimately developed or produced.  Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations or successful construction of production facilities to treat H₂S produced along with oil. Subsequent to 2014 year end, as a result of the substantial recent fall in oil prices, we are considering reductions in our capital expenditures in connection with the processing facility, and there can be no assurances that the processing facility will be completed by 2017, if at all or that a more cost effective facility will re-establish production to all affected wells in the Ebouri and Etame fields.  The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves or a determination by us to not build and install the processing facility in order to re-establish production in the Ebouri and Etame fields could force us to reclassify certain of our proved reserves as unproved reserves.

We have identified material weaknesses in our internal control over financial reporting. These material weaknesses, if not corrected, could affect the reliability of our financial statements and have other adverse consequences.

Under Section 404 of the Sarbanes-Oxley Act of 2002, we are required to furnish a report by our management on internal control over financial reporting. This report must contain, among other matters, an assessment of the effectiveness of our internal control over financial reporting, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any material weaknesses in our internal control over financial reporting identified by our management. In addition, the report must contain a statement that our auditors have issued an attestation report on management's assessment of such internal control over financial reporting.

We have identified material weaknesses in our internal control over financial reporting as of December 31, 2014, as disclosed in “Item 9A. Controls and Procedures”. Failure to have effective internal controls could lead to a misstatement of our financial statements or prevent us from filing our financial statements in a timely manner. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial statements, our business decision processes may be adversely affected, our business and operating results could be harmed, investors could lose confidence in our reported financial information, the price of our common shares could decrease and our ability to obtain additional financing, or additional financing on favorable terms, could be adversely affected. In addition, failure to maintain effective internal control over financial reporting could result in investigations or sanctions by regulatory authorities.

We intend to take further action to remediate the material weaknesses and improve the effectiveness of our internal control over financial reporting. However, we can give no assurances that the measures we may take will remediate the material weaknesses identified or that any additional material weaknesses will not arise in the future due to our failure to implement and maintain adequate internal control over financial reporting. In addition, even if we are successful in strengthening our controls and procedures, those controls and procedures may not be adequate to prevent or identify irregularities or ensure the fair presentation of our financial statements included in our periodic reports filed with the SEC.

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Unless we are able to replace reserves which we have produced, our cash flows and production will decrease over time.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, our estimated net proved reserves will generally decline as reserves are produced. There can be no assurance that our planned development and exploration projects and acquisition activities will result in significant additional reserves or that we will have continuing success drilling productive wells at economic finding costs. The drilling of oil and natural gas wells involves a high degree of risk, especially the risk of dry holes or of wells that are not sufficiently productive to provide an economic return on the capital expended to drill the wells. In addition, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, political instability, availability of capital, economic/currency imbalances, compliance with governmental requirements, receipt of additional seismic data or the reprocessing of existing data, material changes in oil or natural gas prices, prolonged periods of historically low oil and natural gas prices, failure of wells drilled in similar formations or delays in the delivery of equipment and availability of drilling rigs. Certain domestic oil and natural gas producing properties, as well as our Equatorial Guinea property are operated by third parties and, as a result, we have limited control over the nature and timing of exploration and development of such properties or the manner in which operations are conducted on such properties.

Our results of operations, financial condition, cash flows and compliance with debt covenants could be adversely affected by changes in currency exchange rates.

We are exposed to foreign currency risk from our foreign operations. While oil sales are denominated in U.S. dollars, portions of our operating costs in Gabon are denominated in the local currency. A weakening U.S. dollar will have the effect of increasing operating costs while a strengthening U.S. dollar will have the effect of reducing operating costs. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has fluctuated widely in recent years in response to international political conditions, general economic conditions, the European sovereign debt crisis and other factors beyond our control. Our results of operations, financial condition, cash flows and compliance with debt covenants could be adversely affected by such fluctuations in currency exchange rates.

In addition, we entered into a credit facility in the first quarter of 2014 that includes financial covenants which could be affected by foreign currency exchange rates. Failure to maintain these covenants could preclude us from borrowing under our revolving credit facility and require us to immediately pay down any outstanding drawn amounts under the credit agreement, which could affect cash flows or restrict business. As of December 31, 2014, we were in compliance with all of our financial covenants under our credit facility.

Substantial capital, which may not be available to us in the future, is required to replace and grow reserves.

We make, and will continue to make, substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and natural gas reserves. Historically, we have financed these expenditures primarily with cash flow from operations, debt, asset sales, and private sales of equity. During 2014, we participated, and in 2015, we expect to continue to participate, in the further exploration and development projects on our international properties. In Gabon and Angola, we are the operator of the blocks and are thus responsible for contracting on behalf of all the remaining parties participating in the project. We rely on the timely payment of cash calls by our partners to pay for 69.95% of the offshore Gabon block budget, 50% of the onshore Gabon block budget and 50% of the offshore Angola block budget. The continued economic health of our partners could be adversely affected by low oil prices thereby adversely affecting their ability to make timely payment of cash calls.

However, if lower oil and natural gas prices, operating difficulties or declines in reserves result in our revenues being less than expected or limit our ability to borrow funds, or our partners fail to pay their share of project costs, we may have a limited ability to expend the capital necessary to undertake or complete future drilling programs. We cannot assure you that the financing under our credit facility will be available in the future or that additional debt or equity financing or cash generated by operations will be available to meet these requirements.  

Our drilling activities require us to risk significant amounts of capital that may not be recovered.

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by us will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain and cost overruns are common. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including title problems, weather conditions, equipment failures or

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accidents, elevated pressure or irregularities in geologic formations, compliance with governmental requirements and shortages or delays in the delivery of equipment and services.

Cyber-attacks targeting systems and infrastructure used by the oil and natural gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and natural gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and natural gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. While we have not experienced significant cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

Our credit agreement imposes significant operating and financial restrictions on us that may prevent us from pursuing certain business opportunities and restrict our ability to operate our business.

Our credit agreement contains certain covenants that restrict our ability to take various actions, such as:

The restrictions contained in the credit agreement could:

As of December 31, 2014, we believe we are in compliance with all of the financial covenants under our credit facility. Failure to maintain these covenants could preclude us from borrowing under our revolving credit facility and require us to immediately pay down any outstanding drawn amounts under the credit agreement, which could affect cash flows or restrict business.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.

