UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

(Mark One)

 

 

For the fiscal year ended December 31, 2015

OR

 

For the transition period from              to             

Commission file number: 1-32167

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VAALCO Energy, Inc.

(Exact name of registrant as specified on its charter)

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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

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

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  ☒

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate 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  ☒     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.  ☒

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  ☒

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, as of June 30, 2015 was approximately $124.7 million based on a closing price of $2.14 on June 30, 2015.

As of February 29, 2016, there were outstanding 58,527,169 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 Natural Gas Terms

Terms used to describe quantities of oil and natural gas

Terms used to describe the legal ownership of oil and natural gas properties

Terms used to describe interests in wells and acreage

 

Terms used to classify 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:

(A)  The area identified by drilling and limited by fluid contacts, if any, and

(B)  Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data.

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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 natural 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:

(A)  Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B)  The project has been approved for development by all necessary parties and entities, including governmental entities.

(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 producibility 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 used to assign a present value to reserves

Terms used to describe seismic operations

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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, (the “Exchange Act”) which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate may occur in the future, including without limitation, statements regarding our 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 management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “will,” “could,” “should,” “may,” “likely ,”  “plan,” “probably” or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:

The information contained in this report, including the information set forth under the heading “Item 1A. Risk Factors,” identifies additional factors that could cause our results or performance to differ materially from those we express in forward-looking statements. Although we believe that the assumptions underlying our 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, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this report.

Our forward-looking statements speak only as of the date made, and we will not update these forward-looking statements unless the securities laws require us to do so. Our 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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PART I

Item 1. Business

BACKGROUND

VAALCO Energy, Inc. is a Delaware corporation,  incorporated in 1985 and headquartered at 9800 Richmond Avenue, Suite 700, Houston, Texas 77042:  telephone number is (713) 623-0801 and the website is www.vaalco.com. Consolidated 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., VAALCO Energy Mauritius (EG) Limited and VAALCO Energy (USA), Inc. As used in this Annual Report on Form 10-K, the terms, “we”, “us”, “our”, and “VAALCO” mean VAALCO Energy, Inc. and its consolidated subsidiaries, unless the context otherwise requires.

VAALCO is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. We own producing properties and conduct exploration activities as operator in Gabon, West Africa; we conduct exploration activities as an operator in Angola, West Africa, and we participate in exploration and development activities as a non-operator in Equatorial Guinea, West Africa. In the United States (“U.S.”), we operate unconventional resource properties in North Texas and hold undeveloped leasehold acreage in Montana. We also own minor interests in conventional production activities as a non-operator in the U.S. 

STRATEGY

Our strategy has been significantly impacted by the current commodity price environment, in which we have experienced unprecedented oil price declines beginning in the fall of 2014. These price declines have had, and will likely continue to have, a material adverse impact on our cash flows, results of operations and liquidity. As a result of these price declines and significant uncertainties regarding our liquidity, we have substantially adjusted our strategic focus. The consequences of these uncertainties, and our plans to address them, are described in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Current Developments,” “ —Going Concern” and “–Capital Resources and Liquidity,” and Note 2 to the consolidated financial statements included in Part III, Item 8 – “Financial Statements and Supplementary Data.” See also Item 1A. “Risk Factors – Due to our substantial liquidity concerns, we may be unable to continue as a going concern.”

If oil and natural gas prices continue to remain at the current depressed levels, we expect that for 2016 we will not generate adequate revenue to cover our operating expenses, we will generate losses from operations, and our cash flows will not be sufficient to cover our operating expenses. In addition, we experienced significant negative revisions to our estimated proved reserves based upon this low pricing environment. The low oil and natural gas prices affected the economic feasibility of developing our proved undeveloped reserves. These circumstances lead to the reclassification of certain of our resources from proved undeveloped reserves to unproved, which could have material adverse implications for the value of our company, cash flows, access to capital, liquidity and financial condition.

In 2016, we embarked on a strategic alternatives initiative designed to identify and execute on that option which is most likely to result in the greatest value for our shareholders. We are considering multiple alternatives, including, but not limited to, additional debt or equity financing, a sale or farm-down of assets, delay of the discretionary portion of our capital spending to future periods, operating cost reductions, joint ventures and a potential sale or merger.  The Board of Directors has formed a strategic committee to oversee the evaluation of our strategic alternatives. In addition, we have engaged Scotia Capital (USA) Inc. as financial advisor. We plan to secure funds necessary to continue as a going concern.  However, our current cash position and our ability to access additional capital may limit our available opportunities or not provide sufficient cash for operations and there can be no guarantee of future capital acquisition or fundraising success. We are focused on a financially driven operating strategy while pursuing strategic growth opportunities.

Financially Driven Operating Strategy

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Strategic Alternative Opportunities

We believe that we have strong management and technical expertise specific to West Africa which gives us an advantage when looking at growth opportunities in this region:

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic financial information, see Note 13 to the consolidated financial statements which begin on page F-1.

Gabon  Segment

Offshore – Etame Marin Block

Our most significant asset, which accounts for the majority of our revenues, is the Etame Production Sharing Contract (“PSC”), which was signed in 1995, related to the Etame Marin block located offshore the Republic of Gabon (“Gabon”).  The Etame Marin block covers an area of approximately 28,700 gross acres and consists of subsalt reservoirs that lie 20 miles offshore in water depths of approximately 250 feet. The Etame, Avouma/South Tchibala, Ebouri, Southeast Etame and North Tchibala fields are included in the block. Our working interest in the Etame Marin block is 28.1%, and we operate it on behalf of a consortium of five companies.  The development is subject to a 7.5% back-in interest by the Government of Gabon which they assigned to a third party.

Development

In late 2012, we and our partners approved a development plan, consisting of two new platforms and a multi-well development drilling campaign. The drilling campaign included drilling three development wells from the Etame platform, three development wells from the Southeast Etame/North Tchibala (“SEENT”) platform and workovers of existing wells in the Etame Marin block. 