Availability under our revolving credit facility is currently subject to a borrowing base of $65.0 million. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on the value of our oil and

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natural gas reserves as determined by the lenders under our credit facility, and other factors deemed relevant by our lenders. Recent declines in prices for oil and natural gas may cause our banks to reduce the borrowing base under our revolving credit facility.  As of December 31, 2014, we had outstanding borrowings of $15.0 million which bore a weighted average interest rate of 4.32%. We intend to continue borrowing under our revolving credit facility in the future. However, the credit facility contains a covenant that prevents us from borrowing any amounts that would cause our debt to equity ratio to exceed 60:40. As of December 31, 2014, we estimate that this covenant would restrict our total borrowing capacity to approximately $25.0 million. Additionally, any significant reduction in our borrowing base as a result of borrowing base redeterminations, or otherwise, may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further if, the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Weather, unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our oil and natural gas activities.

The oil and natural gas business involves a variety of operating risks, including fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases, underground migration and surface spills or mishandling of fracture fluids including chemical additives, the occurrence of any of which could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Our production facilities are also subject to hazards inherent in marine operations, such as capsizing, sinking, grounding, collision and damage from severe weather conditions. The relatively deep offshore drilling conducted by us overseas involves increased drilling risks of high pressures and mechanical difficulties, including stuck pipe, collapsed casing and separated cable. The impact that any of these risks may have upon us is increased due to the low number of producing properties we own.

We maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant unfavorable event not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows. Furthermore, we cannot predict whether insurance will continue to be available at a reasonable cost or at all.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

In an interpretive guidance on climate change disclosure, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities because of climate-related damages to our facilities and our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. If drought conditions were to occur, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.

We may not have enough insurance to cover all of the risks we face and operators of prospects in which we participate may not maintain or may fail to obtain adequate insurance.

Our business is subject to all of the operating risks normally associated with the exploration for and production, gathering, processing, and transportation of oil and natural gas, including blowouts, cratering and fire, any of which could result in damage to, or destruction of, oil and natural gas wells or formations, production facilities, and other property, as well as injury to persons. For protection against financial loss resulting from these operating hazards, we maintain insurance coverage, including insurance coverage for certain physical damage, blowout/control of a well, comprehensive general liability, and worker’s compensation and employer’s liability. However, our insurance coverage may not be sufficient to cover us against 100% of potential losses arising as a result of the foregoing, and for certain risks, such as political risk, nationalization, business interruption, war, terrorism, and piracy, for which we have limited or no coverage. In addition, we are not insured against all risks in all aspects of our business, such as hurricanes. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

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Our reserve information represents estimates that may turn out to be incorrect if the assumptions upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present values of our reserves.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating the underground accumulations of oil and natural gas that cannot be measured in an exact manner. The estimates included in this document are based on various assumptions required by the SEC, including unescalated prices and costs and capital expenditures subsequent to December 31, 2014, and, therefore, are inherently imprecise indications of future net revenues. Actual future production, revenues, taxes, operating expenses, development expenditures and quantities of recoverable oil and natural gas reserves may vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves incorporated by reference in this document. Specifically, the estimates for our reserves for the year ended December 31, 2014 included assumptions regarding capital expenditures to build the processing facility to remove H₂S and resume production in the Ebouri and Etame fields.  Subsequent to 2014 year end, as a result of the substantial recent fall in oil prices, we are considering more cost efficient options, and there can be no assurances that the processing facility will be completed by 2017, if at all, or that a more cost effective facility will re-establish production to all affected wells in the Ebouri and Etame fields.  A determination to not build the processing facility in order to re-establish production or to build a more cost effective facility that does not re-establish all production from affected wells could force us to reclassify certain of our proved reserves in these fields as unproved reserves.

In addition, our reserves may be subject to downward or upward revision based upon production history, results of future development, availability of funds to acquire additional reserves, prevailing oil and natural gas prices and other factors. Moreover, the calculation of the estimated present value of the future net revenue using a 10% discount rate as required by the SEC is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the oil and natural gas industry in general. It is also possible that reserve engineers may make different estimates of reserves and future net revenues based on the same available data.

The estimated future net revenues attributable to our net proved reserves are prepared in accordance with current SEC guidelines, and are not intended to reflect the fair market value of our reserves. In accordance with the rules of the SEC, our reserve estimates are prepared using an average of beginning of month prices received for oil and natural gas for the preceding twelve months. Future reductions in prices below the average calculated for 2014 would result in the estimated quantities and present values of our reserves being reduced.

A substantial portion of our proved reserves are or will be subject to service contracts, production sharing contracts and other arrangements. The quantity of oil and natural gas that we will ultimately receive under these arrangements will differ based on numerous factors, including the price of oil and natural gas, production rates, production costs, cost recovery provisions and local tax and royalty regimes. Changes in many of these factors do not affect estimates of U.S. reserves in the same way they affect estimates of proved reserves in foreign jurisdictions, or will have a different effect on reserves in foreign countries than in the United States. As a result, proved reserves in foreign jurisdictions may not be comparable to proved reserve estimates in the United States.

If oil and natural gas prices remain depressed for extended periods of time, we may be required to take write-downs in the value of our oil and natural gas properties.

The estimated future net revenues attributable to our net proved reserves are prepared in accordance with current SEC guidelines, and are not intended to reflect the fair market value of our reserves. In accordance with the rules of the SEC, our reserve estimates are prepared using the un-weighted average price received for oil and natural gas based on closing prices on the first day of each month for the preceding twelve months from the date of the report. Prices for oil or gas at their current levels after the severe decline in prices in the second half of 2014 are currently below the average calculated for 2014. Because the undiscounted cash flows and discounted fair value related to the Etame, Ebouri and Southeast Etame/North Tchibala fields were less than the book values for these fields, the Company recorded an impairment of $98.3 million in the fourth quarter of 2014. Sustained lower prices will cause the estimated quantities and present values of our reserves being reduced and which may necessitate further write-downs.

We have less control over our foreign investments than domestic investments, and added risk in foreign countries may affect our foreign investments.

Our international assets and operations are subject to various political, economic and other uncertainties, including, among other things, the risks of war, expropriation, nationalization, renegotiation or nullification of existing contracts, taxation policies, foreign exchange restrictions, changing political conditions, international monetary fluctuations, currency controls and foreign governmental regulations that favor or require the awarding of drilling contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction.  For example, the Gabonese government has recently audited the accounts of a number of energy companies, including ours, that has led to disputes.  The Gabonese government has formed a new oil company that

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may seek to participate in oil and natural gas projects in a manner that could be dilutive to the interest of current license holders and the Gabonese government is under pressure from the Gabonese labor union to require companies to hire higher percentage of Gabonese citizens. In addition, if a dispute arises with our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of the United States.