In May 2014, we  contracted the Constellation II drilling rig to use in the development drilling campaign. Following the installation of the Etame and SEENT platforms in the third quarter of 2014, we commenced drilling the first well, the Etame 8-H, in November 2014 from the Etame platform. In December 2014, we shut-in the Etame 8-H well after determining that it was producing hydrogen sulfide (“H₂S”). See “Hydrogen Sulfide Impact” below. In 2015, two new development wells were drilled and brought on production from the Etame platform.  The Etame 10-H well was brought on production in the first quarter of 2015, and the Etame 12-H well, which began drilling in March 2015, was brought on production in the second quarter of 2015. We moved the rig early in the second quarter of 2015 to the SEENT platform.  Three new development wells were drilled and brought on production from the SEENT platform in 2015: the Southeast Etame 2-H, the North Tchibala 1-H and the North Tchibala 2-H. All the wells brought online subsequent to the Etame 8-H have not produced H₂S. The two wells in the North Tchibala field are the first offshore Gabon wells to produce from the Dentale formation. The rig was moved to the Avouma platform in December 2015 to perform workovers on three wells: South Tchibala 2-H, Avouma 3-H and Avouma 2-H. At the end of 2015, one workover had been completed successfully and the second was underway. In January 2016, the workover campaign was complete. The South Tchibala 2-H was restored to production after being offline since August 2014, and the Avouma 2-H well resumed production at an increased rate. The Avouma 3-H, which was not on production prior to the workover, has been suspended and secured for future use. During the workover operations on the Avouma 3-H, the downhole equipment became lodged in the wellbore with efforts to remove it proving unsuccessful. In 2016, we released the Constellation II rig and no longer intend to drill any wells in 2016 on our Etame Marin block offshore Gabon. We expect to incur costs of up to $7 million related to the contract period from the rig release date through its expiration, for which a liability will be recognized in the first quarter of 2016.

Production

Production operations in the Etame Marin block include 12 wells from four platforms, plus three subsea wells across all fields tied back by pipelines to deliver oil and associated natural gas through a riser system to allow for delivery, processing, storage and ultimately offloading the oil from a leased Floating, Production, Storage and Offloading vessel (“FPSO”) anchored to the seabed on the block. With the FPSO limitations of approximately 25,000 BOPD and 30,000 barrels of total fluids per day, the challenge is to optimize production on both a near and long-term basis subject to investment and operational agreements between VAALCO and the consortium.  During 2015 and 2014,  aggregate production from the block was approximately 6.8 MMBbls (1.7 MMBbls net to us) and 5.8 MMBbls (1.4

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MMBbls net to us), respectively. Our net share of barrels produced reflects an allocation of cost oil and profit oil, after reduction for a  royalty of approximately 13%.

Etame field –  In 2001, the government of Gabon awarded VAALCO and its partners a 12,000 gross acre exploitation area for development of the Etame 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 which is discussed below. The Etame field was originally developed with a total of six subsea wells connected to the FPSO. In the third quarter of 2014, we completed the installation of a  new platform on the field and in the fourth quarter of 2014 commenced the development drilling campaign discussed above which included the drilling of three wells in the Etame field. There are currently five wells producing in the Etame field.  

Avouma/South Tchibala field  –  In 2005, the government of Gabon awarded VAALCO and its partners a 13,000 gross acre exploitation area for the joint development of the Avouma/South Tchibala field. The exploitation area has a term of 20 years through March 2025 (a ten year primary term followed by two subsequent five year renewals). In 2006, we installed a platform at the Avouma/South Tchibala field and subsequently drilled four development wells. At December 31, 2015, three wells were producing, and a workover was underway on the fourth well. As discussed above, the workover of the Avouma 3-H was unsuccessful, and it remains off production in 2016.

Ebouri field –  We drilled the Ebouri discovery well in January 2004. As a result of this discovery well, in 2006, the government of Gabon awarded VAALCO and its partners a 3,700 gross acre exploitation area for the development of the Ebouri field. The exploitation area 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 and three development wells were drilled and completed over the following two years. Currently one well in the Ebouri field is producing; the other two wells were shut-in for safety and marketability reasons in 2012 when the presence of H ₂ S was discovered. See “Hydrogen Sulfide Impact” below.

Southeast Etame field – The Southeast Etame 2-H well was brought on production in July 2015. It required re-drilling a segment of the well following a mechanical failure while drilling. The Southeast Etame 2-H well was drilled to develop an exploration discovery made in 2010. The well came on-line producing in excess of 3,000 gross BOPD.

North Tchibala field –The North Tchibala 1-H well, targeting the Dentale formation also required re-drilling a segment of the well due to wellbore collapse during drilling. It was brought on production in mid-September 2015 at an initial rate of approximately 3,000 gross BOPD and is currently producing at approximately 1,500 BOPD. Oil discoveries were made in the North Tchibala field in the Dentale formation prior to our acquisition of the Etame Marin block in 1995. The North Tchibala 2-H, our second well drilled to the Dentale formation, was brought on production in December 2015 at an initial rate of approximately 500 gross BOPD.

Hydrogen Sulfide Impact

Four of our wells are currently shut-in for safety and marketability reasons because H₂S was present in their production. In July 2012, we discovered the presence of H₂S from two of the three producing wells in the Ebouri field (the Ebouri 3-H and Ebouri 4-H wells), and these wells were shut-in. 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.  The Etame 8-H well was drilled in the fourth quarter of 2014 and testing in the first quarter of 2015 confirmed the presence of H₂S.  Both the Etame 5-H and 8-H wells remain shut-in. No well drilled after the Etame 8-H has produced H₂S.

To re-establish and maximize production from the impacted areas, additional capital investment will be required, including one or more processing facilities capable of removing H₂S, recompletion of the temporarily abandoned wells and potentially drilling additional wells. We evaluated fifteen alternatives which were ranked and high-graded. None of the alternatives were deemed economic at current forecasted oil prices, but we believe economic alternatives are available should oil prices recover sufficiently. In 2015, a total of $1.9 million related to project design and evaluation was charged to expense. As of December 31, 2015, we have no proved reserves booked for the wells impacted by H₂S, and their removal generated a 1,440 MBOE downward revision of our net proved reserves as compared to December 31, 2014.

Exploration

At December 31, 2015, we have no undeveloped leasehold costs related to Etame Marin block. The sixth extension period of the exploration acreage on this block expired at the end of July 2014, with us having fully met all of the obligations under its terms.  

Abandonment

As part of securing the first of two five-year extensions to the Etame field production license to which we were entitled from the government of Gabon, we 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 a period of ten years at 12.14% of the total abandonment estimate for the first seven years with the remaining unfunded estimated costs spread over the last three years of the production license.