Private ownership of oil and natural gas reserves under oil and natural gas leases in the United States differs distinctly from our ownership of foreign oil and natural gas properties. In the foreign countries in which we do business, the state generally retains ownership of the minerals and consequently retains control of, and in many cases participates in, the exploration and production of hydrocarbon reserves. Accordingly, operations outside the United States may be materially affected by host governments through royalty payments, export taxes and regulations, surcharges, value added taxes, production bonuses and other charges.

Almost all of our proven reserves are located offshore of the Republic of Gabon. As of December 31, 2014, we carried an investment, before depletion and amortization, of approximately $168.5 million including leasehold and asset retirement obligations on our balance sheet associated with the Etame Marin block. We have operated in Gabon since 1995 and believe we have good relations with the current Gabonese government. However, there can be no assurance that present or future administrations or governmental regulations in Gabon will not materially adversely affect our operations or cash flows.

We have received an audit report related to our Etame Marin block operations from the Gabon Taxation Department, and an adverse result of the audit could result in a material liability and adversely affect our financial condition.

In October 2014, we received a provisional audit report related to our Etame Marine block operations from the Gabon Taxation Department as part of a special industry-wide audit of business practices and financial transactions in the Republic of Gabon. In November 2014, we responded to the Gabon Taxation Department requesting joint meetings to advance the resolution of this matter and provided a formal reply to the provisional audit report in February 2015. We currently cannot reasonably estimate a range of potential loss, if any, as a result of the audit. The ultimate outcome of the claim and impact cannot be predicted, and an adverse result of the audit could result in a material liability and adversely affect our financial condition.

Our operations may be adversely affected by violent acts such as from civil disturbances, terrorist acts, regime changes, cross-border violence, war, piracy, or other conflicts that may occur in regions that encompass our operations.

Violent acts resulting in loss of life, destruction of property, environmental damage and pollution occur around the world. Many incidents are driven by civil, ethnic, religious or economic strife. In addition, the number of incidents attributed to various terrorist organizations has increased significantly. We operate in regions of the world that have experienced such incidents or are in close proximity to areas where violence has occurred.

We monitor the economic and political environments of the countries in which we operate. However, we are unable to predict the occurrence of disturbances such as those noted above. In addition, we have limited ability to mitigate their impact.

Civil disturbances, terrorist acts, regime changes, war, or conflicts, or the threats thereof, could have the following results, among others:

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Loss of property and/or interruption of our business plans resulting from civil unrest could have a significant negative impact on our earnings and cash flow. In addition, we may not have enough insurance to cover any loss of property or other claims resulting from these risks.

Competitive industry conditions may negatively affect our ability to conduct operations.

The oil and natural gas industry is intensely competitive. We compete with, and may be outbid by, competitors in our attempts to acquire exploration and production rights in oil and natural gas properties. These properties include exploration prospects as well as properties with proved reserves. There is also competition for contracting for drilling equipment and the hiring of experienced personnel. Factors that affect our ability to compete in the marketplace include:

Our competitors include major integrated oil companies and substantial independent energy companies, many of which possess greater financial, technological, personnel and other resources than we do. These companies may be able to pay more for oil and natural gas properties, evaluate, bid for and purchase a greater number of properties than our financial or human resources permit, and be better able than we are to continue drilling during periods of low oil and natural gas prices, to contract for drilling equipment and to secure trained personnel. Our competitors may also use superior technology which we may be unable to afford or which would require costly investment by us in order to compete.

The distressed financial conditions of customers could have an adverse impact on us in the event these customers are unable to pay us for the products or services we provide.

Some of our customers may experience, as a result of the severe decline in oil and natural gas prices in 2014 and in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition.

We may be unable to integrate successfully the operations of any acquisitions with our operations and we may not realize all the anticipated benefits of the recent acquisitions or any future acquisition.

Failure to successfully assimilate any acquisitions could adversely affect our financial condition and results of operations.

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future

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acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities, which could result in material liabilities and adversely affect our financial condition.

One of our growth strategies is to capitalize on opportunistic acquisitions of oil and natural gas reserves. Any future acquisition will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities, and other liabilities and similar factors. Ordinarily, our review efforts are focused on the higher valued properties and are inherently incomplete because it generally is not feasible to review in depth every potential liability on each individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material liabilities and costs that negatively impact our financial condition.

Additional potential risks related to acquisitions include, among other things:

If we consummate any future acquisitions, our capitalization and results of operations may change significantly.

Compliance with environmental and other government regulations could be costly and could negatively impact production.

The laws and regulations of the United States, Gabon, Angola and Equatorial Guinea regulate our current business. Our operations could result in liability for personal injuries, property damage, natural resource damages, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and the issuance of orders enjoining operations. In addition, we could be liable for environmental damages caused by, among others, previous property owners or operators of properties that we purchase or lease. Some environmental laws provide for joint and several strict liabilities for remediation of releases of hazardous substances, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. As a result, we may incur substantial liabilities to third parties or governmental entities and may be required to incur substantial remediation costs. We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change and greenhouse gases and use of hydraulic fracturing fluids, resulting in increased operating costs. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could have a material adverse effect on our financial condition, results of operations and liquidity. Additionally, more stringent GHG regulation could impact demand for oil and natural gas.

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These laws and governmental regulations, which cover matters including drilling operations, taxation and environmental protection, may be changed from time to time in response to economic or political conditions and could have a significant impact on our operating costs, as well as the oil and natural gas industry in general. While we believe that we are currently in compliance with environmental laws and regulations applicable to our operations, no assurances can be given that we will be able to continue to comply with such environmental laws and regulations without incurring substantial costs.

If our assumptions underlying accruals for abandonment costs are too low, we could be required to expend greater amounts than expected.

Almost all of our producing properties are located offshore. The costs to abandon offshore wells may be substantial. For financial accounting purposes, we record the fair value of a liability for an asset retirement obligation in the period in which it is incurred by capitalizing it as part of the carrying amount of the long-lived assets. No assurances can be given that such reserves will be sufficient to cover such costs in the future as they are incurred.