We are required under the Etame production sharing contract to conduct abandonment studies to update the amounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. In January 2016, we completed a new abandonment study. Due to two new platforms and to the development wells drilled since the prior study, the amounts necessary to fund future abandonment obligations increased. This increased  the abandonment estimate used for funding purposes from $10.1 million net to

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VAALCO on an undiscounted basis to $17.2 million, and in turn the annual abandonment requirements net to VAALCO are expected to be $2.6 million in 2016, $2.1 million in 2017 and 2018, and $1.3 million per year for 2019 to 2021.

The abandonment estimate used for this purpose is approximately $61.1 million ($17.2 million net to VAALCO) on an undiscounted basis. Through December 31, 2015, $18.3 million ($5.1 million net to VAALCO) on an undiscounted basis has been funded. The amounts paid are reimbursable through the cost account and are non-refundable. The obligation for abandonment of the Gabon offshore facilities is included in the Asset retirement obligation shown on our consolidated balance sheet. This cash funding is reflected under other long term assets as Abandonment funding on our consolidated balance sheet. 

Impairment

In the fourth quarter of 2014, we recorded an impairment loss of $98.3 million to write down our investment in certain fields comprising the Etame Marin block to fair value as a result of the declines in the forecasted oil prices used in the impairment testing and calculation. We recorded impairments each quarter of 2015 totaling $81.3 million for 2015 to write down our investment in all fields comprising the Etame Marin block, as well as various U.S. fields, primarily as a result of lower forecasted oil prices as well as higher costs for planned development wells used in the impairment evaluation. See Note 5 to the consolidated financial statements for further discussion of impairments.

Onshore – Mutamba Iroru Block

In November 2005, we signed a PSC for the Mutamba Iroru block onshore Gabon. Under the five year contract we were awarded exploration rights to approximately 270,000 acres along the central coast of Gabon. We have a 50% operated working interest in the block (41% net working interest assuming Gabon exercises its back-in rights). After drilling two unsuccessful exploration wells on the block in 2009, we entered into a farmout agreement with Total Gabon to continue the exploration activities. Following seismic reprocessing, we drilled the N’Gongui No. 2 discovery well in 2012.

Since mid-2014, we have been working to finalize a revised or new PSC with the government of Gabon to allow for development of the discovery and to maintain exploration rights on the block. A term sheet, which specifies financial and other obligations to be included in a new PSC, was signed in the third quarter of 2014.

A letter received in September 2015 from the Gabon government expressed their view that the initial PSC has expired and encouraged us to expeditiously enter into a new PSC under the terms of the signed term sheet which, among other factors, honors the 2012 discovery and the accumulated cost account which is used in the calculation of Gabon production taxes. We and our joint venture partner do not agree with the government’s assertion that the initial PSC has expired.  

Meetings were held in October 2015 with the government regarding further amendments to the previously agreed terms of a new PSC, taking into account the substantial decrease in oil prices compared to the price environment when the term sheet was signed in the third quarter of 2014. We also met with the joint venture partner in October 2015 and continue to have discussions on the matter.

We can provide no assurance that we will enter into a new PSC. We 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. As discussed further in Note 5  to the consolidated financial statements, the September 30, 2015 evaluation of the economic viability of the N’Gongui No. 2 well resulted in a determination that the costs no longer met the necessary criteria for suspended well costs, and accordingly we included the costs in exploration expense in the third quarter of 2015.

Angola Segment

Offshore –Block 5 

In November 2006, we signed a production sharing contract for Block 5, offshore Angola. The four year primary term, with an optional three year extension, awarded us exploration rights to 1.4 million acres offshore central Angola. VAALCO’s working interest is 40%. Additionally, we are 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, we were required to acquire and process seismic data 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 delinquent 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, we received a written confirmation from The Ministry of Petroleum of Angola that the available 40% working interest in Block 5, offshore Angola, had 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. Sonangol EP and Sonangol P&P agree that the unpaid amounts from the defaulted partner plus the amounts incurred on the partner’s behalf during the period prior to assignment of the working interest to Sonangol P&P are the responsibility of Sonangol P&P. We invoiced Sonangol P&P for these amounts totaling $7.6 million plus interest in April 2014. Due to the uncertainty of collection, we recorded a full allowance totaling $7.6 million during 2011 through 2013 for the amount owed. Because this amount continued to be owed and due to slow payment history of the monthly cash call

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invoices since their assignment date of January 1, 2014, we placed Sonangol P&P in default in the first quarter of 2015. Sonangol E.P. acknowledged the legitimacy of the amounts owed and pledged to work to bring the Sonangol P&P account to a current status.

On March 14, 2016, we received $19.0 million from Sonangol P&P as payment for the full amounts owed as of December 31, 2015, which included: (i) $8.1 million of partner receivables reported at December 31, 2015 (representing 2015 activity), (ii) the $7.6 million of unpaid costs assumed by Sonangol P&P when they were assigned the participating interest in January 2014, and (iii) $3.2 million of interest as a result of being in default which we have not previously recognized in our financial results. As of December 31, 2015, we had $8.1 million reflected in Accounts with partners, net of an allowance of $7.6 million. As a result of this payment received subsequent to December 31, 2015, net income (loss) for the first quarter of 2016 will reflect the benefit for the reversal of the $7.6 million allowance and the recognition of the $3.2 million of default interest.

 

Although Sonangol P&P’s payment in March 2016 resolves the long outstanding amounts owed, there continues to be uncertainty about the future exploration of Block 5. To date, we have not been successful in farming-down part of our interest in Block 5 and our current liquidity is preventing us from pursuing the project without a partner. Due to the above circumstances regarding our intent and ability to pursue further exploration activities in Angola, we are recording a full impairment totaling $8.2 million of our undeveloped leasehold in the fourth quarter of 2015, the offset being a charge to Exploration expense, and writing off the $1.9 million in equipment inventory to Other operating loss, net.

In October 2014, we entered into the Subsequent Exploration Phase (“SEP”), together with our working interest partner, Sonangol P&P. 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. The SEP requires us and our partner to acquire 3D seismic and to drill two additional exploration wells. The seismic related commitment was completed in 2013. The two-well commitment under the primary exploration period carried over to the SEP period. In the first quarter of 2015, we drilled an unsuccessful exploratory well on the Kindele prospect, a post-salt objective, meeting one of the well commitments.