As part of securing the first of two five-year extensions in 2011 to the Etame field production license to which the Company is entitled from the government of Gabon, the Company agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin Block. The agreement was finalized in the first quarter of 2014 (effective 2011) providing for annual funding over the remaining life of the production license. The amounts paid will be reimbursed through the cost account and are non-refundable to the Company. The initial funding took place in October 2014 for calendar years 2012 and 2013 totaling $8.4 million ($2.3 million net to the Company). The funding for calendar year 2014 was paid in the first quarter of 2015 in the amount of $4.2 million ($1.2 million net to the Company).  As in prior periods, the obligation for abandonment of the Gabon offshore facilities is included in the asset retirement obligation shown on the Company’s balance sheet. The cash funding is reflected under other long term assets as “Abandonment Funding”.

From time to time we may hedge a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and natural gas.

We may reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. Hedging also prevents us from receiving the full advantage of increases in oil or natural gas prices above the maximum fixed amount specified in the hedge agreement. Conversely, hedging may limit our ability to realize cash flows from commodity price increases. In a typical hedge transaction, we have the right to receive from the hedge counterparty the excess of the maximum fixed price specified in the hedge agreement over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the maximum fixed price, we must pay the counterparty this difference multiplied by the quantity hedged even if we had insufficient production to cover the quantities specified in the hedge agreement. Accordingly, if we have less production than we have hedged when the floating price exceeds the fixed price, we must make payments against which there are no offsetting sales of production. If these payments become too large, the remainder of our business may be adversely affected.

The distressed financial conditions of one or more hedge providers could have an adverse impact on us in the event these hedge providers are unable to pay us amounts owed to us under one or more financial hedge transactions by which we have hedged our exposure to commodity price volatility.

From time to time, we enter into financial hedge transactions to hedge or mitigate our exposure to the risks of commodity price volatility with respect to the crude oil or natural gas we produce and sell.  Similarly, some credit agreement facilities will require that we enter into financial hedges with creditworthy hedge providers for a percentage of our anticipated oil and natural gas production in order to ensure that we are able to make debt service payments under such credit facilities if oil and natural gas prices fall.  In such instances, the hedge provider will be obligated to make payments to us under such financial hedge transactions to the extent that the floating (market) price is below an agreed fixed (strike) price. During periods of falling commodity prices, including the recent severe decline in oil and natural gas prices, some of our hedge providers may experience, in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed hedge providers will not default on their obligations to make a payment owed to us or that such a default or defaults will not have a material adverse effect on our business, financial position, and future results of operations or future cash flows. Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. In addition, such events might force such hedge providers to reduce or curtail their future level of financial hedge availability (liquidity) to us, which could have a material adverse effect on our results of operations and financial condition and could have a material adverse effect on one or more of our credit agreement facilities. In addition, hedging agreements expose us to risk of financial loss if the counterparty to a hedging contract defaults on its contract obligations. This risk of counterparty performance is of particular concern given the disruptions that have occurred in the financial markets that led to sudden changes in counterparty’s liquidity and hence their ability to perform under their hedging contracts with us. We are unable to predict sudden changes in counterparty’s creditworthiness or ability to perform.  Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market

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conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on the Company’s ability to use financial derivative instruments to reduce (hedge, manage or mitigate) the effect of commodity price, interest rate, and other cost volatilities associated with its business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), signed into law in 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives markets and entities, such as us, that participate in those markets. The Dodd-Frank Act required the Commodities Futures Trading Commission (“CFTC”) and the Securities and Exchange Commission (“SEC”) to promulgate rules and regulations implementing the new legislation; although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on November 5, 2013, a proposed rule imposing position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain specified types of hedging transactions are exempt from these position limits, provided that such hedging transactions satisfy the CFTC’s requirements for “bona fide hedging” transactions or positions. Similarly, the CFTC has issued a proposed rule on Margin requirements, which proposes to exempt commercial end-users entering into uncleared swaps in order to hedge commercial risks affecting their business from any requirement to post margin to secure their swap transactions that are hedging commercial risks. In addition, the CFTC has issued a final rule authorizing an exception for commercial end-users using swaps to hedge their commercial risks from the otherwise applicable mandatory obligation under the Dodd-Frank Act to clear all swap transactions through a derivatives clearing organization and to trade all such swaps on an exchange.  The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.  All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business.

While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or margin requirements, depending on our ability to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate our commercial risks, these rules and regulations may require us to comply with position limits, margin requirements and with certain clearing and trade-execution requirements in connection with our financial derivative activities. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of commercial end-users to have access to financial derivatives to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes), materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our ability to hedge risks and on our consolidated financial position, results of operations, or cash flows.

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

In recent years, the current U.S. government’s budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for U.S. production activities and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and natural gas within the United States. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.

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We rely on our senior management team and the loss of a single member could adversely affect our operations.

We are highly dependent upon our executive officers and key employees. The unexpected loss of the services of any of these individuals could have a detrimental effect on us.  These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and developing and executing financing and hedging strategies.  We do not maintain key man life insurance on any of our employees.

We rely on a single purchaser of our Gabon production, which could have a material adverse effect on our results of operations.

Effective January 2011, we sold all of our crude oil production in Gabon to Mercuria, and the contract with Mercuria was extended through the first quarter of 2014. In Gabon, starting in the second quarter of 2014, the Company switched to an agency model to sell its crude oil. The Company contracted with a third party in order to sell, based on a fixed barrel fee, on the spot market. For the first quarter of 2015, the Company will also sell its oil under the agency model on the spot market.

The marketability of our production in Texas is dependent upon transportation and processing facilities over which we may have no control.

The marketability of our production from Texas depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. We deliver crude oil and natural gas produced from these areas through gathering systems and pipelines, some of which we do not own. The lack of availability of capacity on third-party systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical or other reasons, including adverse weather conditions. Activist or other efforts may delay or halt the construction of additional pipelines or facilities.

Third-party systems and facilities may not be available to us in the future at a price that is acceptable to us. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay production, thereby harming our business and, in turn, our financial condition, results of operations and cash flows.

Additionally, the price and terms for access to pipeline transportation in the U.S. remain subject to extensive federal and state regulation. If these regulations change, or if rate increase requests are approved, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity. Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The industry historically has been heavily regulated and we cannot provide assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions but is not subject to regulation at the federal level (except for fracturing activity involving the use of diesel). The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater.  A committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. In past sessions, legislation was introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local jurisdictions including Texas, where we operate, have adopted, or are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York recently has announced that it will impose a ban on high-volume hydraulic fracturing. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. Any other new laws or regulations that significantly restrict hydraulic fracturing could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect the determination of whether a well is commercially viable. Further, the EPA has announced an initiative under TSCA to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals and is working on regulations to address wastewater from hydraulic fracturing operations.  If hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities

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who could then make such information publicly available. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.