A $10.0 million dollar assessment ($5.0 million dollars net to VAALCO) applied to each of the three remaining commitment exploration wells for which drilling has not commenced before November 30, 2017. Due to the current outlook for oil prices and the uncertainties about the timing for our partner to pay its share of future costs, there may be delays in drilling the remaining three wells. We have continued to classify the $15.0 million commitment for drilling these wells as long term restricted cash on our balance sheet. We believe that it is not probable that we will incur any liability related to not meeting the commitment deadline to drill the three remaining wells as stated in the production sharing agreement with the Angolan government as the government has caused multiple delays in the Company obtaining a partner to participate in the future well commitments. We will seek to extend the term of the exploration license and hence the well commitment deadline in the coming months.

Equatorial Guinea Segment

Offshore – Block P

VAALCO has a 31% working interest in a portion of Block P, offshore Equatorial Guinea, which was acquired for $10.0 million in 2012 primarily for the exploration potential on the block. Prior to our acquisition in the block, two oil discoveries had been made on the block, establishing a development and production area in the block (the “PDA”). At the time the PDA was established, the block was divided into PDA and non-PDA portions, and we do not have a participating interest in the non-PDA portion of the block. The Ministry of Mines, Industry and Energy and GEPetrol, the current block operator, are currently reviewing a revised joint operating agreement which names us as operator.  Given the current depressed commodity price cycle, it is likely we will minimize any near-term expenditures and expenses in Equatorial Guinea. We and our partners are also working on timing and budgeting for development and exploration activities in the PDA, including the approval of a development and production plan. Development project economics are being re-evaluated considering the continued depressed oil prices and the expected decrease in development costs associated with the fall in oil prices. The production sharing contract covering the PDA provides for a development and production period of twenty-five years from the date of approval of a development and production plan. 

United States Segment

We acquired a 640 acre lease in the Hefley field (Granite Wash formation) in North Texas in December 2010, which is held by production from two wells drilled and brought on line in 2011 and 2012. During 2015,  the two wells produced approximately 3,000 Bbls of condensate and 181 MMcf net to VAALCO. Due to declines in oil and natural gas prices, we recorded an impairment charge of $3.2 million in the fourth quarter of 2015 related to the Hefley and other U.S. fields. No capital expenditures occurred in 2015, and no additional capital expenditures are anticipated in 2016 for this property.

In September 2011, we 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, we were required to drill three wells at our sole cost, all three of which were unsuccessful.  The related leases are held by production from other zones. Due to the sustained low oil prices, we determined that it is uneconomic for us to pursue exploration on these leases, and we charged the remaining unimpaired costs of $1.2 million to exploration expense in 2015. 

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DRILLING ACTIVITY

The table below reports the results of our drilling activity for each of the last three years. International encompasses the Gabon, Angola and Equatorial Guinea segments. With the exception of the Kindele exploratory dry hole drilled in Angola during 2015, all International activity was in Gabon.

 

(1)Includes the N’Gongui No. 2 discovery well which had been suspended since being drilled onshore Gabon in 2012 and was deemed to be unsuccessful in 2015.

(2)Includes the Etame 8-H well that was in progress at December 31, 2014, evaluated for H₂S  in 2015 and then shut-in when the presence of H₂S was confirmed.

 

ACREAGE AND PRODUCTIVE WELLS

Below is the total acreage under lease and the total number of productive oil and natural gas wells as of December 31, 2015:

 

RESERVE INFORMATION

Net Proved Reserves

In accordance with the current guidelines of the SEC, estimates of future net cash flow from our properties and the present value thereof are made using an unweighted, arithmetic average of the first-day-of-the-month price for each of the 12 months the year. Such prices 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. For 2015, such average prices used for our reserve estimates reflected consistently low prices during the year and were $49.36 per Bbl for crude oil from Gabon, $40.43 per Bbl of U.S. crude oil and condensate and $2.35 per Mcf for U.S. natural gas. This compares to much higher average prices for 2014 of $98.88 per Bbl, $86.49 per Bbl and $5.193 per Mcf, respectively.  Further declines in prices could result in the estimated quantities and present values of our reserves being reduced.

Reserves are reported by geographic area. International consists solely of net proved reserves related to the Etame Marin block located offshore Gabon in west Africa. We have no proved reserves related to our other international ventures. 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.  Natural gas volumes as of December 31, 2015 include natural gas liquid (“NGL”) barrels which were converted to Mmcf using the relative prices of the products.  NGLs represent less than 1.5% of our total proved reserves at December 31, 2015 on a barrel of oil equivalent basis. The table below sets forth our estimated net proved reserve quantities for the years ended December 31, 2015, 2014, and 2013 as prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers.

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Changes in Proved Reserves

The following table shows changes in total proved reserves for all presented years

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 at the end of the contract remain the property of the Gabon government.

We do not book proved reserves on discoveries until such time as a development plan has been prepared and approved by our 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 net negative revisions of previous estimates in 2015 were primarily a result of the loss of 3.5 years of production due to lower oil and natural gas prices (2,705  MBOE) and the removal of sour reserves (1,440 MBbl), partially offset by positive revisions due to the performance of wells drilled in the 2014-2015 drilling campaign exceeding expectations (370  MBbl). The oil price used to value reserves for 2015 was $49.36 per Bbl, which is almost 50% lower than the $98.88 per Bbl used for 2014 reserves. This price decrease

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accelerated the economic cutoff date for the Etame Marin block reserves from December 2021 as of the end of 2014 to May 2018 as of the end of 2015. Investigations into the cause of the crude souring indicate that the effect is not as widespread as previously projected and the volume of sour resources is less than earlier estimates. As discussed in “Hydrogen Sulfide Impact” above, crude sweetening options were studied extensively over the course of 2015; however, all of the options were uneconomic in the current commodity price environment.   

The net positive revisions of previous estimates 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).  The Ebouri field proved undeveloped reserves were revised downward (300 MBbls) due to higher costs of developing the reserves rendering them uneconomic. In 2014, the extensions and discoveries were associated with the booking of the Southeast Etame and North Tchibala reserves.

The net positive revisions of previous estimates in 2013 were primarily due to better reservoir performance at the Etame field (800 MBbls). Extensions and discoveries 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.  

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 our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural 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 judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. The standardized measure of discounted future net cash flows should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties.

Proved Undeveloped Reserves

We annually review all proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Continued declines in oil and natural gas prices in 2015 have caused our PUDs to become uneconomic to develop at the prices required by the SEC guidelines. Accordingly, we have no PUDs at December 31, 2015 compared with 5,036 MBbls of PUDs December 31, 2014. Reserves related to the successful wells drilled in 2015 were transferred to proved developed producing reserves during the year. The remaining PUD reserves were reclassified to unproved due to lower oil prices.

Controls over Reserve Estimates

Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and natural gas reserves quantities and present values in compliance with Securities Exchange Commission (“SEC”) regulations and generally accepted accounting principles in the U.S. (“GAAP”). Compliance with these rules and regulations with respect to our reserves is the responsibility of a reservoir engineer, who is our principal engineer. Our principal engineer has over 20 years of experience in the oil and natural 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 Audit Committee of the Board of Directors meets periodically with management to discuss matters and policies related to reserves.

Our controls over reserve estimation include retaining NSAI as our independent petroleum and geological firm for all years presented.  We provide information to NSAI about our oil and natural gas properties which includes, but is not limited to, production profiles, ownership and production sharing rights, prices,  costs and future drilling plans. NSAI prepares its 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, 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. The report of NSAI is filed as an exhibit to this Annual Report on Form 10-K. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. John R. Cliver and Mr. Mike K. Norton. 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. Norton, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years of prior industry experience. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology.  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.

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Net Volumes sold, Prices, and Production Costs

Net volumes sold,  average sales prices per unit, and production costs per unit for our 2015, 2014, and 2013 operations are shown in the tables below. 

 

 

 

 

AVAILABLE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document we file 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. Our SEC filings are also available to the public at the SEC’s website at www.sec.gov.

You may also obtain copies of our annual, quarterly and current reports, proxy statements and certain other information filed with the SEC, as well as amendments thereto, free of charge from our website at www.vaalco.com. No information from the either the SEC’s or our website is incorporated by reference herein. We have placed on our website copies of our 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

Prior to the second quarter in 2014, we sold oil from Gabon under contracts with Mercuria Trading NV (“Mercuria”) beginning with the calendar year 2011. Beginning in the second quarter of 2014 and through April 2015, we switched to an agency model by contracting with a third party, The Vitol Group, to sell our crude oil on the spot market for a fixed per barrel fee. Beginning in May 2015, we have sold our crude oil production from Gabon under a term contract with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. The contracted purchasers were TOTSA Total Oil Trading SA (“Total”) for May through July of 2015 and Glencore Energy UK Ltd. (“Glencore”) for August through December of 2015. The contract with Glencore U.K. ends in July 2016. Sales of  oil to Glencore U.K. and Total were 38% and 27% of total revenues for 2015, respectively, with less than 1% related to U.S. production.

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EMPLOYEES

As of December 31, 2015, we had 125 full-time employees, 80 of whom were located in Gabon and seven of whom were located in Angola. We are 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. We believe relations with employees are satisfactory.

COMPETITION

The oil and natural 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 natural 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 natural gas is affected by a number of factors beyond our control which may delay drilling, increase prices and have other adverse effects which cannot be accurately predicted.

Our competition for acquisitions, exploration, development and production includes the major oil and natural 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 us, giving those competitors an enhanced ability to evaluate and acquire desirable leases properties or prospects. Our ability to generate reserves in the future will depend on our ability to select and acquire suitable producing properties and/or developing prospects for future drilling and exploration.

INSURANCE 

We are not fully insured against all risks associated with our business either because such insurance is unavailable or because premium costs are considered uneconomic. A material loss not fully covered by insurance could have an adverse effect on our financial position, results of operations or cash flows. We maintain insurance at levels we believe to be customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of certain prohibited substances in to the environment. Such insurance might not cover the complete claim amount and would not cover fines or penalties for a violation of environmental law.

ENVIRONMENTAL REGULATIONS

General

Our activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control in Gabon, Angola and the U.S., and will be subject to the laws and regulations of Equatorial Guinea when exploration drilling occurs in those countries. Although no assurances can be made, we believe 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 our capital expenditures, earnings or competitive position with respect to its existing assets and operations. We cannot predict what effect future regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our 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 could have a material effect on us. Developing countries, in certain instances, have patterned environmental laws after those in the U.S., which are discussed below. However, the extent to which any environmental laws are enforced in developing countries varies significantly.

In the U.S., 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 natural gas exploration and production industry has been and continues to be 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 (and has solicited comments on continuing this initiative for fiscal years 2017-2019).  The trend has been the enactment of new or more stringent requirements on the oil and natural 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

We currently own or lease, and in the past we have owned or leased, properties that have been used for the exploration and production of oil and natural gas for many years. Although we have used 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 us or on or under

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locations where such wastes have been taken for disposal. In addition, some of these properties are or have been operated by third parties. We have 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 natural gas wastes and properties have gradually become stricter over time. We 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 contamination 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 a  Hazardous Substance, in the course of its operations, we have generated and will generate substances that may fall within CERCLA’s definition of a  Hazardous Substance and may have disposed of these substances at disposal sites owned and operated by others. We may also be the owner or operator of sites on which Hazardous Substances have been released. To its knowledge, neither VAALCO nor its predecessors have been designated as a PRP by the EPA under CERCLA; we also do 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 we are or has been an owner or operator or to which we sent regulated substances, we could be liable for costs of investigation and remediation and damages to natural resources.

Solid and Hazardous Waste Handling

We generate 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 comparable state statutes (“Hazardous Wastes”). Furthermore, although most oil and natural gas wastes generally are exempt from regulation as hazardous waste, not all current comparable state statutes may provide this exemption, and certain wastes generated may be subject to RCRA or comparable state statutes. It is possible that certain wastes generated by our oil and natural gas operations that are currently exempt may in the future be designated as Hazardous Wastes under RCRA or other applicable statutes and, therefore, may be subject to more rigorous and costly operating and 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 U.S., 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 us to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an unauthorized discharge of wastes, we may be liable for penalties as well as cleanup and response costs.

Oil Pollution Act

The Oil Pollution Act of 1990 (“OPA”), which amends and augments the 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 U.S. 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, we may be liable for costs and damages.