Additionally, a number of lawsuits and enforcement actions have been initiated across the country alleging that hydraulic fracturing practices have adversely impacted drinking water supplies, use of surface water, and the environment generally. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected.

Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.

 

None.

 

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Offshore Gabon- Etame Marin Block

VAALCO has an interest in an approximately 28,700 gross acre offshore block in Gabon, the Etame Marin block, where it signed a production sharing contract in 1995. The block contains the Etame, Avouma, South Tchibala and Ebouri fields, all of which are in production, and the Southeast Etame/North Tchibala field, which are currently being developed. These fields and discoveries consist of subsalt reservoirs that lie 20 miles offshore in water depths of approximately 250 feet.

VAALCO operates the Etame Marin block on behalf of a consortium of companies. The Company owns a 28.1% interest in the development areas in and surrounding the Etame, Avouma/South Tchibala and Ebouri fields. The development areas were subject to a 7.5% back-in by the Government of Gabon, which occurred for these fields after their successful development. The Government of Gabon has since assigned the back-in interest to a third party. The Southeast Etame/North Tchibala field will also be subject to the 7.5% back in by the Government of Gabon.

The Etame Marin block consortium approved the development of the Etame field in 2001. An application for commerciality was filed with the government of Gabon, and in July 2001 the consortium was awarded an approximately 12,000 gross acre exploitation area surrounding the field. The exploitation area has a term of 20 years through June 2021 (a ten year primary term followed by two subsequent five year renewals) and also includes the Southeast Etame field currently being developed.

The development of the Etame field included drilling and completing subsea wells connected to a contracted floating production, storage and offloading vessel (“FPSO”). More recently, in the third quarter of 2014, the Company installed a platform in approximately 250 feet of water and in the fourth quarter of 2014 commenced drilling of two development wells from the platform. The development wells are tied back to the FPSO via a pipeline. There are currently four wells producing in the Etame field.  

In April 2005, a development plan for the joint development of the Avouma/South Tchibala field was approved by the Gabon government. The Company was awarded an approximately 13,000 gross acre exploitation area which has a term of 20 years through March 2025 (a ten year primary term followed by two subsequent five year renewals). In 2006, the Company installed a platform in approximately 250 feet of water and drilled development wells from the platform. Three wells are currently producing in the South Tchibala/Avouma field.  A well in the Avouma field is temporarily not producing oil as it is waiting on a workover to replace an in-line valve and potentially the failed electrical submersible pumps. The development wells are tied back to the FPSO via a ten mile pipeline.

The Company drilled the Ebouri discovery well to total depth in January 2004. In October 2006, the Gabon government approved the development plan for the Ebouri field and the Company was awarded an approximately 3,700 gross acre exploitation area which has a term of 20 years through July 2026 (a ten year primary term followed by two subsequent five year renewals). A platform was installed in July 2008, approximately seven miles from the FPSO and is tied back to the FPSO via a pipeline as was done for the Avouma/South Tchibala field. The first development well began production in January 2009 and the second development well began producing crude oil in April 2009. A third development well began production in May 2010. There is currently one producing well in the Ebouri field.

In July 2012, the Company discovered the presence of hydrogen sulfide (“H₂S”) from two of the three producing wells in the Ebouri field. The wells were shut-in for safety and marketability reasons resulting in a decrease of approximately 2,000 BOPD or approximately 10% of the gross daily production from the Etame Marin block at that time. In addition, H₂S was first detected in January 2014 and later confirmed in July 2014 in the Etame 5-H well in the Etame field, and this well has also been shut-in. Analysis and options for re-establishing production from the impacted areas continued through the fourth quarter of 2014.  To re-establish and maximize production from the impacted areas, additional capital investment will be required, including a processing facility capable of removing H₂S, recompletion of the temporarily abandoned wells, and potentially, additional new wells. Considering the substantial recent fall in oil prices, the Company and its partners are focusing on more cost efficient options for a processing facility (e.g. chemical removal options, construction of a smaller facility on existing structures, or the use of surplus equipment and used structures). There can be no assurances that the processing facility will be completed by 2017, if at all, or that a more cost effective facility will cover all affected areas of the Ebouri and Etame fields. It is expected that the timing of the project startup will be known as early as the fourth quarter of 2015 with a goal of re-establishing production from the area impacted by H₂S as soon as practical. Should the Company and its partners evaluation result in no economic alternative, a decrease of as much as 2.4 million barrels of proved undeveloped reserves could result.

The Company and its partners approved the construction of two additional production platforms in late 2012 as part of future development plans for the Etame Marin block. The construction of the two new platforms began in the first quarter of 2013 and were installed in the third quarter of 2014. One platform was installed in the Etame field and the second platform was installed between the Southeast Etame/North Tchibala field.  The Company contracted a drilling rig to commence a multi-well development drilling

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program, which moved onto location and began drilling the first well in November 2014 from the Etame platform, in the Etame field. The Company drilled a successful exploration well in the Southeast Etame area in 2010 which is expected to be developed from the second platform in 2015. The total cost to build and install the two platforms was $351.0 million ($106.5 million net to the Company). The cost of the wells is not included in the platform costs.

The sixth extension of the exploration acreage on this block expired at the end of July 2014. The Company fully met all of the obligations under the terms of the sixth extension period.  In the second quarter of 2014, and prior to the deadline, the Company and its partners submitted a proposal for a seventh exploration license. The Government of Gabon responded in the first quarter of 2015 that a seventh exploration license would require a separate production sharing contract (“PSC”) and this requirement is being evaluated by the Company and its partners.  

Late in 2012, a drilling and workover campaign began with the arrival of a drilling rig to conduct a six well program that was ultimately increased to an eight well program extending into 2014.  The early-2014 program included the drilling of an exploration well that did not discover commercial quantities of hydrocarbons.  Accordingly, the Company expensed $1.9 million of incurred dry hole costs in the fourth quarter of 2013 for this well, with the remainder of $11.7 million of dry hole costs expensed in the first quarter of 2014.  The Company performed a workover to replace the electrical submersible pumps in a well in the Avouma field in the first quarter of 2014 and in May 2014 brought on production a development well drilled in the South Tchibala field to replace a well with damaged casing.  