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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. We believe that currently we have established adequate proof of financial responsibility for our 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 natural 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 natural 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 in 2012 and released a draft of the study in 2015. This study and EPA’s enforcement initiative for the energy extraction sector could result in additional regulatory requirements that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

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 historic regulations were not written to address modern hydraulic fracturing activities.  The BLM has finalized revisions to its hydraulic fracturing regulations. Among other things, the BLM rules impose new requirements to validate the protection of groundwater, disclosure of chemicals used in hydraulic fracturing and higher standards for the interim storage of recovered waste fluids from hydraulic fracturing. This rule is the subject of legal challenges and a federal district court in Wyoming has issued a preliminary injunction temporarily delaying implementation of the BLM rules.

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. Further, in 2015, the EPA proposed wastewater pretreatment standards for discharges of wastewater pollutants from onshore unconventional oil and natural gas extraction facilities to publicly-owned treatment works.

If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where we conduct business, we could incur substantial compliance costs and such requirements could adversely delay or restrict our ability to conduct fracturing activities on our U.S. 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

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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 we were to have a portion of our leases designated as critical or suitable habitat, it may adversely impact the value of the affected leases.

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 U.S. 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, we could incur significant costs to control our 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. We 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 we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

In 2015, the EPA proposed new rules limiting methane emissions from the oil and natural gas industry. The proposed rules, if adopted, would amend the air emissions rules for oil and natural gas production sources and natural gas processing and transmission sources to include new standards for methane. In January 2016, BLM has proposed rules governing flaring and venting on public and tribal lands, which could require additional equipment and emissions controls as well as inspection requirements. Simultaneously with the proposal of the methane rules, the EPA released a proposal soliciting comments on two alternatives for aggregating multiple surface sites into a single-source of air quality permitting purposes. Depending upon the alternative selected by the EPA, sites which currently would not require permitting under the Clean Air Act could require permits, an outcome that could result in costs and delays to our operations; however, given the present uncertainty regarding this rule, the extent and magnitude of that impact cannot be reliably or accurately estimated.  

Air Emissions

Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. At the federal level, the 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 us to forego construction, modification or operation of certain air emission sources.

On April 17, 2012, the EPA issued final rules to subject oil and natural 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 provide “New Source Performance Standards” (“NSPS”) for completions of hydraulically fractured natural gas wells.    These standards are applicable to new hydraulically fractured wells and also to existing wells that are refractured.

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For each well completion operation with hydraulic fracturing begun prior to January 1, 2015, these standards require owners/operators to 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 natural 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 capture the natural gas and make it available for use or sale, which can be done through the use of green completions.

Further, these 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, which consists of two operated producing wells in North Texas. We have no plans at this time to pursue more U.S. properties.

OSHA and Other Regulations

To the extent not preempted by other applicable laws, we are 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 us to organize, maintain and/or disclose information about hazardous materials used or produced in our operations.

Item 1A. Risk Factors  

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.

Due to our substantial liquidity concerns, we may be unable to continue as a going concern.

Our annual revenues from oil and natural gas sales decreased from $127.7 million for 2014 to $80.4 million for 2015. Our total cash and cash equivalents at December 31, 2015 were $25.4 million, decreasing from $69.1 million as of December 31, 2014. As of December 31, 2015, we had a working capital deficit of $3.0 million. If oil and natural gas prices continue to remain at current depressed levels, we expect that for 2016 we will not generate adequate revenue to cover our operating expenses, we will generate losses from operations, and our cash flows will not be sufficient to cover our operating expenses. We currently require additional capital to execute our business plan and continue as a going concern. If we are unable to obtain capital funding, our business operations will be harmed, and we may not be able to continue as a going concern.

The operation of the terms of our existing revolving credit loan agreement may also adversely impact our liquidity. As of December 31, 2015 (and as of March 16, 2016), we had outstanding borrowings of $15.0 million under our revolving credit facility. In March 2016, we announced that the borrowing base under our revolving credit facility had been reduced to $20.1 million at December 31, 2015. The International Finance Corporation (“IFC”), our lender under the revolving credit facility, has communicated to us that if we were to seek additional drawdowns before the next scheduled redetermination date as of June 30, 2016, the IFC could elect, under the terms of the loan agreement, to conduct an interim redetermination which it believes would result in a borrowing base of less than $20.1 million if commodity prices are lower than they were at December 31, 2015. Therefore, we currently have very limited, if any, borrowing capacity under our revolving credit facility. A continuation of prevailing low price levels for oil and natural gas may cause the IFC to make further reductions in the borrowing base under the credit facility.

If we fail to satisfy our obligations with respect to our indebtedness or trade payables, or fail to comply with the financial and other restrictive covenants contained in the loan agreement governing our revolving credit facility, an event of default could result, which would permit acceleration of such debt and which could result in an event of default under the facility and acceleration of other indebtedness, and could permit our secured lender to foreclose on any of our assets securing that debt. Any accelerated debt would become immediately due and payable.

Our current financial condition and the short-term outlook for our business operations raise substantial doubt about our ability to continue as a going concern.

Our financial statements have been prepared assuming that we will continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

Our ability to borrow funds and to obtain additional capital on reasonable terms is substantially dependent on oil and natural gas prices. The prices of oil and natural gas declined dramatically in the second half of 2014 and remained low, decreasing further in 2015. Average prices for our crude oil sales have fallen from $103.23 per barrel in June 2014 to $33.56 per barrel in December 2015. As a result, our revenues decreased from $127.7 million for the year ended December 31, 2014 to $80.4 million for the year ended December 31, 2015.

Continued depressed oil and natural gas prices or further declines in oil and natural gas prices for 2016 and thereafter would have a material adverse effect on our liquidity, financial condition, results of operations and on the carrying value of our proved reserves.

We currently require additional capital to execute our business plan and continue as a going concern. If we are unable to obtain funding, our business operations will be harmed, and we may not be able to continue as a going concern.

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We will require additional capital to continue to operate our business, expand our exploration and development programs, and continue as a going concern. Any future acquisitions and future exploration, development, production, leasing activities and marketing activities, as well as our administrative requirements, will require a substantial amount of additional capital and cash flow. We may pursue additional capital through various financial transactions or arrangements, and are considering multiple alternatives, including, but not limited to, additional debt or equity financing, a sale or farm-downs of assets, joint ventures, rescheduling discretionary portions of our capital spending to future periods or operating cost reductions. There can be no guarantee of future capital acquisition or fundraising success. Additionally, our current financial position, our current lack of cash resources and our potential inability to continue as a going concern could materially adversely affect our common share prices and our ability to obtain additional financing or new capital from sales of our capital stock.