Following the installation of the two additional platforms in the third quarter of 2014, the Company and its partners began a development well drilling campaign beginning in October 2014 from the Etame platform.  The first well drilled, the Etame 8-H well, was completed in December 2014 and was shut-in as the well was determined to be producing H₂S during the initial testing process.  The Company is planning to conduct an extended well test of the Etame 8-H well, to confirm and quantify the presence of H₂S which was detected during the initial 17 hour flow test.  The well test is expected to occur in the first half of 2015. In December 2014, the Company spudded the Etame 10-H well which was drilled to the 1-V fault block, and the well was brought on production in the first quarter of 2015. The Etame 10-H well confirmed the presence of an undrained lower lobe of the Gamba reservoir in this fault block with no H₂S present. Additional development wells are expected to be drilled in 2015 from the two platforms.

As part of securing the first of two five-year extensions in 2011 to the Etame field production license to which the Company is entitled from the government of Gabon, the Company agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin Block. The agreement was finalized in the first quarter of 2014 (effective 2011) providing for annual funding over the remaining life of the production license. The amounts paid will be reimbursed through the cost account and are non-refundable to the Company. The initial funding took place in October 2014 for calendar years 2012 and 2013 totaling $8.4 million ($2.3 million net to the Company). The funding for calendar year 2014 was paid in the first quarter of 2015 in the amount of $4.2 million ($1.2 million net to the Company).  As in prior periods, the obligation for abandonment of the Gabon offshore facilities is included in the asset retirement obligation shown on the Company’s balance sheet. The cash funding is reflected under other long term assets as “Abandonment Funding”.

In the fourth quarter of 2014, the Company recorded an impairment loss of $98.3 million to write down its investment in certain fields comprising the Etame Marin Block, offshore Gabon to its fair value. An impairment of $38.5 million was recorded in the Etame field, $5.9 million in the Ebouri field and $53.9 million in the Southeast Etame/North Tchibala field.  The impairment is a result of the recent decline in the forecasted oil prices used in the impairment testing and calculation.

Onshore Gabon - Mutamba Iroru block

In November 2005, the Company signed a production sharing contract for the Mutamba Iroru block onshore Gabon. The five year contract awarded the Company exploration rights to approximately 270,000 acres along the central coast of Gabon. The Company acquired aeromagnetic gravity data in 2008, and together with seismic data acquired from previous operators over the block in 2006 and 2007, drilled two exploration wells in 2009. Both wells encountered water bearing sands and were abandoned.

The Company executed a farm-out agreement in August 2010 with Total Gabon on the Mutamba Iroru block located onshore near the coast in central Gabon. Under the terms of the agreement, the Company and Total Gabon committed to reprocess 400 kilometers of 2-D seismic data and drill one exploration well. The seismic reprocessing work was completed in 2012. The exploration well was drilled in 2012 resulting in a discovery. In return for funding 75% of the work commitment (seismic reprocessing and exploration well costs), Total Gabon earned a 50% interest on the permit.

A revised production sharing contract (“PSC”) including exploration rights is in the approval process.  The term sheet, which specifies financial and other obligations to be included in the PSC, was agreed to and signed by the Company, its joint venture partner, and the Government of Gabon on July 31, 2014. The form of the PSC has been completed and presented to the Company and its joint

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venture partner for execution.  The joint venture partner has withheld its approval of the new PSC pending resolution of certain legal aspects of the new agreement with the Government of Gabon.  In March 2015, the joint venture partner indicated to the Company that the legal aspects have not yet been resolved to their satisfaction. The Company can provide no assurance as to the joint venture partner approving the PSC. The Company remains committed to this block and further meetings of the parties are expected to occur in the first half of 2015.  

After the PSC is approved, an application for a development area will be made by the Company.  After issuance of a development area, the next step is the submittal of the plan of development.  The Company can provide no assurances as to the either the approval of the PSC by the Government of Gabon, or the subsequent approval of a development area by the Government of Gabon.

Development of the onshore block is expected to capitalize on synergies such as experienced personnel from our operating base office space, warehouse and open yard space in Port Gentil, Gabon.

Offshore Angola – Block 5

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola. The four year primary term, with an optional three year extension, awards the Company exploration rights to 1.4 million acres offshore central Angola. The Company’s working interest is 40%. Additionally, the Company is required to carry the Angolan national oil company, Sonangol P&P, for 10% of the work program. During the first four years of the contract, the Company had commitments to acquire and process seismic and drill two exploration wells.  The seismic commitments were met within the time period, but the wells were not drilled due to partner non-performance.

The government-assigned working interest partner was delinquent in paying their share of the costs several times in 2009 and consequently was placed in a default position. By a governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract, and a one year time extension was granted for drilling the two exploration commitment wells. Additional extensions were subsequently granted by the Angolan government until November 30, 2014 to drill the two exploration commitment wells.

In the fourth quarter of 2013, the Company received a written confirmation from The Ministry of Petroleum of Angola that the available 40% working interest in Block 5, offshore Angola, has been assigned to Sonangol E.P., the National Concessionaire.  The Ministry of Petroleum also confirmed that Sonangol E.P. would assign the aforementioned participating interest to its exploration and production affiliate, Sonangol P&P. The assignment was made effective on January 1, 2014. The unpaid amounts from the defaulted partner plus the amounts incurred on partner behalf during the period prior to assignment of the working interest to Sonangol P&P are believed by the Company to be the responsibility of the acquirer of the working interest.  The Company invoiced Sonangol P&P for these amounts totaling $7.6 million plus interest in April 2014.  Due to the uncertainty of collection, the Company has recorded a full allowance totaling $7.6 million during 2011 through 2013 for the amount owed to the Company above its 40% working interest plus the 10% carried interest.

In April 2014, the Company received a letter and contractual amendment proposal from Sonangol E.P., the national oil company in Angola related to the extension of the two well drilling commitment. Due to the uncertainty that the primary term of the exploration license would be extended by the Republic of Angola in accordance with the contractual amendment proposal before the November 30, 2014 expiration date, in October 2014, the Company entered into the Subsequent Exploration Phase (“SEP”), together with its working interest partner, Sonangol P&P. The SEP option was provided for in the Production Sharing Agreement signed in 2006 with the Republic of Angola. The SEP extends the exploration period for an additional three year period such that the new expiry date for exploration activities is November 30, 2017. Entering the SEP requires the Company and its partner to acquire 3D seismic covering six hundred square kilometers and to drill two additional exploration wells. The Company has already satisfied the seismic obligation of the SEP with the purchase of 3D seismic in the outboard segment of the block in late 2013, which is currently being processed and will continue to be processed into 2015.

By entering into the SEP, the Company is required to drill a total of four exploration wells during the exploration extension period.  The four well obligations include the two well commitments under the primary exploration period that carries over to the SEP period. A $10.0 million dollar assessment ($5.0 million dollars net to VAALCO) applies to each of the four commitment exploration wells, if any, that remain undrilled at the end of the exploration period in November 2017. Restricted cash of $10.0 million for the two new commitment wells was recorded in the fourth quarter of 2014. At December 31, 2014 the Company had $20.0 million in restricted cash related to the offshore Angola exploration agreement.

A drilling rig contract was signed in July 2014 for a semi-submersible rig to drill the exploration well on the Kindele prospect, a post-salt objective. The well began drilling in the first quarter of 2015. Drilling this well satisfies one of the four exploration well obligations and will release $5.0 million of the $20.0 million recorded as restricted cash at December 31, 2014 by the Company.

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Offshore Equatorial Guinea - Block P

In July 2012, the Company signed a definitive agreement with Petronas Carigali Overseas SDN BHD for the purchase of a 31% working interest in Block P, located offshore Equatorial Guinea for 57,000 acres at a cost of $10.0 million. The acquisition was completed on November 1, 2012. GEPetrol, the national oil company of Equatorial Guinea, is the operator of the block. During 2014, the Company and GEPetrol continued to work on a joint operatorship model whereby the Company would have a significant role in operator activities on the block. Additionally, the Company has been working with the Ministry of Mines, Industry and Energy regarding timing and budgeting for development and exploration activities.

Onshore Domestic - Texas

The Company acquired a 640 acre lease in the Hefley field (Granite Wash formation) in North Texas in December 2010 and a 480 acre lease in the same formation in July 2011. The first well drilled in the Hefley field began production in August 2011. Production from the second well drilled began in April 2012. During 2014, the two wells produced approximately 3,000 Bbls of condensate and 200 million cubic feet of gas net to the Company after deduction of royalty and severance taxes.  Financial impairments totaling $12.6 million were recorded for the Hefley field in 2011 and 2012 on the basis of production performance, projected hydrocarbon price curves, operating expenses and estimated reserves.  In the second half of 2013, the Company expensed the remaining unevaluated leasehold costs of the two leases totaling $2.6 million. No capital expenditures occurred in 2014 and no additional capital expenditures are anticipated in 2015 for this property.

Onshore Domestic - Montana

In September 2011, the Company acquired a 65% working interest in approximately 22,000 gross acres (14,300 net acres) covering the Middle Bakken and deeper formations in the East Poplar unit and the Northwest Poplar field in Roosevelt County, Montana. The working interest was subsequently reduced to 50% and 11,000 net acres in December 2012.  Pursuant to the terms of the acquisition, the Company was required to drill three wells at its sole cost. The first of the two wells drilled were unsuccessful efforts, resulting in dry hole costs and leasehold impairment totaling $18.4 million recorded in the fourth quarter of 2012. The third well which was drilled in the fourth quarter of 2012 at a cost of $3.0 million was charged to dry-hole expense in the third quarter of 2013. The remaining carrying value of the undeveloped acreage of this property is $1.3 million and is held by production.  No capital expenditures occurred in 2014, and no capital expenditures are anticipated for this property in 2015.

Domestic – Outside Operated

The Company has minor interests in Brazos County, Texas producing from the Buda/Georgetown formations. The Company also owns certain minor non-operated interests in the Ship Shoal area of the Gulf of Mexico and in Pickens County, Alabama. During 2014, these wells produced approximately 100 Bbls of oil and 5 million cubic feet of gas net to the Company. No significant activity was undertaken on these properties in 2014 and no capital expenditures are anticipated in 2015 for these properties.

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Sales Volumes, Prices, and Production Costs

Sales volumes, prices, and production costs (net to the Company) for the Company’s operations for the years 2014, 2013, and 2012 are shown below.

 

 

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RESERVE INFORMATION

The table below sets forth the Company’s estimated net proved reserves for the years ended December 31, 2014, 2013, and 2012 as prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. There have been no estimates of total proved net oil or gas reserves filed with or included in reports to any federal authority or agency other than the SEC since the beginning of the last fiscal year. International reserves are located in the Etame Marin block offshore Gabon.  Domestically, reserves are located in Texas (onshore), Louisiana (offshore) and Alabama (onshore). Reserves estimated by our independent engineers at December 31, 2014, 2013, and 2012 reflect oil and natural gas spot prices based on the average prices during the 12-month period before the ending date of the period covered by this report determined as an unweighted, arithmetic average of the first-day-of-the-month price for each month within such period.

 

Proved Undeveloped Reserves

The Company annually reviews all proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. The Company’s PUDs are generally expected to be converted to proved developed reserves within five years of the date they are first booked as PUDs. However, lower prices for oil and natural gas as seen in the recent decline may cause the Company in the future to forecast less capital to be available for development of its proved undeveloped reserves in the future, which will cause the Company to decrease the amount of its proved undeveloped reserves it expects to develop within the allowed time frame.  In addition, lower oil and natural gas prices may cause the Company’s proved undeveloped reserves to become uneconomic to develop, which would cause it to remove them from the proved undeveloped category.  Specifically, the estimates of the Company’s reserves for the year ended December 31, 2014 included assumptions regarding capital expenditures to build the processing facility to remove H₂S and resume production from certain wells in the Ebouri and Etame fields.  Subsequent to 2014 year end, as a result of the substantial recent fall in oil prices, the Company is considering more cost efficient options, and there can be no assurances that the processing facility will be completed by 2017, if at all, or that a more cost effective facility will cover all affected areas of the Ebouri and Etame fields.  A determination to not build the processing facility, or to build a more cost effective facility, could force the Company to reclassify certain of its PUDs in these fields as unproved reserves.

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The Company had 5,036 MBbls of PUD’s at December 31, 2014 compared with 3,927 MBbls of PUD’s at December 31, 2013.  Approximately 3.5 million barrels of the PUD’s are related to the construction of the two new platforms for Etame and Southeast Etame/North Tchibala (2.4 MBbls and 1.1 MBbls of PUD’s respectively).   Approximately 1.1 MBbls of PUD’s are associated with the Ebouri field.  The remaining 0.4 MBbls of PUD’s associated with the Avouma/South Tchibala field. The table below shows the years that the existing PUD’s (MBbls) were booked (unaudited).

 

 

All of the reserves at Ebouri, and a portion of the reserves in the main fault block at Etame may be sour, and the development of these reserves is dependent upon the installation of processing facilities to remove H₂S.