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 reasonable 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 declined dramatically in the second half of 2014 and decreased further in 2015. During 2014, based on New York Mercantile Exchange (“NYMEX”) pricing, the spot price per Bbl of West Texas Intermediate crude oil ranged from a high of $107.26 to a low of $53.45, and the Henry Hub spot price per Mcf of natural gas ranged from a high of $6.00 to a low of $3.48. During 2015, the spot price per Bbl of West Texas Intermediate crude oil ranged from a high of $61.36 to a low of $34.55,  and the Henry Hub spot price per Mcf of natural gas ranged from a high of $2.99 to a low of $1.93.

As a result of the substantial decline in oil and natural gas prices, our revenues, operating income, cash flows and borrowing capacity have been materially and adversely affected and have required reductions in the carrying value of our oil and natural gas properties and our planned level of capital expenditures. The average price at which we sold oil in 2015 was $47.85 per Bbl compared to $93.66 per Bbl in 2014, and $108.35 per Bbl in 2013. Because the oil price we are required to use by the 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 oil and natural gas 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 U.S. shale production,  international political conditions, including uprisings and political unrest in the Middle East and Africa, 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.

Further reductions in our borrowing base under our revolving credit facility as a result of 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.

As of December 31, 2015 (and at March 16, 2016), we had outstanding borrowings of $15.0 million under our revolving credit facility. Availability under our revolving credit facility is subject to a borrowing base which is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on the value of our oil and natural gas reserves as determined by the IFC, the lender under the credit facility, and other factors deemed relevant by it. We announced in March 2016 that our borrowing base had been redetermined by the IFC and reduced from $65.0 million to $20.1 million effective December 31, 2015. This reduction was primarily a result of the lower anticipated oil and natural gas prices used to determine our commitment amount. Continued low or declining prices for oil and natural gas may cause the IFC to reduce further the borrowing base under our revolving credit facility.

The IFC has also communicated to us that if we were to seek additional drawdowns under the credit facility before the next scheduled borrowing base redetermination date (as of June 30, 2016), it could elect, under the terms of the loan agreement, to conduct an interim redetermination which it believes would result in a borrowing base of less than $20.1 million, if prevailing commodity prices are lower than they were at December 31, 2015.

Any further reductions in our borrowing base as a result of borrowing base redeterminations, or otherwise, would likely negatively impact our liquidity and our ability to fund our operations and, as a result, would likely 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 results of operations.

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For additional information regarding our revolving credit facility and our long-term indebtedness, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Capital Resources and Liquidity” and Note 7 to the consolidated financial statements.

Our revolving credit facility loan agreement imposes significant restrictions on our current and future operations. If we default under the loan agreement, the lender may act to accelerate our indebtedness, which would impact our ability to conduct our business and results of operations.

Our credit agreement contains a number of restrictive covenants that impose significant operating and financial restrictions on us, which may limit our ability to engage in acts that may be in our best interests. These covenants including restrictions on our ability to:

In addition, the loan agreement includes certain financial ratios, including;

As of December 31, 2015, we were in compliance with all of our financial covenants under our revolving credit facility. However, we can make no assurance that we will be able to continue to comply with these financial covenants in the future. Failure to maintain these covenants or otherwise negotiate amendments to the credit facility could preclude us from borrowing under our credit facility and require us to immediately pay down any outstanding drawn amounts under the credit facility.

These covenants have the effect of restricting our ability to engage in certain actions, including potentially limiting our ability to sell assets, make future borrowings under the revolving credit facility or incur other additional indebtedness. Our ability to meet our net debt to EBITDAX ratio and our different coverage ratio requirements can be affected by events beyond our control, including changes in commodity prices. There can be no assurance that we will be able to comply with these covenants in future periods. In addition, if we receive any additional waivers or amendments to our revolving credit facility loan agreement, the lender may impose additional operating and financial restrictions on us.

A breach of the covenants under our revolving credit facility loan agreement could result in an event of default under the agreement. Such a default may allow the lender to accelerate payment of the indebtedness under the facility. Furthermore, if we were unable to repay the amounts due and payable under the credit facility, the lender could proceed against the collateral granted to it to secure that indebtedness.

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 Marin block consists of five fields with 12 producing wells. Production from these fields constituted approximately 98% of our total production for the year ended December 31, 2015. In addition, at December 31, 2015, 93% of our total net proved reserves were

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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.

Increases in oil supplies from U.S. 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 U.S. 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. In addition, the U.S. federal government has recently ended its decades-old prohibition of exports of crude oil produced in the lower 48 states of the U.S. It is too recent an event to determine the impact this regulatory change may have on our operations or our sales of crude oil. 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.  

If oil and natural gas prices remain depressed for extended periods of time, we may be required to take further 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. In the fourth quarter of 2014, we recorded an impairment loss of $98.3 million to write down our investment in certain fields comprising the Etame Marin block to fair value as a result of the declines in the forecasted oil prices used in the impairment testing and calculation. As a result of further declines in prices and increased development well costs, during 2015, we recorded additional impairments totaling $81.3 million related to the Etame Marin block and to various fields in the U.S. Sustained lower prices will cause the estimated quantities and present values of our reserves to be reduced, which may necessitate further write-downs.

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 material changes in oil or natural gas prices, 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, 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.

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

To replace and grow reserves, we must 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 2015, we participated in 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 budget and 50% of the offshore Angola 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. In Angola, our partner, Sonangol P&P failed to pay its cash calls timely, and was in default from the first quarter of 2015 through March 2016.

However, if continuing depressed 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 revolving 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.  

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

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 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 U.S.

Private ownership of oil and natural gas reserves under oil and natural gas leases in the U.S. differs distinctly from our rights in foreign reserves where the state generally retains ownership of the minerals, and in many cases participates in, the exploration and production of hydrocarbon reserves. Accordingly, operations outside the U.S. may be materially affected by host governments through royalty payments, export taxes and regulations, surcharges, value added taxes, production bonuses and other charges. Gabon has indicated an interest in taking their oil in kind rather than us continuing to marketing on their behalf, which could cause fluctuations in the timing of and realized prices for oil sales.