Elaborating, in July 2012, the Company discovered the presence of hydrogen sulfide (“H₂S”) from two of the three producing wells in the Ebouri field. The wells were shut-in for safety and marketability reasons resulting in a decrease of approximately 2,000 BOPD or approximately 10% of the gross daily production from the Etame Marin block at that time. In addition, H₂S was first detected in January 2014 and later confirmed in July 2014 in the Etame 5-H well in the Etame field, and this well has also been shut-in. Analysis and options for re-establishing production from the impacted areas continued through the fourth quarter of 2014.  To re-establish and maximize production from the impacted areas, additional capital investment will be required, including a processing facility capable of removing H₂S, recompletion of the temporarily abandoned wells, and potentially, additional new wells. Considering the substantial recent fall in oil prices, the Company and its partners are focusing on more cost efficient options for a processing facility (e.g. chemical removal options, construction of a smaller facility on existing structures, or the use of surplus equipment and used structures). There can be no assurances that the processing facility will be completed by 2017, if at all, or that a more cost effective facility will cover all affected areas of the Ebouri and Etame fields. It is expected that the timing of the project startup will be known as early as the fourth quarter of 2015 with a goal of re-establishing production from the area impacted by H₂S as soon as practical. Should the Company and its partners evaluation result in no economic alternative a decrease of as much as 2.4 million barrels of proved undeveloped reserves could result at Etame and Ebouri.

The Company does not have any PUD’s associated with its United States operations.

Controls Over Reserve Estimates

The Company’s policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations and GAAP. Compliance with these rules and regulations with respect to the Company’s reserves is the responsibility of the Company’s reservoir engineer, who is the Company’s principal engineer. The Company’s principal engineer has over 20 years of experience in the oil and gas industry, including over 10 years as a reserve evaluator, trainer or manager and is a qualified reserves estimator, as defined by the Society of Petroleum Engineers’ standards. Further professional qualifications include a Bachelor’s and Master’s degree in petroleum engineering, extensive internal and external reserve training, and asset evaluation and management. In addition, the principal engineer is an active participant in industry reserve seminars, professional industry groups and has been a member of the Society of Petroleum Engineers for over 20 years.

The Company’s controls over reserve estimates included retaining NSAI as our independent petroleum and geological firm. The Company provided information about the Company’s oil and gas properties, including production profiles, prices and costs, to NSAI and they prepare their own estimates of the reserves attributable to our properties. All of the information regarding reserves in this annual report on Form 10-K is derived from the report of NSAI. The report of NSAI is included as an exhibit to this annual report on Form 10-K.

The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies.  NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical

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persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. John Cliver and Mr. Patrick Higgs. Mr. Cliver, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2009 and has over 5 years of prior industry experience.  He graduated from Rice University in 2004 with a Bachelor of Science Degree in Chemical Engineering and from University of Texas at Austin in 2008 with a Master of Business Administration Degree.  Mr. Higgs, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1996 and has over 20 years of prior industry experience.  He graduated from Texas A&M University in 1976 with a Bachelor of Science Degree in Geophysics.  Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The Audit Committee of the Board of Directors meets with management, including the Company’s principal engineer, to discuss matters and policies related to reserves.

The following tables set forth the net proved reserves of the Company as of December 31, 2014, 2013 and 2012, and the changes during such periods.

 

 

The Company does not book proved reserves on discoveries until such time as a development plan has been prepared and approved by the Company’s partners in the discovery. Furthermore, if a government agreement that the reserves are commercial is required to develop the field, this approval must have been received prior to booking any reserves.

The Company’s proved developed reserves are located offshore Gabon and in Alabama, Texas and waters of the Gulf of Mexico.  Revisions in 2014 were primarily due to better reservoir performance at the Avouma/South Tchibala field (1,507 MBbls) and a combination of better reservoir performance from existing wells at Etame, and revisions to proved undeveloped reserves at Etame (1,122 MBbls).  Ebouri proved undeveloped reserves were revised downward (300 MBbls) due to higher costs of developing the reserves rendering them uneconomic.   Revisions in 2013 were primarily due to better reservoir performance at the Etame field (800 MBbls).  In 2012, the revisions were due to improved reservoir performance at the Avouma/South Tchibala field (1,200 MBbls) and improved reservoir performance at Etame (1,000 MBbls). In 2014, the extensions and discoveries were associated with the booking of the Southeast Etame/North Tchibala reserves. Extensions and discovery reserve additions in 2013 were due to the drilling of the Avouma 3H well which extended the reservoir boundary further to the north at the Avouma field.  In 2012, the extensions and discoveries were associated with the booking of the Southeast Etame/North Tchibala reserves following approval of the development plans for these fields and final investment decision to install the platforms necessary to develop these fields.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and

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judgment. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Company’s properties. The information set forth in the foregoing tables includes revisions for certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in product prices. Moreover, crude oil amounts shown for Gabon are recoverable under a service contract and the reserves in place remain the property of the Gabon government.

In accordance with the current guidelines of the SEC, the Company’s estimates of future net cash flow from the Company’s properties and the present value thereof are made using oil and gas contract prices using a twelve month average price and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. In Gabon, the 12-month weighted average price of oil as of December 31, 2014, was $98.88 per Bbl. In the United States, the 12-month weighted average price as of December 31, 2014, was $86.49 per Bbl of condensate and $5.193 per Mcf of gas. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates.  Prices for oil or gas at their current levels after the severe decline in the second half of 2014 are currently below the average calculated for 2014, and sustained lower prices will cause the twelve month weighted average price to decrease over time as the lower prices are reflected in the average price, resulting in the estimated quantities and present values of the Company’s reserves being reduced.

Additionally, the estimates for the Company’s reserves for the year ended December 31, 2014 included assumptions regarding capital expenditures to build the processing facility to remove H₂S and resume production from certain wells in the Ebouri and Etame fields.  Subsequent to 2014 year end, as a result of the substantial recent fall in oil prices, the Company is considering more cost efficient options, and there can be no assurances that the processing facility will be completed by 2017, if at all, or that a more cost effective facility will cover all affected areas of the Ebouri and Etame fields.  A determination to not build the processing facility or to build a more cost effective facility could cause the Company to reclassify certain of its PUDs in these fields as unproved reserves.

Drilling History

In 2014, the Company drilled three wells and completed one well reported in 2013 as being in-progress as follows: one development well offshore Gabon in the Avouma/South Tchibala field (productive), two developments wells offshore Gabon in the Etame field (in-progress) and one exploratory well offshore Gabon (dry, reported as being in-progress at the end of 2013).