Almost all of our proved reserves are related to the Etame Marin block located offshore Gabon. 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.

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.

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 U.S. 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.

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

We currently sell our crude oil production from Gabon under a term contract with Glencore at pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors, that ends in July 2016.

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 may 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.

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, natural 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

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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 climate 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 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.

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, 2015, 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 our 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 2015 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 U.S. As a result, proved reserves in foreign jurisdictions may not be comparable to proved reserve estimates in the U.S.

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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 costs in Gabon and Angola are denominated in the local currency. A weakening U.S. dollar will have the effect of increasing 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.

Fluctuations in currency exchange rates may negatively impact our earnings, which are subject to financial covenants under our revolving 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. As of December 31, 2015, we were in compliance with all financial covenants under our credit facility.

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 any future acquisitions.

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 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 employer 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 U.S., Gabon, Angola and Equatorial Guinea regulate our current business. These laws and regulations may require that we obtain permits for our development, limit or prohibit drilling activities in certain protected or sensitive areas, or restrict the substances that can be released in connection with our operations. 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

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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. 

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 and capitalize the related costs as part of the carrying amount of the long-lived assets. The estimated liability is reflected as Asset retirement obligation in the balance sheets.

As part of the Etame field production license, we are subject to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. On an annual basis over the remaining life of the production license, we fund a portion of these estimated abandonment costs.  The amount of cash funded through the end of a period is reflected separately from the asset retirement obligation under other long term assets as Abandonment funding and is non-refundable to us. See “Item 1. Business – Segment and Geographic Information –Gabon Segment—Etame Marin Block—Abandonment” for further information. If estimated abandonment costs were to increase in the future, we may be required to increase our funding of such costs. 

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. 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 may 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. 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 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 our 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

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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 regarding the capital that a swap dealer or major swap participant is required to post with respect to its swap business, but the CTFC has not yet issued a final rule. The CFTC issued a final rule on Margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption for 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 capital 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 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 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 U.S. 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.

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 Gabon. In November 2014, we responded to the Gabon Taxation Department requesting joint meetings to advance the resolution of this matter and later provided a formal reply to the provisional audit report in February 2015. A tentative agreement was reached with the Gabon Taxation Department in April 2015, and we are working with the Gabon Taxation Department to finalize the audit. During 2015, we accrued an estimated settlement of $0.3 million based upon preliminary negotiations. 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. 

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

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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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and general character of our principal oil and natural gas assets, production facilities, and other important physical properties have been described by segment under Item 1. Business. Information about oil and natural gas reserves, including the basis for their estimation, is discussed in “Item 1. Business.”

Item 3. Legal Proceedings

The Chancery Court of the State of Delaware held that our charter and bylaw provisions that allowed for director removal “for cause only” are invalid as a matter of Delaware law. The proceeding is still pending as to the plaintiffs’ request to recover their attorneys’ fees and costs.

On December 7, 2015, Plaintiff Vladimir Gusinsky Living Trust filed a stockholder class action lawsuit in the Court of Chancery of the State of Delaware (the “Court”) against the Company and all of its directors alleging that certain provisions of the Company’s Restated Charter and Second Amended and Restated Bylaws that restricted the removal of its directors to removal for cause only (the “director removal provisions”) were invalid as a matter of Delaware law. Plaintiff George Shapiro also filed a similar stockholder class action lawsuit in the Court on December 7, 2015. Thereafter, the plaintiffs agreed to the consolidation of their cases (the “Consolidated Case”).

After a hearing on the Consolidated Case on December 21, 2015, Vice Chancellor Laster issued an opinion in In re VAALCO Energy, Inc. Stockholder Litigation, Consol. C.A. No. 11775-VCL holding that, in the absence of a classified board or cumulative voting, the director removal provisions conflicted with Section 141(k) of the Delaware General Corporation Law and are therefore invalid. No appeal to the ruling has been made and the Company has no plans for such action.

Lastly, while the central issue stated in the preceding paragraph in regard to the Consolidated Case has been resolved, the plaintiffs still maintain a pending request in the Court to recover their attorneys’ fees and costs associated with the Consolidated Case.

 Item 4. Mine Safety Disclosures

Not applicable. 

PART II

 Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities  

GENERAL

Our common stock is traded on the New York Exchange under the symbol EGY. The following table sets forth the range of high and low sales prices of the common stock for the periods indicated.

 

 

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On February 29, 2016, the last reported sale price of the common stock on the New York Stock Exchange was $1.06 per share.

As of February 29, 2016, based upon information received from our transfer agent and brokers and nominees, there were approximately 59 holders of record of VAALCO common stock. This number does not include owners for whom common stock may be held in “street” names.

Dividends

We have not paid cash dividends and do not anticipate paying cash dividends on the common stock in the foreseeable future.  

Performance Graph

The following graph compares the yearly percentage change in our cumulative total stockholder return on common shares with the cumulative total return of the S&P 500 Index and the SPDR S&P Oil & Gas Exploration and Production Index. For this purpose, the yearly percentage change in our cumulative total stockholder return is calculated by dividing (a) the sum of the dividends paid during the “measurement period,” and the difference between the price for our shares at the end and the beginning of the measurement period, by (b) the price for our common shares at the beginning of the measurement period. “Measurement period” means the period beginning at the market close on the last trading day before the beginning of our fifth preceding fiscal year, through and including the end of our most recently completed fiscal year. We were first listed on the New York Stock Exchange on October 12, 2006.

 

 

 

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Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information as of December 31, 2015 regarding the number of shares of common stock that may be issued under our compensation plans. Please refer to Note 10 to the consolidated financial statements for additional information on stock based compensation.

 

Issuer Purchases of Equity Securities for Year Ended December 31, 2015

During 2015, we acquired 120,455 shares in cashless stock option exercises and to satisfy tax withholding obligations related to stock option exercises.   

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Item 6. Selected Financial Data

The following table sets forth, as of the dates and for the periods indicated, selected financial information. The financial information for each of the five years ended December 31, 2015, 2014, 2013, 2012 and 2011 has been derived from the Consolidated Financial Statements filed in the Annual Report on Form 10-K for each year. The information should be read in conjunction with “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of future results.